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January 2011

U.S. Energy Information Administration

Assistant Administrator for Energy Statistics

Office of Electricity, Renewables, and Uranium Statistics

U.S. Department of Energy

Washington DC 20585

This report was prepared by the U.S. Energy Information Administration (EIA), the statistical and analytical agency within the U.S. 

Department of Energy. By law, EIA’s data, analyses, and forecasts are independent of approval by any other officer or employee of 

the United States Government. The views in this report therefore should not be construed as representing those of the Department 

of Energy or other Federal agencies.

This report is only available on the Web at:

http://www.eia.gov/cneaf/electricity/epa/epa_sum.html
ii U.S. Energy Information Administration/Electric Power Annual 2009

Contacts 

Questions concerning the Electric Power Annual can be directed to the National Energy Information 

Center at 202-586-8800 or InfoCtr@eia.gov.

Year-in-Review

William Booth (202/586-5611) 

email: william.booth@eia.gov

Marie Rinkoski Spangler (202/586-2446)

email: marie.rinkoski-spangler@eia.gov

Kevin G. Lillis (202/586-3704)

email: kevin.lillis@eia.gov

Capacity

Vlad Dorjets (202/586-3141)

email: vlad.dorjets@eia.gov

Patricia Hutchins (202/586-1029)

email: patricia.hutchins@eia.gov

Generation

Channele Wirman (202/586-5356)

email: channele.wirman@eia.gov

Chris Cassar (202/586-5448)

email: christopher.cassar@eia.gov

Ron S. Hankey (202/586-2630)

email: ronald.hankey@eia.gov

Demand, Capacity Resources, and Capacity Margins

Orhan M. Yildiz (202/586-5410)

email: orhan.yildiz@eia.gov

Marie Rinkoski Spangler (202/586-2446)

email: marie.rinkoski-spangler@eia.gov

Fuel

Channele Wirman (202/586-5356)

email: channele.wirman@eia.gov

Rebecca Peterson (202/586-4509)

email: rebecca.peterson@eia.gov

Chris Cassar (202/586-5448)

email: christopher.cassar@eia.gov

Ron S. Hankey (202/586-2630)

email: ronald.hankey@eia.gov

Emissions

Kevin G. Lillis (202/586-3704)

email: kevin.lillis@eia.gov

Trade

Michelle Bowles (202/586-2430)

email: michelle.bowles@eia.gov

Retail Customers, Sales, and Revenue

Stephen Scott (202/586-5140) 

email: stephen.scott@eia.gov

Karen McDaniel (202/586-4280) 

email: karen.mcdaniel@eia.gov

Revenue and Expense Statistics

Stephen Scott (202/586-5140) 

email: stephen.scott@eia.gov

Karen McDaniel (202/586-4280) 

email: karen.mcdaniel@eia.gov

Kevin G. Lillis (202/586-3704)

email: kevin.lillis@eia.gov

Demand-Side Management

Stephen Scott (202/586-5140) 

email: stephen.scott@eia.gov

Karen McDaniel (202/586-4280) 

email: karen.mcdaniel@eia.gov

Quality

The U.S. Energy Information Administration is committed to quality products and service. To ensure that this report meets the 

highest standards for quality, please forward your comments or suggestions about this publication to Orhan M. Yildiz at 

202/586-5410, or email: orhan.yildiz@eia.gov.

For general inquiries about energy data, please contact the National Energy Information Center at 202/586-8800. Internet 

users may contact the center at: infoctr@eia.gov.
U.S. Energy Information Administration/Electric Power Annual 2009 iii

Revision Notice

January 4, 2011 Revision:

A revision to the energy source codes for three generators in Montana (changed from 

geothermal to waste heat) has resulted in changes to the Electric Power Annual 2009.

Details of this revision can be found by using the highlighted link provided below. 

http://www.eia.gov/cneaf/electricity/epa/epa_noticerev.html

Please note that this link is also provided on the Electric Power Annual web page among 

publication related dates as:

Report Revised: January 4, 2011
iv U.S. Energy Information Administration/Electric Power Annual 2009

Preface

The Electric Power Annual 2009 summarizes 

electric power industry statistics at the national 

level. The publication provides industry 

decision-makers, government policymakers, 

analysts, and the general public with historical 

data that may be used in understanding U.S. 

electricity markets. The Electric Power

Annual is prepared by the Office of 

Electricity, Renewables, and Uranium 

Statistics; under the Assistant Administrator 

for Energy Statistics; U.S. Energy 

Information Administration; U.S. Department 

of Energy. 

Data in this report can be used in analytic studies 

for public policy and business decisions. The 

chapters present information and data in the 

following areas: electricity generation; electric 

generating capacity; demand, capacity resources, 

and capacity margins; fuel, consumption and 

receipts; emissions; electricity trade; retail 

electric customers, sales, revenue and average 

retail price; electric utility revenue and expense 

statistics; and demand-side management. 

Monetary values in this publication are 

expressed in nominal terms. 

Data published in the Electric Power Annual are 

compiled from four surveys completed annually 

or monthly by electric utilities and other electric 

power producers and submitted to the EIA and 

five surveys administered by other government 

organizations1

. The EIA forms are described in 

detail in the "Technical Notes."

1The Department of Energy, Office of Electricity Delivery and Energy 

Reliability; the Federal Energy Regulatory Commission; the Department 

of Agriculture, Rural Utility Service; and the National Energy Board of 

Canada.
U.S. Energy Information Administration/Electric Power Annual 2009 v

Contents 

Electric Power Industry 2009:............................................................................................................................................................... 1

Year in Review ..................................................................................................................................................................................... 1

Chapter 1. Capacity............................................................................................................................................................................13

Chapter 2. Generation and Useful Thermal Output ...........................................................................................................................25

Chapter 3. Fuel and Emissions...........................................................................................................................................................30

Chapter 4. Demand, Capacity Resources, and Capacity Margins......................................................................................................39

Chapter 5. Characteristics of the Electric Power Industry .................................................................................................................46

Chapter 6. Trade ................................................................................................................................................................................52

Chapter 7. Retail Customers, Sales, and Revenue .............................................................................................................................54

Chapter 8. Revenue and Expense Statistics .......................................................................................................................................67

Chapter 9. Demand-Side Management ..............................................................................................................................................71

Appendices 

A. Technical Notes ...............................................................................................................................................................77

Glossary .......................................................................................................................................................................................100
vi U.S. Energy Information Administration/Electric Power Annual 2009

Tables

Pages 

Table ES1. Summary Statistics for the United States, 1998 through 2009 ...................................................................................... 9

Table ES2. Supply and Disposition of Electricity, 1998 through 2009 ......................................................................................... 12

Chapter 1. Capacity.............................................................................................................................................................................. 13

Table 1.1. Existing Net Summer Capacity by Energy Source and Producer Type, 1998 through 2009 ...................................... 14

Table 1.1.A. Existing Net Summer Capacity of Other Renewables by Producer Type, 1998 through 2009 ................................... 16

Table 1.2. Existing Capacity by Energy Source, 2009................................................................................................................. 17

Table 1.3. Existing Capacity by Producer Type, 2009................................................................................................................. 17

Table 1.4. Planned Generating Capacity Additions from New Generators, by Energy Source, 2010-2014 ................................ 18

Table 1.5. Capacity Additions, Retirements and Changes by Energy Source, 2009.................................................................... 19

Table 1.6.A. Capacity of Dispersed Generators by Technology Type, 2004 through 2009............................................................. 20

Table 1.6.B. Capacity of Distributed Generators by Technology Type, 2004 through 2009........................................................... 20

Table 1.6.C. Total Capacity of Dispersed and Distributed Generators by Technology Type, 2004 through 2009......................... 20

Table 1.7. Fuel Switching Capacity of Operable Generators Reporting Natural Gas as the Primary Fuel, by Producer Type, 

2009............................................................................................................................................................................. 21

Table 1.8. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum Liquids by Type of Prime 

Mover, 2009 ................................................................................................................................................................ 21

Table 1.9. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum Liquids by Type of Prime 

Mover, 2009 ................................................................................................................................................................ 22

Table 1.10. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum Liquids, by Year of Initial 

Commercial Operation, 2009 ...................................................................................................................................... 22

Table 1.11. Interconnection Cost and Capacity for New Generators, by Producer Type, 2008 and 2009 ..................................... 23

Table 1.12. Interconnection Cost and Capacity for New Generators, by Grid Voltage Class, 2008 and 2009 .............................. 24

Chapter 2. Generation and Useful Thermal Output.......................................................................................................................... 25

Table 2.1. Net Generation by Energy Source by Type of Producer, 1998 through 2009............................................................. 26

Table 2.1.A. Net Generation by Selected Renewables by Type of Producer, 1998 through 2009................................................... 28

Table 2.2. Useful Thermal Output by Energy Source by Combined Heat and Power Producers, 1998 through 2009 ................ 29

Chapter 3. Fuel and Emissions ............................................................................................................................................................ 30

Table 3.1. Consumption of Fossil Fuels for Electricity Generation by Type of Power Producer, 1998 through 2009 ................ 31

Table 3.2. Consumption of Fossil Fuels for Useful Thermal Output by Type of Combined Heat and Power Producers, 1998 

through 2009 ............................................................................................................................................................... 32

Table 3.3. Consumption of Fossil Fuels for Electricity Generation and for Useful Thermal Output, 1998 through 2009........... 33

Table 3.4. End-of-Year Stocks of Coal and Petroleum by Type of Producer, 1998 through 2009 .............................................. 34

Table 3.5. Receipts, Average Cost, and Quality of Fossil Fuels for the Electric Power Industry, 1998 through 2009 ................ 35

Table 3.6. Receipts and Quality of Coal Delivered for the Electric Power Industry, 1998 through 2009.................................... 35

Table 3.7. Average Quality of Fossil Fuel Receipts for the Electric Power Industry, 1998 through 2009 .................................. 36

Table 3.8. Weighted Average Cost of Fossil Fuels for the Electric Power Industry, 1998 through 2009.................................... 37

Table 3.9. Emissions from Energy Consumption at Conventional Power Plants and Combined-Heat-and-Power Plants, 1998 

through 2009 ............................................................................................................................................................... 38

Table 3.10. Number and Capacity of Existing Fossil-Fuel Steam-Electric Generators with Environmental Equipment, 1998 

through 2009 ............................................................................................................................................................... 38

Table 3.11. Average Costs of Existing Flue Gas Desulfurization Units, 1998 through 2009 ........................................................ 38

Chapter 4. Demand, Capacity Resources, and Capacity Margins.................................................................................................... 39

Table 4.1. Noncoincident Peak Load, Actual and Projected by North American Electric Reliability Corporation Region, 

2005 through 2014 ...................................................................................................................................................... 40

Table 4.2. Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability 

Corporation Region, Summer, 1998 through 2009 ..................................................................................................... 41

Table 4.3. Net Internal Demand, Actual or Planned Capacity Resources, and Capacity Margins by North American Electric 

Reliability Corporation Region, Summer, 2009 through 2014.................................................................................... 42

Table 4.4. Net Internal Demand, Actual or Planned Capacity Resources, and Capacity Margins by North American Electric 

Reliability Corporation Region, Winter, 2009 through 2014 ...................................................................................... 43

Chapter 5. Characteristics of the Electric Power Industry ............................................................................................................... 46

Table 5.1. Count of Electric Power Industry Power Plants, by Sector, by Predominant Energy Sources within Plant, 2001 

through 2009 ............................................................................................................................................................... 47

Table 5.2. Average Capacity Factors by Energy Source, 1998 through 2009.............................................................................. 48
U.S. Energy Information Administration/Electric Power Annual 2009 vii

Table 5.3. Average Operating Heat Rate for Selected Energy Sources, 2001 through 2009 ....................................................... 49

Table 5.4. Average Heat Rates by Prime Mover and Energy Source, 2009................................................................................. 50

Table 5.5. Planned Transmission Capacity Additions, by High-Voltage Size, 2010 through 2016............................................. 51

Chapter 6. Trade................................................................................................................................................................................... 52

Table 6.1. Electric Power Industry - Electricity Purchases, 1998 through 2009 .......................................................................... 53

Table 6.2. Electric Power Industry - Electricity Sales for Resale, 1998 through 2009 ................................................................ 53

Table 6.3. Electric Power Industry - U.S. Electricity Imports from and Electricity Exports to Canada and Mexico, 1998 

through 2009 ............................................................................................................................................................... 53

Chapter 7. Retail Customers, Sales, and Revenue ............................................................................................................................. 54

Table 7.1. Number of Ultimate Customers Served by Sector, by Provider, 1998 through 2009.................................................. 55

Table 7.2. Retail Sales and Direct Use of Electricity to Ultimate Customers by Sector, by Provider, 1998 through 2009 ......... 57

Table 7.3. Revenue from Retail Sales of Electricity to Ultimate Customers by Sector, by Provider, 1998 through 2009........... 59

Table 7.4. Average Retail Price of Electricity to Ultimate Customers by End-Use Sector, 1998 through 2009.......................... 61

Table 7.5. Net Metering and Green Pricing Customers by End Use Sector, 2002 - 2009............................................................ 66

Chapter 8. Revenue and Expense Statistics........................................................................................................................................ 67

Table 8.1. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities, 1998 through 2009.................... 68

Table 8.2. Average Power Plant Operating Expenses for Major U.S. Investor-Owned Electric Utilities, 1998 through 2009.... 68

Table 8.3. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (With Generation Facilities), 

1998 through 2009 ...................................................................................................................................................... 69

Table 8.4. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (Without Generation Facilities), 

1998 through 2009 ...................................................................................................................................................... 69

Table 8.5. Revenue and Expense Statistics for U.S. Federally Owned Electric Utilities, 1998 through 2009............................. 70

Table 8.6. Revenue and Expense Statistics for U.S. Cooperative Borrower Owned Electric Utilities, 1998 through 2009 ........ 70

Chapter 9. Demand-Side Management ............................................................................................................................................... 71

Table 9.1. Demand-Side Management Actual Peak Load Reductions by Program Category, 1998 through 2009...................... 72

Table 9.2. Demand-Side Management Program Annual Effects by Program Category, 1998 through 2009 .............................. 72

Table 9.3. Demand-Side Management Program Incremental Effects by Program Category, 1998 through 2009....................... 72

Table 9.4. Demand-Side Management Program Annual Effects by Sector, 1998 through 2009 ................................................. 73

Table 9.5. Demand-Side Management Program Incremental Effects by Sector, 1998 through 2009 .......................................... 74

Table 9.6. Demand-Side Management Program Energy Savings, 1998 through 2009 ................................................................ 75

Table 9.7. Demand-Side Management Program Direct and Indirect Costs, 1998 through 2009 ................................................. 75

Appendices ..................................................................................................................................................................................... 76

Table A1. Sulfur Dioxide Uncontrolled Emission Factors........................................................................................................... 95

Table A2. Nitrogen Oxides Uncontrolled Emission Factors........................................................................................................ 96

Table A3. Carbon Dioxide Uncontrolled Emission Factors......................................................................................................... 97

Table A4. Nitrogen Oxides Control Technology Emissions Reduction Factors......................................................................... 98

Table A5. Unit-of-Measure Equivalents ...................................................................................................................................... 98
viii U.S. Energy Information Administration/Electric Power Annual 2009

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Figure ES 1. U.S. Electric Power Industry Net Generation, 2009................................................................................................. 2

Figure ES2. U.S. Electric Power IndustrySummer Capacity, 2009............................................................................................ 4

Figure ES3. Planned Summer Capacity Additions, 2010-2014.................................................................................................... 5

Figure ES4. Annual Change in Retail Sales to Bundled and Unbundled Customers, 2008 to 2009 (Percent Change)................ 6

Figure ES5. Fossil Fuel Costs for Electricity Generation, 1998-2009................................................................................... 7

Figure 1.1. U.S. Electric Industry Generating Capacity by State, 2009....................................................................................15

Figure 2.1. U.S. Electric Industry Net Generation by State, 2009............................................................................................27

Figure 4.1 Historical North American Electric Reliability Council Regions for the Contiguous U.S., 2005..........................44

Figure 4.2 Consolidated North American Electric Reliability Corporation Regional Entities, 2009 ......................................45

Figure 7.1. U.S. Electric Industry Total Ultimate Customers by State, 2009 ...........................................................................56

Figure 7.2. U.S. Electric Industry Total Retail Sales by State, 2009 ........................................................................................58

Figure 7.3. U.S. Electric Industry Total Revenues by State, 2009 ...........................................................................................60

Figure 7.4. Average Retail Price of Electricity by State, 2009................................................................................................. 62

Figure 7.5. Average Residential Price of Electricity by State, 2009.........................................................................................63

Figure 7.6. Average Commercial Price of Electricity by State, 2009.......................................................................................64

Figure 7.7. Average Industrial Price of Electricity by State, 2009 ...........................................................................................65
U.S. Energy Information Administration/Electric Power Annual 2009 1

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Generation. Electricity markets in 2009 were 

keenly affected by economic and environmental 

developments. Electricity generation was down 

4.1 percent, reaching its lowest level since 2003; 

this was the largest decline in 6 decades 1 and 

follows a 0.9-percent decline in 2008. The drop 

in power demand reflects a 2.6-percent decline in 

economic activity (GDP) during 2009.2

 

Summer temperatures during 2009 were 

relatively mild, resulting in a 1.1 percent decline 

in residential electricity sales between 2008 and 

2009.

A 9.1-percent decline in industrial demand for 

electricity, which fell to the lowest level since 

1987, accounted for most of the decline in 

overall electricity consumption. The drop in 

industrial electricity demand reflected the 9.3-

percent drop in industrial output, as measured by 

the Federal Reserve Bank’s index of industrial 

production.3

 

Emissions. Environmental developments played 

an important role in electricity markets in 2009.

The policy debate over greenhouse gas 

legislation continued throughout 2009. 

Electric power plant investment and 

operation decisions made during 2009 may 

have been affected by expectations that 

some form of future cap on carbon dioxide 

(CO2) loomed on the horizon. 

CO2, nitrogen oxides (NOx,) and sulfur 

dioxide (SO2) emissions posted the largest 

declines on record.4 Total CO2 emissions 

were 8.6-percent lower in 2009. Emissions 

from coal-fired plants fell 11.0 percent, 

largely attributable to a 10.3-percent decline 

in coal consumption. 

1 The U.S. Energy Information Administration’s historic electricity 

generation data goes back to 1949.

2 U.S. Department of Commerce Bureau of Economic Analysis, News 

Release: Gross Domestic Product: Second Quarter 2010 (Third 

Estimate), Table 1. 3 U.S. Federal Reserve Bank, Industrial Production and Capacity 

Utilization, (Table 11). 4

The U.S. Energy Information Administration has been estimating 

CO2, NOX, and SO2 emissions since 1989.

NOx and SO2 emissions from electric power 

plants declined 28.1 and 23.8 percent, 

respectively (Table 3.9) in 2009. For coalfired generation, the declines in NOx and 

SO2 emissions were even greater, at 34.0

percent and 24.7 percent, respectively. 

Fuel costs. The price of natural gas delivered to 

electric power plants fell in 2009 to roughly half 

the 2008 level. In 2009, annual average natural 

gas wellhead prices reached their lowest level 

in 7 years. Increased supply due to the 

availability of shale gas, coupled with mild 

winter temperatures and higher production, 

and storage levels, and significant expansions 

of pipelines capacity also worked to put 

downward pressure on natural gas prices. 5

At the same time, the cost of coal rose 6.8

percent (Table 3.8), largely due to long-term 

contracts signed prior to the recent recession. 6, 7

Between 2000 and 2009, coal prices to electric 

power plants rose 84 percent. 

Coal-to-gas switching. The increase in 

delivered coal prices and the decrease in 

delivered natural gas prices, combined with 

surplus capacity at highly-efficient gas-fired 

combined-cycle plants resulted in coal-to-gas 

fuel switching This occurred particularly in 

the Southeast (Alabama, Arkansas, Florida, 

Georgia, Mississippi, and South Carolina) and 

also Pennsylvania. Nationwide, coal-fired 

electric power generation declined 11.6 percent 

from 2008 to 2009, bringing coal’s share of the 

electricity power output to 44.5 percent, the

lowest level since 1978. Coal consumption at 

U.S. power plants paralleled the decline in 

generation, dropping 10.3 percent from 2008.

In sharp contrast, natural gas-fired generation 

increased 4.3 percent in 2009, despite the 4.1-

percent decline in overall electric generation. 

The natural gas share of generation increased to 

23.3 percent—the highest level since 1970. 

Electricity’s share of the total U.S. natural gas 

consumption has also risen rapidly, growing 

from 17 percent in 1996 to over 30 percent in 

2009.8

 

5 U.S. Energy Information Administration, Natural Gas Year-inReview, 2009 6 U.S. Energy Information Administration, U.S. Coal Supply and 

Demand: 2009 ”Coal Prices”, p. 12 7 The Southern Company (a large consumer of coal for electricity 

production), reported: “While coal prices reached unprecedented high 

levels in 2008, the recessionary economy pushed prices downward in 

2009. However, the lower prices did not fully offset the higher priced 

coal already in inventory and under long-term contract.” Southern 

Company 2009 10-K, p. II-16. 
2 U.S. Energy Information Administration/Electric Power Annual 2009

Wind development. Wind power has been the 

fastest-growing source of new electric power 

generation for several years. In 2009, generation 

from wind power increased 33.5 percent over 

2008, bringing the share of total generation to

1.9 percent. This followed year-over-year 

generation gains of 60.7 percent in 2008, 29.6 

percent in 2007, and 49.3 percent in 2006 (Table 

ES.1). Wind capacity in 2009 totaled 34,296 

megawatts (MW), as compared to 24,651 MW in 

2008. 

In 2009 (and 2010), wind generators were 

eligible for Federal production and investment 

tax credits or a cash grant in lieu of those tax 

credits. 9 Since passage of the 2005 Energy Policy 

Act (EPACT2005), interest-free financing via 

Clean Renewable Energy Bonds (CREBs) has 

been available to government entities investing 

in wind. Section 9006, under Title IX of the 

2002 and 2008 Farm Bills, also contains grant 

and loan guarantee provisions for wind projects 

for farmers, ranchers, and other rural businesses. 

Renewable generation is fostered by both 

Federal incentives and State renewable portfolio 

standards. As of October 2010, 29 States, the 

District of Columbia, and Puerto Rico have 

legislated renewable energy portfolio standards, 

and 7 more States have adopted renewable 

portfolio goals.10

.#'!#

Net generation of electric power fell 4.1 percent 

in 2009, to 3,950 million megawatthours (MWh) 

from 4,119 million MWh in 2008 (Figure ES1). 

This is the largest decline in electricity 

generation in at least 60 years. Electricity

generation also declined 0.9 percent in 2008. The 

years 2008 and 2009 represent only the third and 

fourth instances that generation has dropped year 

over year since 1949 (the first two occurrences 

were during recessions in 1982 and 2001). 

8

U.S. Energy Information Administration, Annual Energy Review, 

2009, Table 6.5.

9 The grant program arose out of Section 1603 of the American 

Economic Recovery and Reinvestment Act of 2009 (ARRA) and was 

intended to allow investors who could not take advantage of tax 

credits to fund these projects with an equivalent government grants.

This program expires December 31, 2010. See the Database of State 

Incentives for Renewables and Efficiency (DSIRE) at 

http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=U

S53F&re=1&ee=1

10 See the DSIRE database at http://www.dsireusa.org/. 

Additionally, this is the first time over the last 6 

decades that generation has declined in two 

consecutive years. 

Coal, natural gas, and nuclear generation 

accounted for 88.0 percent of total net generation 

in 2009, and between 85 and 90 percent during 

the period 1997 through 2009. However, the 

relative contribution of these energy sources has 

been shifting; natural gas generation has seen the 

fastest growth in recent years.

/!,$0 1 2101&'!&()#$'%

'.#'!#		

Source: U.S. Energy Information Administration, Form 

EIA-923, "Power Plant Operations Report.”

Coal. Coal-fired electric generation declined 

11.6 percent between 2008 and 2009. With this 

decline, coal’s share of electricity generation 

reached its lowest level since 1978: 44.5 percent 

of electricity generation in 2009, down from 48.2 

percent in 2008. 

Several factors have worked to erode the 

advantage that coal-fired generation has 

historically derived from its lower fuel costs. 

These factors include lower natural gas prices 

and higher coal prices; surplus capacity at 

efficient natural gas plants, and the cost of 

compliance with current environmental 

regulations.

Production at the Nation’s coal mines in 2009 

reflected the weakened state of coal demand for 
U.S. Energy Information Administration/Electric Power Annual 2009 3

electricity generation. Appalachian coal 

production fell 13.0 percent in 2009 from the 

previous year. Even Western (Powder River 

Basin) coal production, which has a significant 

price advantage, showed an 8.1-percent decline

in 2009.11

Natural gas-fired power generation increased 

by 4.3 percent in 2009, raising natural gas’s 

share of the electricity market to 23.3 percent—

its highest share since 1970. Natural gas’s share 

of the electricity market has been greater than the 

nuclear share since 2006. New capacity, as well 

as the increased utilization of existing generators

(see Table 5.2 on capacity factors), account for 

the increase in share.

Nuclear power generation accounted for 20.2 

percent of the electricity generated in 2009, a 

0.9-percent decrease from the prior year. The 

decline in nuclear generation in 2009 is the 

result of scheduled and unscheduled plant 

outages and derates. 

Hydroelectric power generation fluctuates

perennially with precipitation levels and snow 

accumulation. Overall, generation from 

conventional hydro plants (exclusive of pumped 

storage) increased 7.3 percent from 2008 to 2009 

(Table ES.1). The western States were still 

suffering from a prolonged drought during 2009.

The Bonneville Power Administration, which is 

the largest producer of hydroelectric power in the 

west, reported reduced runoff for the January 

through July 2009 period as compared to the 

same period in 2008.12 In contrast, many eastern 

States experienced record rainfall: Alabama, 

Georgia, Kentucky, North Carolina, and 

Tennessee all reported substantial gains in hydro 

generation in 2009. The Tennessee Valley 

Authority cited better water conditions, resulting 

in a 71-percent increase in hydropower during 

2009.13

 

 

Renewables. Total non-hydro renewable 

generation increased 14.0 percent in 2009, 

following a 19.9-percent increase in 2008. The 

fastest-growing component was wind power 

(33.5-percent increase). Solar generation 

11 U.S. Energy Information Administration .,Annual Coal Report, 

2008 and 2009, Table 6.

12 Bonneville Power Administration, 2009 Annual Report, (10-K),

p. 9. Melting snow creates much of BPA’s runoff. Snowpack in the 

mountains accumulates from December to February (approximately), 

and significant runoff, and therefore peak hydro production, occurs 

March through July (approximately). 

13 Tennessee Valley Authority, 2009 Annual Report (10-K), p.12.

increased 3.1 percent. Since 1998, generation 

from non-hydro renewables has increased 86.6 

percent.

In 2009, renewable generation made up 10.6 

percent of total generation. The largest three 

contributors were hydro (6.9 percent), wind (1.9 

percent), followed by wood and wood-derived 

fuels (0.9 percent). Discounting the hydro 

portion, renewable generation made up 3.6 

percent of total generation. 

Petroleum’s contribution to U.S. net electricity 

generation peaked in 1973 at 17 percent, but has 

fallen steadily since to almost insignificant 

levels. Petroleum’s share of power output fell 

below one percent in 2009, reflecting a 15.8- 

percent decrease in petroleum-fired power 

generation between 2008 and 2009. 

Nuclear and fossil capacity factors. The 

capacity factor is a measure of how consistently 

a generator is producing power: it represents the 

ratio of actual generation during a time period 

(typically a year) to the maximum possible 

generation assuming continuous full-load output. 

Baseload plants, which have high utilization 

rates due primarily to low variable operating 

costs, typically operate at capacity factors of 70

percent or higher. Intermediate plants, which 

have higher variable operating costs, typically

vary their output during the day to meet changes 

in load. The most expensive peaking plants may 

operate rarely and only to meet the highest 

peaks, usually in the summer or winter.

Due to decreased demand for electricity, the 

average capacity factor for many fuels fell in 

2009 (Table 5.2). Nuclear power plants (which 

in the United States are universally operated as 

baseload units because of their very low fuel 

costs) maintained a high capacity factor (90.3 in 

2009). The capacity factor for coal plants, which 

make up the bulk of U.S. baseload capacity but 

can also operate in load-following mode,14

dropped sharply (8.4 percentage points) in 2009, 

from 72.2 percent to 63.8 percent. 

The vast majority of natural gas capacity in the 

United States operates as load-following or 

peaking units. In 2009, coal-to-gas switching 

increased the usage of combined-cycle natural 

gas generators; the capacity factor for these units 

14 Despite representing only three quarters of the capacity of natural 

gas plants, coal plants account for approximately twice the amount of 

electricity produced by natural gas plants (Table ES.1)
4 U.S. Energy Information Administration/Electric Power Annual 2009

increased from 40.6 percent in 2008 to 42.5 

percent in 2009. 

34&!'%

Total U.S. net summer generating capacity grew 

by 1.5 percent between 2008 and 2009 to 1,025 

gigawatts (GW; Figure ES2). Both in absolute 

and percentage terms, wind generating capacity 

showed the strongest gains: the 9,645 MW of 

wind capacity additions were more than double 

that of natural gas, which had the second-largest 

increase in capacity at 3,812 MW. Coal, nuclear, 

and hydroelectric capacity experienced marginal 

gains.

During 2009, 382 new generators were 

connected to the grid, 51 fewer than in 2008 

(Table 1.11). These new units added 23,144 

MW of capacity, 50.1 percent of which were 

added by independent power producers (IPPs; 

11,590 MW), with nearly all of the remainder 

added by electric utilities (10,939 MW). 

Wind capacity additions accounted for 63.3 

percent of all capacity gains in 2009, 

increasing the amount of installed wind 

capacity by 39.1 percent. With 34.3 GW of 

total capacity, wind now accounts for 3.3 

percent of total U.S. capacity, up from less 

than 3 tenths of a percent 10 years earlier.

Four States accounted for 51 percent of total 

U.S. wind capacity: Texas (9.4 GW), 15 Iowa 

(3.4 GW), California (2.7 GW), and 

Washington (2.0 GW). 

Natural gas capacity. In 2009, natural gas 

capacity increased by 1.0 percent, led by 

installations in California, Florida and Texas. 

About 72 percent of all natural gas plant 

capacity additions during 2009 were highly 

efficient combined-cycle units. In 2009, 

combined-cycle units accounted for 50 percent 

of total natural-gas-fired electricity capacity 

versus 2 percent of natural gas-fired capacity 

two decades ago. Coal capacity. Coal-fired electric capacity 

increased by 0.3 percent between 2008 and 

2009 to 314,294 MW. A total of 13 new coal15 As of the end of 2009 Texas had 76 wind plants comprising 9.1 

percent of overall Texas electricity capacity. In 2005, Texas 

adopted a RPS which required the state to have 5,880 MW of total 

renewable capacity in place by 2015, and 10,000 MW by 2025. Texas 

is very close to meeting the 2025 standard with its wind capacity 

alone.

fired generators came on line in 2009, notably 

the 682-MW Nebraska City 2 unit (Omaha 

Public Power District) and the 415-MW 

Springerville 4 unit (Salt River Project). Both 

East Kentucky Power Cooperative and Archer 

Daniels Midland installed generators capable 

of co-firing coal with biomass. 

/!,$01 2101&'!&()

#$'%0$34&!'%

		

Source: U.S. Energy Information Administration, Form 

EIA-860, “Annual Electric Generator Report.”

Coal retirements in 2009 totaled 529 MW. 

Further retirements are planned. For example, 

in December 2009, Progress Energy announced 

that it planned to retire 11 generators (1,500 

MW) at four of its North Carolina coal plants 

that lacked desulfurization equipment, and 

replace the lost capacity with natural gas units. 

Progress Energy’s remaining units are all 

equipped with scrubbers. 16 

Solar capacity. Solar power is a rapidly 

growing source of new capacity, albeit from a 

relatively small base. Solar power producers 

added 83 MW of capacity in 2009, a 15.5-

percent increase over 2008. California, with 

450 MW of existing (utility-scale) solar 

capacity, accounted for 72.8 percent of total 

capacity, followed by Nevada, with 14.3 

percent of capacity. Two large plants were 

brought on line in 2009: FPL’s 25 MW 

DeSoto Solar Energy Plant in Florida, 

described as the largest photovoltaic solar 

16 “Progress Energy Plans to Retire Remaining Unscrubbed Coal 

Plants in NC,” December 1, 2009.
U.S. Energy Information Administration/Electric Power Annual 2009 5

plant in the world (at the time), 17 and NRG 

Energy’s 21-MW facility in Blythe, California, 

which was constructed in just 3 months. 

The 20 MW scale of recent solar power plant 

additions far exceeds the average size of the 

current fleet of solar units, but is in turn dwarfed 

by the scale of units in the planning stage. 18 For 

example, by 2013, BrightSource Energy is 

scheduled to bring on line all three units of its 

390-MW Ivanpah concentrated thermal power 

plant in California.

Nuclear uprates. Since 1998, there have been 

104 operable units in the United States. 19 In 

2009, nuclear capacity increased 249 MW, due 

to a combination of uprates (technical 

modifications of existing units) and other net 

capacity adjustments. Through such uprates to 

existing capacity, rather than new builds, 3.6 

GW of nuclear capacity have been added to the 

system over the past decade (Table 1.1), 

representing over 3 percent of total U.S. nuclear 

capacity in 2009. This added capacity is the 

equivalent of building several new reactors. 

Prospects for new nuclear reactors. Currently, 

there is one nuclear power unit under 

construction, TVA’s 1,150 MW Watts Bar 2, 

which is scheduled to be in operation in 2012. 

Initial construction of Watts Bar 2, which began 

in 1973, was suspended in 1988 and resumed in 

2007. TVA may also complete Unit 1 at its 

Bellefonte site, which would enter operation in 

the 2018-2019 time frame. TVA suspended

construction of Bellefonte in 1988.

During 2009, one application was submitted to 

the Nuclear Regulatory Commission (NRC) for 

the construction of two nuclear units at FPL’s 

existing Turkey Point facility. This compares to 

applications for 16 units during 2008 and 8 units 

in 2007. The NRC also granted an Early Site 

Permit to Southern Company’s/Georgia Power’s 

Vogtle nuclear power units 3 and 4 (August, 

2009) and preliminary site preparation has 

begun. 20

17 FPL. http://www.fpl.com/environment/solar/desoto.shtml. 18 Todd Woody, “Solar Power Projects Face Potential Hurdles,” The 

New York Times, October 28, 2010, 

http://www.nytimes.com/2010/10/29/business/energyenvironment/29solar.html?_r=1&scp=1&sq=ivanpah&st=cse. 19 TVA’s Brown Ferry 1 was offline for many years but was officially

classified as “operable” because it retained a Nuclear Regulatory 

Commission operating license. The unit actually returned to service 

in 2007. 

20 Other investors include Oglethorpe Power (30 percent) and the 

Municipal Electric Authority of Georgia (22.7 percent). Source: 

(##34&!'%

Capacity plans are constantly evolving as electric 

power producers navigate a dynamic, rapidly 

changing market. Each year, EIA asks electric 

power producers for a snapshot of their plans as 

of the end of the previous year. The information 

below, and in Table 1.4, represents capacity 

plans as of December 31, 2009, as reported to 

EIA during the spring of 2010. EIA also collects 

monthly data on the status of proposed 

generators. 21 

Capacity additions by fuel type. As of the end 

of 2009 electric power producers planned to add 

72,157 MW of capacity between 2010 and 2014. 

Of this, 48.3 percent was planned to be fired by 

natural gas (34,828 MW) and 23.1 percent from 

coal (16,685 MW) (Figure ES3). 

/!,$0
1 (##0$34&!'%

!'!#	 		 

Source: U.S. Energy Information Administration, Form 

EIA-860, “Annual Electric Generator Report.”

For the period 2010-2014, planned wind 

additions totaled 11,560 MW, or 16.0 percent of 

total reported planned additions. Wind plants 

have a much shorter planning horizon and are 

built more quickly than fossil fuel-fired plants; 

only 6.2 percent of the reported new wind 

capacity additions were planned to occur after 

2012.

World Nuclear News, “Georgia Power Accepts Vogtle Loan 

Guarantee,” June 21, 2010. 21U.S. Energy Information Administration, Electric Power Monthly,

Table ES3, New and Planned U.S. Electric Generating Units.
6 U.S. Energy Information Administration/Electric Power Annual 2009

Solar additions were expected to add 4,087 MW 

of capacity by 2014. The planned completion of 

Watts Bar 2 in 2012 would add 1,122 MW of 

nuclear capacity. The construction of new coal 

plants has been discouraged by increasing costs 

for capital-intensive projects, concerns over 

possible future CO2 and other environmental 

restrictions, and the prospect that natural gas 

prices will remain low over the long-term. 

&'!&!'%0#(!&

In 2009, retail sales of electricity fell to 3,597 

billion kilowatthours, a 3.6-percent decline from 

the prior year and the lowest level of sales since 

2004 (Table 7.2). Industrial demand experienced

the greatest decline, falling 9.1 percent from 

2008, to levels unseen since 1987. The 

residential and commercial sectors reported 

declines of 1.1 percent and 2.2 percent, 

respectively. 

Retail sales to industrial customers. The 

Federal Reserve Bank’s index of industrial 

production fell 9.2 percent in 2009, driven by 41 

and 42 percent decreases in the automobile and 

iron and steel components, respectively.22 In the 

East North Central Census Division, which 

contains some of the Nation’s most 

industrialized States (Illinois, Indiana, Michigan, 

Ohio, and Wisconsin), overall electricity demand 

declined 6.9 percent (Figure ES4), led by a 12.3-

percent decline in industrial demand. The East 

South Central States (Alabama, Kentucky, 

Mississippi, and Tennessee) saw the next largest 

decline at 6.8 percent. 

Weather and Retail Sales to Residential 

Customers. Year-over-year (i.e., short term) 

changes in residential electricity sales largely 

reflect changes in the weather. Summer 

temperatures during 2009 were relatively mild in 

the contiguous states. 23

 

This dampened air 

conditioning demand; for the June through 

August summer period, residential electricity 

sales declined 3.3 percent between 2008 and 

2009. 

22 IHS Global Insight, “U.S. Economic Outlook,” April 2010, p. 92.

23 National Oceanic & Atmospheric Administration, National Data 

Climate Center, State of the Climate National Overview Annual 2009

/!,$01 ##$3-#,!#'!

0'5$##

2#$#3$'		

'		
(&#'3-#,

Source: U.S. Energy Information Administration, 

Form EIA-861, “Annual Electric Power Industry 

Report.”

Prices. Overall retail electricity prices rose 0.9 

percent between 2008 and 2009 (from 9.74 cents 

to 9.83 cents per kWh). The overall 25.8-percent 

decline in fossil fuel prices as delivered to 

electric plants had little immediate impact on 

electric power prices to the end user; the lag in 

changes between fuel prices and power prices 

can be a year or two, as changes in retail 

electricity rates are dependent on each State’s 

utility regulatory review process. 

&'!&6

Wholesale Markets. Wholesale power 

purchases in 2009 totaled 5,029 million MWh.24

This represents a decrease of 10.4 percent 

between 2008 and 2009, following an increase of 

3.7 percent from 2007 to 2008 (Table 6.1) and a 

peak in 2002 at 8,755 million MWh. Electric 

utilities and energy-only providers (power 

marketers) each account for roughly half of 

wholesale purchases. The power marketers’ 

share of the wholesale market dropped from 69.1 

percent in 2002 to 51.0 percent in 2009, as a 

consequence of the financial failure of many 

marketers and contraction of trade following the 

collapse of Enron. Electric utilities’ wholesale 

purchases have generally remained stable over 

the last decade, but in a shrinking market their 

market share has risen from 29.9 percent in 2002 

to 47.0 percent in 2009. 

24 A single “block” of electricity can be sold multiple times, with each 

purchase appearing in the data reported to EIA. Consequently, total 

wholesale purchases exceed total supply of electricity (3,950 million 

MWh in 2009).
U.S. Energy Information Administration/Electric Power Annual 2009 7

Electricity sales for resale (wholesale power 

sales) fell similarly in 2009, down 10.8 percent 

from 2008 to 5,065 million MWh. Energy-only 

providers made up 44.2 percent of the market in 

2009. Electric utilities comprised 29.5 percent of 

the market in 2009, IPPs 25.6 percent, and

combined heat and power plants less than one 

percent. 

International trade. The U.S. buys from and 

sells electricity to Canada and, to a much smaller 

degree, Mexico. Although the U.S. imported 

slightly less than 1 percent of its electricity 

consumption in 2009, Canadian exports account 

for roughly 8 percent of Canada’s production of 

electricity (Table 6.3).25 Canada is the second 

largest exporter of electricity in the world, 

primarily generated by hydroelectric plants in 

Quebec, Ontario, and British Columbia. 26

Canadian and U.S. electricity markets are highly 

integrated with multiple transmission lines 

crossing the international border. 

Electricity trade with Mexico is much smaller. 

Net purchases from Mexico in 2009 constituted 

0.01 percent of total U.S. supply. 

/!/$

Stocks at Electric Power Plants. End-of-year 

coal stocks rose 17.3 percent between 2008 and 

2009 to reach their highest levels in at least 60 

years. At 189 million tons, coal stocks have 

almost doubled since 2005 (Table 3.4), probably 

due to the sharp decline in coal-fired generation 

combined with limited flexibility in coal supply 

contracts to reduce deliveries. 27 In some cases, 

this involuntary inventory accumulation has 

prompted utilities to attempt to renegotiate their 

coal contracts or to petition their PUCs for 

ameliorative actions. 28

25 U..S. Energy Information Administration, International Energy 

Statistics, 

http://tonto.eia.doe.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=2&pid

=2&aid=12. Note: The ratio of Canadian electricity exports to 

domestic generation is for the year 2008.

26 North America Energy Working Group, Security and Prosperity 

Partnership, Energy Picture Experts Group, “North America—The 

Energy Picture II,” January 2006. 27 In its 2009 annual report, the large coal-fired generation company, 

AEP Corp, cited “an increase in coal inventory reflecting decreased

customer demand for electricity” AEP 2009 Annual Report, p. 20. 28Duke Energy Carolinas, Docket No. E-7, Sub 909, and Indiana 

Utility Regulatory Commission, Cause No. 38707 FAC 83, Approved 

March 24, 2010 

http://www.in.gov/iurc/files/38707_83order_032410.pdf. 

/! /$ 3'1 The average delivered 

cost of fossil fuels to electric power plants fell 

26.0 percent in 2009, from $4.11 per MMBtu in 

2008 to $3.04 per MMBtu (Table 3.5). Most of 

this decline relates to natural gas prices; in 2009 

natural gas prices fell to about half their 2008 

levels (Figure ES5). Annual average costs of 

natural gas to the electric power industry 

peaked in 2008 at $9.02 per million Btu—the 

highest nominal dollar level in at least two 

decades—before falling to $4.74 per MMBtu in 

2009. The average cost of coal actually rose 

between 2008 and 2009 from $2.07 to $2.21 per 

MMBtu, due to the prevalence of long-term 

contracts and the relatively small role of the 

coal spot market. 

!!#

Decreases in all emissions. Estimated emissions 

of carbon dioxide (CO2), sulfur dioxide (SO2), 

and nitrogen oxide (NOx) all declined in 2009 

compared to 2008 (Table 3.9). This was due in 

part to reduced coal-fired generation. Coal 

produces far more emissions per kWh of 

electricity than other major fuels. SO2 and NOx

emissions were further reduced by installations 

of new emission control devices.

SO2 emissions fell 23.8 percent between 2008 

and 2009, from 7,830 thousand metric tons to 

5,970 thousand metric tons (Table 3.9). This is

the largest year-over-year decline since 1989 (the 

/!,$071 /!/$3'8

&'!&!'%.#'!#

 		

Source: U.S. Energy Information Administration, 

Form EIA-923, "Power Plant Operations Report.”
8 U.S. Energy Information Administration/Electric Power Annual 2009

first year in EIA’s data series). Nationwide, the 

count of generators with SO2 control systems

increased from 327 in 2008 to 384 in 2009 

(Table 3-10), contributing to the reduction in 

SO2 emissions. 

Data for 2009 also show significant reductions in 

NOx emissions, which dropped 28.1 percent 

from 2008, from 3,330 to 2,395 thousand metric 

tons—also the largest decline on record. Since 

1998, sulfur dioxide and nitrogen oxide 

emissions have been reduced by 55.7 percent and 

62.9 percent, respectively, largely due to the 

implementation of the Clean Air Act 

Amendments of 1990.

Estimated CO2 emissions by U.S. electric 

generators and combined heat and power 

facilities fell by 8.6 percent from 2008 to 2009 

(from 2,484 million metric tons to 2,270 million 

metric tons), largely due to decreased coal

consumption. Emissions from coal-fired power 

plants typically account for four fifths of CO2 

emissions produced by the electric power sector. 

The estimated CO2, SO2, and NOx emissions are 

determined by the type and quantity of fossil 

fuels consumed by power plants. In the case of 

SO2 and NOx, boiler configurations and the 

presence of, or absence of, pollution abatement 

equipment play a major role. The methodology 

used to estimate emissions is described in the 

Technical Notes and Tables A1, A2, and A3.
U.S. Energy Information Administration/Electric Power Annual 2009 9

Table ES1. Summary Statistics for the United States, 1998 through 2009

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Net Generation (thousand megawatthours)

Coal1 ............................................................ 1,755,904 1,985,801 2,016,456 1,990,511 2,012,873 1,978,301 1,973,737 1,933,130 1,903,956 1,966,265 1,881,087 1,873,516 

Petroleum2 .................................................... 38,938 46,243 65,739 64,166 122,225 121,145 119,406 94,567 124,880 111,221 118,061 128,800 

Natural Gas3 ................................................. 920,797 882,981 896,590 816,441 760,960 710,100 649,908 691,006 639,129 601,038 556,396 531,257 

Other Gases4................................................. 10,629 11,707 13,453 14,177 13,464 15,252 15,600 11,463 9,039 13,955 14,126 13,492 

Nuclear ......................................................... 798,855 806,208 806,425 787,219 781,986 788,528 763,733 780,064 768,826 753,893 728,254 673,702 

Hydroelectric Conventional5......................... 273,445 254,831 247,510 289,246 270,321 268,417 275,806 264,329 216,961 275,573 319,536 323,336 

Other Renewables6 ....................................... 143,824 126,101R 105,238 96,525 87,329 83,067 79,487 79,109 70,769 80,906 79,423 77,088

Wind........................................................ 73,886 55,363 34,450 26,589 17,811 14,144 11,187 10,354 6,737 5,593 4,488 3,026

Solar Thermal and Photovoltaic............... 891 864 612 508 550 575 534 555 543 493 495 502

Wood and Wood Derived Fuels7.............. 35,596 37,300 39,014 38,762 38,856 38,117 37,529 38,665 35,200 37,595 37,041 36,338

Geothermal.............................................. 15,009 14,840R 14,637 14,568 14,692 14,811 14,424 14,491 13,741 14,093 14,827 14,774

Other Biomass8........................................ 18,443 17,734 16,525 16,099 15,420 15,421 15,812 15,044 14,548 23,131 22,572 22,448

Pumped Storage9 .......................................... -4,627 -6,288 -6,896 -6,558 -6,558 -8,488 -8,535 -8,743 -8,823 -5,539 -6,097 -4,467

Other10 .......................................................... 11,929 11,804R 12,231 12,974 12,821 14,232 14,045 13,527 11,906 4,794 4,024 3,571

All Energy Sources ..................................... 3,949,694 4,119,388 4,156,745 4,064,702 4,055,423 3,970,555 3,883,185 3,858,452 3,736,644 3,802,105 3,694,810 3,620,295

Net Summer Generating Capacity (megawatts)

Coal1............................................................. 314,294 313,322 312,738 312,956 313,380 313,020 313,019 315,350 314,230 315,114 315,496 315,786 

Petroleum2 .................................................... 56,781 57,445 56,068 58,097 58,548 59,119 60,730 59,651 66,162 61,837 60,069 66,282 

Natural Gas3 ................................................. 401,272 397,460R 392,876 388,294 383,061 371,011 355,442 312,512 252,832 219,590 195,119 180,288 

Other Gases4 ................................................. 1,932 1,995 2,313 2,256 2,063 2,296 1,994 2,008 1,670 2,342 1,909 1,520 

Nuclear ......................................................... 101,004 100,755 100,266 100,334 99,988 99,628 99,209 98,657 98,159 97,860 97,411 97,070 

Hydroelectric Conventional5......................... 78,518 77,930 77,885 77,821 77,541 77,641 78,694 79,356 78,916 79,359 79,393 79,151

Other Renewables6 ....................................... 48,552 38,466R 30,069 24,113 21,205 18,717 18,153 16,710 16,101 15,572 15,942 15,444 

Wind........................................................ 34,296 24,651 16,515 11,329 8,706 6,456 5,995 4,417 3,864 2,377 2,252 1,720

Solar Thermal and Photovoltaic............... 619 536 502 411 411 398 397 397 392 386 389 335

Wood and Wood Derived Fuels7.............. 6,939 6,864 6,704 6,372 6,193 6,182 5,871 5,844 5,882 6,147 6,795 6,802

Geothermal.............................................. 2,382 2,229R 2,214 2,274 2,285 2,152 2,133 2,252 2,216 2,793 2,846 2,893

Other Biomass11....................................... 4,317 4,186 4,134 3,727 3,609 3,529 3,758 3,800 3,748 3,869 3,660 3,694

Pumped Storage9 .......................................... 22,160 21,858 21,886 21,461 21,347 20,764 20,522 20,371 19,664 19,522 19,565 19,518

Other12 .......................................................... 888 942 788 882 887 746 684 686 519 523 1,023 810

All Energy Sources ..................................... 1,025,400 1,010,171 994,888 986,215 978,020 962,942 948,446 905,301 848,254 811,719 785,927 775,868

Demand, Capacity Resources, and Capacity Margins – Summer

Net Internal Demand (megawatts) ................ 713,106 744,151R 766,786R 776,479 746,470 692,908 696,752 696,376 674,833 680,941 653,857 638,086 

Capacity Resources (megawatts) .................. 916,449 909,504R 914,397R 891,226 882,125 875,870 856,131 833,380 788,990 808,054 765,744 744,670

Capacity Margins (percent)........................... 22.2 18.2 16.1 12.9 15.4 20.9 18.6 16.4 14.5 15.7 14.6 14.3

Fuel

Consumption of Fossil Fuels for Electricity Generation

Coal (thousand tons)1............................. 934,683 1,042,335 1,046,795 1,030,556 1,041,448 1,020,523 1,014,058 987,583 972,691 994,933 949,802 946,295 

Petroleum (thousand barrels)2................ 67,666 80,932 112,615 110,634 206,785 203,494 206,653 168,597 216,672 195,228 207,871 222,640 

Natural Gas (millions of cubic feet)3 ..... 7,120,585 6,895,843 7,089,342 6,461,615 6,036,370 5,674,580 5,616,135 6,126,062 5,832,305 5,691,481 5,321,984 5,081,384 

Other Gases (millions of Btu)4 ............... 83,593 96,757 114,904 114,665 109,916 135,144 156,306 131,230 97,308 125,971 126,387 124,988 

Consumption of Fossil Fuels for Thermal Output in Combined Heat and Power Facilities

Coal (thousand tons)1............................. 20,507 22,168 22,810 23,227 23,833 24,275 17,720 17,561 18,944 20,466 20,373 20,320 

Petroleum (thousand barrels)2................ 13,164 12,016 19,775 20,371 24,408 25,870 17,939 14,811 18,268 22,266 26,822 28,845 

Natural Gas (millions of cubic feet)3 ..... 816,787 793,537 872,579 942,817 984,340 1,052,100 721,267 860,019 898,286 985,263 982,958 949,106 

Other Gases (millions of Btu)4 ............... 175,671 203,236 214,321 226,464 238,396 218,295 137,837 146,882 166,161 230,082 223,713 208,828 

Consumption of Fossil Fuels for Electricity Generation and Useful Thermal Output

Coal (thousand tons)1............................. 955,190 1,064,503 1,069,606 1,053,783 1,065,281 1,044,798 1,031,778 1,005,144 991,635 1,015,398 970,175 966,615 

Petroleum (thousand barrels)2................ 80,830 92,948 132,389 131,005 231,193 229,364 224,593 183,408 234,940 217,494 234,694 251,486 

Natural Gas (millions of cubic feet)3 ..... 7,937,372 7,689,380 7,961,922 7,404,432 7,020,709 6,726,679 6,337,402 6,986,081 6,730,591 6,676,744 6,304,942 6,030,490

Other Gases (millions of Btu)4 ............... 259,264 299,993 329,225 341,129 348,312 353,438 294,143 278,111 263,469 356,053 350,100 333,816 

Stocks at Electric Power Sector Facilities (year end)

Coal (thousand tons)13............................ 189,467 161,589 151,221 140,964 101,137 106,669 121,567 141,714 138,496 102,296 141,604 120,501 

Petroleum (thousand barrels)14............... 46,181 44,498 47,203 51,583 50,062 51,434 53,170 52,490 57,031 40,932 54,109 56,591 

Receipts of Fuel at Electricity Generators15

Coal (thousand tons)1............................. 981,477 1,069,709 1,054,664 1,079,943 1,021,437 1,002,032 986,026 884,287 762,815 790,274 908,232 929,448 

Petroleum (thousand barrels)2................ 88,951 96,341 88,347 100,965 194,733 186,655 185,567 120,851 124,618 108,272 145,939 181,276 

Natural Gas (millions of cubic feet)16 .... 8,118,550 7,879,046 7,200,316 6,675,246 6,181,717 5,734,054 5,500,704 5,607,737 2,148,924 2,629,986 2,809,455 2,922,957 

Cost of Fuel at Electricity Generators (cents per million Btu)15

Coal1........................................................ 221 207 177 169 154 136 128 125 123 120 122 125

Petroleum2 ............................................... 702 1,087 717 623 644 429 433 334 369 418 236 202

Natural Gas16 ........................................... 474 902 711 694 821 596 539 356 449 430 257 238

Emissions (thousand metric tons)

Carbon Dioxide (CO2) .................................. 2,269,508 2,484,012R 2,547,032R 2,488,918R 2,543,838R 2,486,982R 2,445,094R 2,423,963R 2,418,607R 2,470,834R 2,366,302R 2,351,600R

Sulfur Dioxide (SO2) .................................... 5,970 7,830 9,042 9,524 10,340 10,309 10,646 10,881 11,174 11,963 12,843 13,464

Nitrogen Oxides (NOX)................................. 2,395 3,330 3,650 3,799 3,961 4,143 4,532 5,194 5,290 5,638 5,955 6,459 

Trade (million megawatthours)

Purchases...................................................... 5,029 5,613 5,411 5,503 6,092 6,999 6,980 8,755 7,555 2,346 2,040 2,021

Sales for Resale ............................................ 5,065 5,681 5,479 5,493 6,072 6,759 6,921 8,569 7,345 2,355 1,998 1,922

Electricity Imports and Exports (thousand megawatthours)

Imports ......................................................... 52,191 57,019R 51,396 42,691 43,929R 34,210 30,395 36,779 38,500 48,592 43,215 39,513 

Exports ......................................................... 18,138 24,198R 20,144 24,271 19,151R 22,898 23,975 15,796 16,473 14,829 14,222 13,656 

See end of table for Notes and Sources.
10 U.S. Energy Information Administration/Electric Power Annual 2009

Table ES1. Summary Statistics for the United States, 1998 through 2009 

(Continued) 

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Retail Sales and Revenue Data – Bundled and Unbundled

Number of Ultimate Customers (thousands)

Residential.................................................... 125,177 124,937 123,950 122,471 120,761 118,764 117,280 116,622 114,890 111,718 110,383 109,048 

Commercial .................................................. 17,562 17,563 17,377 17,172 16,872 16,607 16,550 15,334 14,867 14,349 14,074 13,887 

Industrial ...................................................... 758 775 794 760 734 748 713 602 571 527 553 540

Transportation .............................................. 1 1 1 1 1 1 1 NA NA NA NA NA

Other ............................................................ NA NA NA NA NA NA NA 1,067 1,030 974 935 933

All Sectors .................................................... 143,497 143,276 142,122 140,404 138,367 136,119 134,544 133,624 131,359 127,568 125,945 124,408 

Sales to Ultimate Customers (thousand megawatthours)

Residential.................................................... 1,364,474 1,379,981 1,392,241 1,351,520 1,359,227 1,291,982 1,275,824 1,265,180 1,201,607 1,192,446 1,144,923 1,130,109

Commercial .................................................. 1,307,168 1,335,981 1,336,315 1,299,744 1,275,079 1,230,425 1,198,728 1,104,497 1,083,069 1,055,232 1,001,996 979,401

Industrial ...................................................... 917,442 1,009,300 1,027,832 1,011,298 1,019,156 1,017,850 1,012,373 990,238 996,609 1,064,239 1,058,217 1,051,203

Transportation .............................................. 7,781 7,700 8,173 7,358 7,506 7,224 6,810 NA NA NA NA NA

Other ............................................................ NA NA NA NA NA NA NA 105,552 113,174 109,496 106,952 103,518 

All Sectors .................................................... 3,596,865 3,732,962 3,764,561 3,669,919 3,660,969 3,547,479 3,493,734 3,465,466 3,394,458 3,421,414 3,312,087 3,264,231 

Direct Use..................................................... 126,938 132,197R 125,670R 146,927 150,016 168,470 168,295 166,184 162,649 170,943 171,629 160,866 

Total Disposition .......................................... 3,723,803 3,865,159R 3,890,231R 3,816,845 3,810,984 3,715,949 3,662,029 3,631,650 3,557,107 3,592,357 3,483,716 3,425,097 

Revenue From Ultimate Customers (million dollars)

Residential.................................................... 157,008 155,433 148,295 140,582 128,393 115,577 111,249 106,834 103,158 98,209 93,483 93,360

Commercial .................................................. 134,106 138,469 128,903 122,914 110,522 100,546 96,263 87,117 85,741 78,405 72,771 72,575 

Industrial ...................................................... 61,459 68,920 65,712 62,308 58,445 53,477 51,741 48,336 50,293 49,369 46,846 47,050

Transportation .............................................. 829 827 792 702 643 519 514 NA NA NA NA NA

Other ............................................................ NA NA NA NA NA NA NA 7,124 8,151 7,179 6,796 6,863

All Sectors .................................................... 353,403 363,650 343,703 326,506 298,003 270,119 259,767 249,411 247,343 233,163 219,896 219,848

Average Retail Price (cents per kilowatthour)

Residential.................................................... 11.51 11.26 10.65 10.40 9.45 8.95 8.72 8.44 8.58 8.24 8.16 8.26 

Commercial .................................................. 10.26 10.36 9.65 9.46 8.67 8.17 8.03 7.89 7.92 7.43 7.26 7.41 

Industrial ...................................................... 6.70 6.83 6.39 6.16 5.73 5.25 5.11 4.88 5.05 4.64 4.43 4.48 

Transportation .............................................. 10.65 10.74 9.70 9.54 8.57 7.18 7.54 NA NA NA NA NA

Other ............................................................ NA NA NA NA NA NA NA 6.75 7.20 6.56 6.35 6.63 

All Sectors .................................................... 9.83 9.74 9.13 8.90 8.14 7.61 7.44 7.20 7.29 6.81 6.64 6.74 

Revenue and Expense Statistics (million dollars)

Major Investor Owned

Utility Operating Revenues ........................... 276,124 298,962 270,964R 275,501 265,652 238,759 230,151 219,609 267,276 233,915 213,090 214,849

Utility Operating Expenses............................ 244,243 267,263 241,198R 245,589 236,786 206,960 201,057 189,062 234,910 210,250 180,467 183,954

Net Utility Operating Income ........................ 31,881 31,699 29,766R 29,912 28,866 31,799 29,094 30,548 32,366 23,665 32,623 30,896

Major Publicly Owned (with Generation Facilities)

Operating Revenues ...................................... NA NA NA NA NA NA 33,906 32,776 38,028 31,843 26,767 26,155 

Operating Expenses....................................... NA NA NA NA NA NA 29,637 28,638 32,789 26,244 21,274 20,880 

Net Electric Operating Income ...................... NA NA NA NA NA NA 4,268 4,138 5,238 5,598 5,493 5,275 

Major Publicly Owned (without Generation Facilities)

Operating Revenues ...................................... NA NA NA NA NA NA 12,454 11,546 10,417 9,904 9,354 8,790

Operating Expenses....................................... NA NA NA NA NA NA 11,481 10,703 9,820 9,355 8,737 8,245 

Net Electric Operating Income ...................... NA NA NA NA NA NA 974 843 597 549 617 545

Major Federally Owned

Operating Revenues ...................................... NA NA NA NA NA NA 11,798 11,470 12,458 10,685 10,186 9,780 

Operating Expenses....................................... NA NA NA NA NA NA 8,763 8,665 10,013 8,139 7,775 7,099 

Net Electric Operating Income ...................... NA NA NA NA NA NA 3,035 2,805 2,445 2,546 2,411 2,681 

Major Cooperative Borrower Owned 

Operating Revenues ...................................... 42,189 42,087R 38,208 36,723 34,088 30,650 29,228 27,458 26,458 25,629 23,824 23,988

Operating Expenses....................................... 38,337 38,511R 34,843 33,550 31,209 27,828 26,361 24,561 23,763 22,982 21,283 21,223

Net Electric Operating Income ...................... 3,852 3,576R 3,365 3,173 2,879 2,822 2,867 2,897 2,696 2,647 2,541 2,764 

Demand-Side Management (DSM) Data17

Actual Peak Load Reductions (megawatts)

Total Actual Peak Load Reduction ................ 31,682 31,735R 30,253 27,240 25,710 23,532 22,904 22,936 24,955 22,901 26,455 27,231

DSM Energy Savings (thousand megawatthours)

Energy Efficiency.......................................... 76,891 74,861R 67,134 62,951 58,891 52,662 48,245 52,285 52,946 52,827 49,691 48,775 

Load Management......................................... 1,015 1,813R 1,857 865 1,006 2,047 2,020 1,790 990 875 872 392

DSM Cost (million dollars)

Total Cost ................................................... 3,594 3,175R 2,523 2,051 1,921 1,557 1,297 1,626 1,630 1,565 1,424 1,421 





1 Includes anthracite, bituminous, subbituminous and lignite coal. Waste and synthetic coal are included starting in 2002.

2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology) and waste oil.

3 Includes a small number of generators for which waste heat is the primary energy source.

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 5 Conventional hydroelectric power excluding pumped storage facilities.

6 Other renewables represents the summation of the sub-categories of Wind, Solar Thermal and Photovoltaic, Wood and Wood Derived Fuels, Geothermal, and Other Biomass. 7 Wood/wood waste solids (including paper pellets, railroad ties, utility poles, wood chips, bark, and wood waste solids), wood waste liquids (red liquor, sludge wood, spent sulfite liquor, 

and other wood-based liquids), and black liquor.

8 Biogenic municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, 

methane, and other biomass gases).

9 Pumped storage is the capacity to generate electricity from water previously pumped to an elevated reservoir and then released through a conduit to turbine generators located at a lower 

level. The generation from a hydroelectric pumped storage facility is the net value of production minus the energy used for pumping.. 10 Non-biogenic municipal solid waste, batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies. 11 Municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, methane, and 

other biomass gases).
U.S. Energy Information Administration/Electric Power Annual 2009 11

12 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies. 13 Anthracite, bituminous, subbituminous, lignite, and synthetic coal; excludes waste coal. 14 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to 

liquid petroleum, see Technical Notes for conversion methodology). Data prior to 2004 includes small quantities of waste oil. 15 For 2002 through 2007, includes data from the Form EIA-423 for independent power producers, and commercial and industrial power-producing facilities. Beginning in 2008, data are

collected on the Form EIA-923 for utilities, independent power producers, and commercial and industrial power-producing facilities. Receipts, cost, and quality data are collected from

plants above a 50 MW threshold, and imputed for plants between 1 and 50 MW. Therefore, there may be a notable increase in fuel receipts beginning with 2008 data. Receipts of coal 

include imported coal.

16 Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately. 17 Data presented are reflective of large utilities.

NA = Not available. 

R = Revised. 

Note: ·See Glossary reference for definitions.·See Technical Notes Table A5 for conversion to different units of measure.·Capacity by energy source is based on the capacity associated 

with the energy source reported as the most predominant (primary) one, where more than one energy source is associated with a generator.·Dual-fired capacity returned to respective fuel 

categories for current and all historical years. New fuel switchable capacity tables have replaced dual-fired breakouts.·Totals may not equal sum of components because of ind

Sources: U.S. Energy Information Administration Form EIA-411, "Coordinated Bulk Power Supply Program Report;" Form EIA-412, "Annual Electric Industry Financial Report" The 

Form EIA-412 was terminated in 2003; Form EIA-767, "Steam-Electric Plant Operation and Design Report" was suspended; Form EIA-860, "Annual Electric Generator Report;" Form 

EIA-861, "Annual Electric Power Industry Report;" Form EIA-923, "Power Plant Operations Report" replaces several form(s) including: Form EIA-906, "Power Plant Report;" Form EIA920 "Combined Heat and Power Plant Report;" Form EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report; and FERC Form 423, "Monthly Report of Cost and Quality 

of Fuels for Electric Plants," and their predecessor forms. Federal Energy Regulatory Commission, FERC Form 1, "Annual Report of Major Utilities, Licensees and Others;" FERC Form 

1-F, "Annual Report for Nonmajor Public Utilities and Licensees;" Rural Utilities Service (RUS) Form 7, "Operating Report;" RUS Form 12, "Operating Report;" Imports and Exports: 

DOE, Office of Electricity Delivery and Energy Reliability, Form OE-781R, " Annual Report of International Electric Export/Import Data," predecessor forms, and National Energy Board 

of Canada. For 2001 forward, data from the California Independent System Operator are used in combination with the Form OE-781R values to estimate electricity trade with Mexico.
12 U.S. Energy Information Administration/Electric Power Annual 2009

Table ES2. Supply and Disposition of Electricity, 1998 through 2009 

(Million Megawatthours) 

Category 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Supply

Generation ..........................................................

 Electric Utilities.......................................... 2,373 2,475 2,504 2,484 2,475 2,505 2,462 2,549 2,630 3,015 3,174 3,212

 Independent Power Producers ..................... 1,278 1,332 1,324 1,259 1,247 1,119 1,063 955 781 458 201 91

 Combined Heat and Power, Electric............ 159 167 177 165 180 184 196 194 170 165 155 154

Electric Power Sector Generation Subtotal ....... 3,810 3,974 4,005 3,908 3,902 3,808 3,721 3,698 3,580 3,638 3,530 3,457

 Combined Heat and Power, Commercial..... 8 8 8 8 8 8 7 7 7 8 9 9

 Combined Heat and Power, Industrial......... 132 137 143 148 145 154 155 153 149 157 156 154

Industrial and Commercial Generation Subtotal 140 145 151 157 153 162 162 160 157 165 165 163

Total Net Generation .......................................... 3,950 4,119 4,157 4,065 4,055 3,971 3,883 3,858 3,737 3,802 3,695 3,620

Total Imports ...................................................... 52 57 51 43 44R 34 30 37 39 49 43 40

Total Supply ...................................................... 4,002 4,176 4,208 4,107 4,099R 4,005 3,914 3,895 3,775 3,851 3,738 3,660

Disposition

Retail Sales .......................................................

 Full-Service Providers................................. 3,289 3,434 3,468 3,438 3,413 3,318 3,285 3,324 3,297 3,310 3,236 3,240

 Energy-Only Providers................................ 296 286 283 219 237 222 189 141 98 112 76 24

 Facility Direct Retail Sales.......................... 13 14 14 12 11 8 20 NA NA NA NA NA

Total Electric Industry Retail Sales..................... 3,597 3,733 3,765 3,670 3,661 3,547 3,494 3,465 3,394 3,421 3,312 3,264

Direct Use........................................................... 127 132R 126R 147 150 168 168 166 163 171 172 161

Total Exports ...................................................... 18 24 20 24 19R 23 24 16 16 15 14 14

Losses and Unaccounted For .............................. 260 287R 298R 266 269 266 228 248 202 244 240 221

Total Disposition ............................................... 4,002 4,176 4,208 4,107 4,099R 4,005 3,914 3,895 3,775 3,851 3,738 3,660

NA = Not available. 

R = Revised. 

Notes: • Facility Direct Retail Sales typically represent bilateral electric power sales between industrial and commercial generating facilities. • Direct Use represents commercial and 

industrial facility use of onsite net electricity generation; electricity sales or transfers to adjacent or co-located facilities; and barter transactions. Losses and Unaccounted For includes: (1) 

reporting by utilities and power marketers that represent losses incurred in transmission and distribution, as well as volumes unaccounted for in their own energy balance; and (2) 

discrepancies among the differing categories upon balancing the table. • Totals may not equal sum of components because of independent rounding.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-861, "Annual Electric Power Industry Report;" and predecessor forms. Imports 

and Exports: Mexico data - DOE, Fossil Fuels, Office of Fuels Programs, Form OE-781R, "Annual Report of International Electrical Export/Import Data:" Canada data - National Energy 

Board of Canada (metered energy firm and interruptible).
U.S. Energy Information Administration/Electric Power Annual 2009 13

Chapter 1. Capacity 
14 U.S. Energy Information Administration/Electric Power Annual 2009

Table 1.1. Existing Net Summer Capacity by Energy Source and Producer Type, 1998 through 2009

(Megawatts)

Period Coal1 Petroleum 2 Natural 

Gas3

Other 

Gases4 Nuclear Hydroelectric 

Conventional5

Other 

Renewables6

Hydroelectric 

Pumped 

Storage7

Other8 Total

Total (All Sectors)

1998................... 315,786 66,282 180,288 1,520 97,070 79,151 15,444 19,518 810 775,868

1999................... 315,496 60,069 195,119 1,909 97,411 79,393 15,942 19,565 1,023 785,927

2000................... 315,114 61,837 219,590 2,342 97,860 79,359 15,572 19,522 523 811,719

2001................... 314,230 66,162 252,832 1,670 98,159 78,916 16,101 19,664 519 848,254

2002................... 315,350 59,651 312,512 2,008 98,657 79,356 16,710 20,371 686 905,301

2003................... 313,019 60,730 355,442 1,994 99,209 78,694 18,153 20,522 684 948,446

2004................... 313,020 59,119 371,011 2,296 99,628 77,641 18,717 20,764 746 962,942

2005................... 313,380 58,548 383,061 2,063 99,988 77,541 21,205 21,347 887 978,020

2006................... 312,956 58,097 388,294 2,256 100,334 77,821 24,113 21,461 882 986,215

2007................... 312,738 56,068 392,876 2,313 100,266 77,885 30,069 21,886 788 994,888 

2008................... 313,322 57,445 397,460R 1,995 100,755 77,930 38,466R 21,858 942 1,010,171

2009................... 314,294 56,781 401,272 1,932 101,004 78,518 48,552 22,160 888 1,025,400 

Electricity Generators, Electric Utilities

1998................... 299,739 62,704 130,404 55 97,070 75,525 2,067 18,898 229 686,692

1999................... 277,780 49,020 123,192 220 95,030 74,122 790 18,945 224 639,324

2000................... 260,990 41,032 123,665 57 85,968 73,738 837 18,020 13 604,319

2001................... 244,451 38,456 112,841 57 63,060 72,968 979 17,097 13 549,920

2002................... 244,056 33,876 127,692 61 63,202 73,391 989 17,807 -- 561,074

2003................... 236,473 32,570 125,612 61 60,964 72,827 925 17,803 13 547,249

2004................... 235,976 31,415 131,734 58 60,651 71,696 960 18,048 13 550,550

2005................... 229,705 30,867 147,752 -- 56,564 71,568 1,545 18,195 39 556,235 

2006................... 230,644 30,419 157,742 104 56,143 71,840 2,291 18,301 39 567,523 

2007................... 231,289 29,115 162,756 104 54,211 72,186 2,806 18,693 39 571,200

2008................... 231,857 30,657 173,106 -- 54,376 72,142 4,066 18,664 39 584,908

2009................... 234,397 30,174 180,571 -- 54,355 72,690 5,614 18,930 39 596,769

Electricity Generators, Independent Power Producers

1998................... 6,132 1,463 17,051 -- -- 2,454 6,955 620 -- 34,675

1999................... 27,725 8,508 38,553 -- 2,381 4,142 8,794 620 -- 90,724

2000................... 44,164 18,771 60,327 -- 11,892 4,509 8,994 1,502 -- 150,159

2001................... 60,701 25,311 102,693 -- 35,099 4,885 9,894 2,567 79 241,230

2002................... 61,770 23,664 140,404 9 35,455 4,911 10,390 2,564 80 279,246 

2003................... 66,538 26,028 178,624 6 38,244 5,058 11,786 2,719 46 329,049 

2004................... 67,242 25,918 190,855 8 38,978 5,274 12,070 2,717 46 343,106

2005................... 73,734 26,041 188,043 12 43,424 5,284 13,864 3,152 46 353,601

2006................... 72,730 25,384 184,196 20 44,190 5,263 15,865 3,160 46 350,854

2007................... 71,943 24,818 184,888 8 46,055 5,346 21,002 3,193 26 357,278

2008................... 71,864 24,823 179,169R -- 46,379 5,433 28,139R 3,193 46 359,044

2009................... 70,123 24,657 176,035 8 46,649 5,470 36,556 3,230 46 362,773

Combined Heat and Power, Electric Power

1998................... 5,021 800 19,632 -- -- -- 749 -- -- 26,202

1999................... 5,230 1,097 19,390 -- -- -- 741 -- -- 26,459

2000................... 5,044 907 20,704 262 -- -- 736 -- -- 27,653

2001................... 4,628 972 21,226 287 -- 1 498 -- 28 27,639 

2002................... 5,222 1,084 28,455 182 -- -- 555 -- -- 35,499

2003................... 5,534 1,051 34,895 185 -- 1 665 -- -- 42,332

2004................... 5,609 677 32,600 289 -- 1 555 -- -- 39,731

2005................... 5,560 530 31,740 289 -- 1 614 -- -- 38,735

2006................... 5,837 970 30,031 325 -- 1 628 -- -- 37,793

2007................... 5,885 907 29,468 339 -- -- 656 -- -- 37,254

2008................... 5,927 900 29,575 206 -- -- 701 -- -- 37,309

2009................... 5,940 897 28,875 206 -- -- 740 -- -- 36,658

Combined Heat and Power, Commercial9

1998................... 317 282 1,188 -- -- 32 463 -- -- 2,281

1999................... 317 381 1,106 -- -- 32 465 -- -- 2,302

2000................... 314 308 1,186 -- -- 33 399 -- -- 2,240

2001................... 295 299 1,950 -- -- 22 348 -- -- 2,912

2002................... 292 301 1,216 -- -- 22 357 -- -- 2,188

2003................... 347 343 994 -- -- 22 371 -- -- 2,077

2004................... 368 321 1,069 5 -- 22 404 -- -- 2,188

2005................... 397 333 1,024 5 -- 25 435 -- -- 2,219

2006................... 428 341 1,040 5 -- 25 433 -- -- 2,272

2007................... 428 348 1,064 5 -- 22 443 -- 3 2,312

2008................... 428 352 1,059 5 -- 22 444 -- 3 2,312

2009................... 424 348 1,105 5 -- 22 480 -- 3 2,386

Combined Heat and Power, Industrial9

1998................... 4,577 1,034 12,012 1,465 -- 1,139 5,210 -- 581 26,019

1999................... 4,443 1,062 12,877 1,689 -- 1,097 5,151 -- 799 27,119

2000................... 4,601 818 13,708 2,023 -- 1,079 4,607 -- 510 27,348

2001................... 4,156 1,124 14,123 1,327 -- 1,041 4,382 -- 399 26,553

2002................... 4,010 726 14,745 1,756 -- 1,033 4,419 -- 607 27,295

2003................... 4,127 738 15,316 1,742 -- 786 4,406 -- 625 27,740

2004................... 3,825 789 14,753 1,937 -- 648 4,728 -- 687 27,367

2005................... 3,984 777 14,501 1,757 -- 662 4,747 -- 802 27,230

2006................... 3,317 983 15,285 1,802 -- 693 4,896 -- 797 27,773

2007................... 3,194 880 14,699 1,858 -- 331 5,163 -- 720 26,844

2008................... 3,246 713 14,551 1,784 -- 334 5,116 -- 854 26,599

2009................... 3,412 704 14,686 1,714 -- 337 5,162 -- 800 26,815



1 Anthracite, bituminous coal, subbituminous coal, lignite, and waste coal.

2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Includes a small number of generators for which waste heat is the primary energy source.

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 5 Conventional hydroelectric power excluding pumped storage facilities.

6

 Wood, black liquor, other wood waste, municipal solid waste, landfill gas, sludge waste, agriculture byproducts, other biomass, geothermal, solar thermal, photovoltaic energy, and wind. 7 Pumped storage capacity generates electricity from water pumped to an elevated reservoir and then released through a conduit to turbine generators located at a lower level. 8 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies.

9 Small number of electricity-only, non-Combined Heat and Power plants may be included.

R = Revised. 

Notes: • See Glossary reference for definitions. • Capacity by energy source is based on the capacity associated with the energy source reported as the most predominant (primary) one, 

where more than one energy source is associated with a generator. • Totals may not equal sum of components because of independent rounding.
U.S. Energy Information Administration/Electric Power Annual 2009 15

Figure 1.1. U.S. Electric Industry Generating Capacity by State, 2009
16 U.S. Energy Information Administration/Electric Power Annual 2009

Table 1.1.A. Existing Net Summer Capacity of Other Renewables by Producer Type, 1998 through 2009

(Megawatts)

Period Wind

Solar Thermal

and Photovoltaic

Wood and WoodDerived Fuels1 Geothermal

Other

Biomass2

Total 

(Other Renewables)

Total (All Sectors)

1998.................................. 1,720 335 6,802 2,893 3,694 15,444

1999.................................. 2,252 389 6,795 2,846 3,660 15,942

2000.................................. 2,377 386 6,147 2,793 3,869 15,572

2001.................................. 3,864 392 5,882 2,216 3,748 16,101

2002.................................. 4,417 397 5,844 2,252 3,800 16,710

2003.................................. 5,995 397 5,871 2,133 3,758 18,153

2004.................................. 6,456 398 6,182 2,152 3,529 18,717

2005.................................. 8,706 411 6,193 2,285 3,609 21,205

2006.................................. 11,329 411 6,372 2,274 3,727 24,113

2007.................................. 16,515 502 6,704 2,214 4,134 30,069

2008.................................. 24,651 536 6,864 2,229R 4,186 38,466R

2009.................................. 34,296 619 6,939 2,382 4,317 48,552

Electricity Generators, Electric Utilities

1998.................................. 9 5 268 1,550 236 2,067

1999.................................. 29 5 240 273 243 790

2000.................................. 54 5 259 273 247 837

2001.................................. 60 4 309 271 335 979

2002.................................. 111 9 248 271 350 989

2003.................................. 140 9 268 162 346 925

2004.................................. 326 10 313 152 160 960

2005.................................. 765 11 391 242 136 1,545

2006.................................. 1,441 11 428 240 172 2,291

2007.................................. 1,928 12 418 158 290 2,806

2008.................................. 3,190 14 427 159 276 4,066

2009.................................. 4,655 42 431 159 327 5,614

Electricity Generators, Independent Power Producers

1998.................................. 1,711 330 1,170 1,344 2,400 6,955

1999.................................. 2,222 385 1,244 2,573 2,370 8,794

2000.................................. 2,323 382 1,227 2,520 2,543 8,994 

2001.................................. 3,804 388 1,178 1,945 2,580 9,894

2002.................................. 4,305 388 1,162 1,981 2,553 10,390

2003.................................. 5,855 388 1,121 1,972 2,450 11,786

2004.................................. 6,130 388 1,138 2,000 2,414 12,070

2005.................................. 7,941 400 1,033 2,044 2,447 13,864

2006.................................. 9,888 400 1,037 2,034 2,505 15,865

2007.................................. 14,587 489 1,066 2,056 2,803 21,002

2008.................................. 21,461 521 1,196 2,070R 2,891 28,139R

2009.................................. 29,640 575 1,220 2,223 2,898 36,556

Combined Heat and Power, Electric Power

1998.................................. -- -- 356 -- 393 749

1999.................................. -- -- 354 -- 387 741

2000.................................. -- -- 242 -- 494 736

2001.................................. -- -- 144 -- 354 498

2002.................................. -- -- 144 -- 411 555

2003.................................. -- -- 204 -- 461 665

2004.................................. -- -- 179 -- 375 555

2005.................................. -- -- 218 -- 395 614

2006.................................. -- -- 212 -- 416 628

2007.................................. -- -- 210 -- 446 656

2008.................................. -- -- 223 -- 478 701

2009.................................. -- -- 237 -- 503 740

Combined Heat and Power, Commercial3

1998.................................. -- -- 7 -- 456 463

1999.................................. -- -- 7 -- 459 465

2000.................................. -- -- 7 -- 392 399

2001.................................. -- -- 6 -- 342 348

2002.................................. -- -- 6 -- 351 357

2003.................................. -- -- 7 -- 364 371

2004.................................. -- -- 7 -- 397 404

2005.................................. -- -- 7 -- 428 435

2006.................................. -- -- 7 -- 426 433

2007.................................. -- -- 8 -- 435 443

2008.................................. -- * 8 -- 436 444

2009.................................. 1 * 8 -- 471 480

Combined Heat and Power, Industrial3

1998.................................. -- -- 5,001 -- 209 5,210

1999.................................. -- -- 4,950 -- 201 5,151

2000.................................. -- -- 4,413 -- 194 4,607

2001.................................. -- -- 4,245 -- 138 4,382

2002.................................. -- -- 4,285 -- 134 4,419

2003.................................. -- -- 4,271 -- 136 4,406

2004.................................. -- -- 4,545 -- 183 4,728

2005.................................. -- -- 4,545 -- 202 4,747

2006.................................. -- -- 4,688 -- 208 4,896

2007.................................. -- 1 5,002 -- 160 5,163

2008.................................. -- 1 5,010 -- 105 5,116

2009.................................. -- 1 5,043 -- 118 5,162



1 Wood/wood waste solids (including paper pellets, railroad ties, utility poles, wood chips, bark, and wood waste solids), wood waste liquids (red liquor, sludge wood, spent sulfite liquor, 

and other wood-based liquids), and black liquor.

2 Municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, methane, and 

other biomass gases).

3 Small number of electricity-only, non-Combined Heat and Power plants may be included.

* = Value is less than half of the smallest unit of measure.

R = Revised. 

Notes: • See Glossary reference for definitions. • Totals may not equal sum of components because of independent rounding. • Capacity by energy source is based on the capacity 

associated with the energy source reported as the most predominant (primary) one, where more than one energy source is associated with a generator.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
U.S. Energy Information Administration/Electric Power Annual 2009 17

Table 1.2. Existing Capacity by Energy Source, 2009 

(Megawatts)

Energy Source Number of 

Generators

Generator 

Nameplate Capacity 

Net Summer 

Capacity

Net Winter 

Capacity

Coal1............................................ 1,436 338,723 314,294 316,363

Petroleum2 ................................... 3,757 63,254 56,781 60,878

Natural Gas3

................................. 5,470 459,803 401,272 432,309

Other Gases4 ................................ 98 2,218 1,932 1,899

Nuclear ........................................ 104 106,618 101,004 102,489

Hydroelectric Conventional5 ........ 4,005 77,910 78,518 78,127

Wind............................................ 620 34,683 34,296 34,350

Solar Thermal and Photovoltaic ... 110 640 619 537

Wood and Wood Derived Fuels6

.. 353 7,829 6,939 6,992

Geothermal .................................. 222 3,421 2,382 2,561

Other Biomass7 ............................ 1,502 5,007 4,317 4,382

Pumped Storage ........................... 151 20,538 22,160 22,063

Other8 .......................................... 48 1,042 888 900

Total...................................... 17,876 1,121,686 1,025,400 1,063,848

1 Anthracite, bituminous coal, subbituminous coal, lignite, and waste coal.

2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Includes a small number of generators for which waste heat is the primary energy source.

4 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 5 The net summer capacity and/or the net winter capacity may exceed nameplate capacity due to upgrades to and overload capability of hydroelectric generators. 6 Wood/wood waste solids (including paper pellets, railroad ties, utility poles, wood chips, bark, and wood waste solids), wood waste liquids (red liquor, sludge wood, spent sulfite liquor, 

and other wood-based liquids), and black liquor.

7 Municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, methane, and

other biomass gases).

8 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies.

Notes: • Capacity by energy source is based on the capacity associated with the energy source reported as the most predominant (primary) one, where more than one energy source is 

associated with a generator. • Totals may not equal sum of components because of independent rounding. • In some reporting of capacity data, such as for wind, solar and wave energy 

sites, the capacity for multiple generators is reported in a single generator record and is presented as a single generator in the count of number of generators.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."

Table 1.3. Existing Capacity by Producer Type, 2009 

(Megawatts)

Producer Type Number of 

Generators

Generator Nameplate 

Capacity

Net Summer 

Capacity

Net Winter 

Capacity

Electric Power Sector

Electric Utilities............................................................................ 9,428 646,984 596,769 615,483

Independent Power Producers....................................................... 5,531 399,030 362,773 377,974

Total................................................................................... 14,959 1,046,014 959,542 993,457

Combined Heat and Power Sector

Electric Power1 ............................................................................. 645 42,235 36,658 39,623

Commercial2 ................................................................................. 649 2,676 2,386 2,478

Industrial2 ..................................................................................... 1,623 30,761 26,815 28,290

Total................................................................................... 2,917 75,672 65,858 70,391

Total All Sectors............................................................................... 17,876 1,121,686 1,025,400 1,063,848 

1 Includes only independent power producers` combined heat and power facilities.

2 Small number of electricity-only, non-Combined Heat and Power plants may be included.

Notes: • See Glossary reference for definitions. • Totals may not equal sum of components because of independent rounding. • In some reporting of capacity data, such as for wind, solar 

and wave energy sites, the capacity for multiple generators is reported in a single generator record and is presented as a single generator in the count of number of generators.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
18 U.S. Energy Information Administration/Electric Power Annual 2009

Table 1.4. Planned Generating Capacity Additions from New Generators, by Energy Source, 2010-

2014

(Count, Megawatts) 

Energy Source Number of Generators Generator Nameplate Capacity Net Summer Capacity Net Winter Capacity

2010

U.S. Total......................................... 426 25,520 23,523 24,407

Coal1

................................................ 13 8,102 7,414 7,479

Petroleum2 ....................................... 29 1,245 1,110 1,174

Natural Gas...................................... 110 9,488 8,361 9,107

Other Gases3

.................................... 3 117 117 117

Nuclear ............................................ -- -- -- --

Hydroelectric Conventional4

............ 9 21 21 21

Wind................................................ 80 5,780 5,775 5,776

Solar Thermal and Photovoltaic....... 87 510 507 507

Wood and Wood Derived Fuels5

...... 3 80 67 67

Geothermal...................................... 7 39 21 25

Other Biomass6

................................ 85 138 129 133

Pumped Storage............................... -- -- -- -- Other7 .............................................. -- -- -- --

2011

U.S. Total......................................... 238 19,362 18,057 18,512

Coal1

................................................ 6 2,534 2,397 2,397

Petroleum2 ....................................... 10 213 206 209

Natural Gas...................................... 80 11,510 10,391 10,844

Other Gases3 .................................... 1 4 3 3

Nuclear ............................................ -- -- -- --

Hydroelectric Conventional4

............ 5 8 8 8

Wind................................................ 43 3,949 3,931 3,931

Solar Thermal and Photovoltaic....... 66 950 942 943

Wood and Wood Derived Fuels5

...... 5 167 152 150

Geothermal...................................... -- -- -- -- Other Biomass6

................................ 22 27 27 27

Pumped Storage............................... -- -- -- --

Other7 .............................................. -- -- -- -- 2012

U.S. Total......................................... 117 19,814 18,521 19,171

Coal1

................................................ 11 6,169 5,643 5,736

Petroleum2 ....................................... 3 52 42 50

Natural Gas...................................... 56 9,713 9,171 9,668

Other Gases3 .................................... 2 41 41 41

Nuclear ............................................ 1 1,270 1,122 1,164

Hydroelectric Conventional4

............ 3 125 116 116

Wind................................................ 6 1,138 1,138 1,138

Solar Thermal and Photovoltaic....... 21 857 851 851

Wood and Wood Derived Fuels5

...... 6 258 224 236

Geothermal...................................... -- -- -- -- Other Biomass6

................................ 8 192 173 173

Pumped Storage............................... -- -- -- -- Other7 .............................................. -- -- -- --

2013

U.S. Total......................................... 59 8,118 7,127 7,694

Coal1

................................................ 1 290 290 290

Petroleum2 ....................................... -- -- -- -- Natural Gas...................................... 29 5,417 4,649 5,224

Other Gases3 .................................... -- -- -- -- Nuclear ............................................ -- -- -- --

Hydroelectric Conventional4

............ 8 270 270 270

Wind................................................ 4 415 415 415

Solar Thermal and Photovoltaic....... 7 1,123 982 972

Wood and Wood Derived Fuels5

...... 3 202 181 181

Geothermal...................................... 5 185 160 162

Other Biomass6

................................ 2 217 181 181

Pumped Storage............................... -- -- -- -- Other7 .............................................. -- -- -- --

2014

U.S. Total......................................... 34 5,582 4,929 5,137

Coal1

................................................ 4 1,020 941 948

Petroleum2 ....................................... -- -- -- -- Natural Gas...................................... 19 2,501 2,256 2,454

Other Gases3 .................................... 3 840 593 596

Nuclear ............................................ -- -- -- --

Hydroelectric Conventional4

............ 3 34 34 34

Wind................................................ 1 300 300 300

Solar Thermal and Photovoltaic....... 4 888 805 805

Wood and Wood Derived Fuels5

...... -- -- -- -- Geothermal...................................... -- -- -- -- Other Biomass6

................................ -- -- -- -- Pumped Storage............................... -- -- -- -- Other7 .............................................. -- -- -- --

1 Anthracite, bituminous coal, subbituminous coal, lignite, and waste coal.

2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 4 Conventional hydroelectric power excluding pumped storage facilities; includes ocean power technology (wave energy).

5 Wood/wood waste solids (including paper pellets, railroad ties, utility poles, wood chips, bark, and wood waste solids), wood waste liquids (red liquor, sludge wood, spent sulfite liquor, 

and other wood-based liquids), and black liquor.

6 Municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, methane, and 

other biomass gases).

7 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies.

Notes: • Projected data are updated annually, so revision superscript is not used. • Capacity by energy source is based on the capacity associated with the energy source reported as the 

most predominant (primary) one, where more than one energy source is associated with a generator. These data reflect plans as of December 31, 2009. • Totals may not equal sum of 

components because of independent rounding. • In some reporting of capacity data, such as for wind, solar and wave energy sites, the capacity for multiple generators is reported in a single 

generator record and is presented as a single generator in the count of number of generators.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
U.S. Energy Information Administration/Electric Power Annual 2009 19

Table 1.5. Capacity Additions, Retirements and Changes by Energy Source, 2009 

(Count, Megawatts) 

Energy Source

Generator Additions Generator Retirements Updates and Revisions1

Number 

of 

Generators

Generator 

Nameplate 

Capacity 

Net 

Summer 

Capacity 

Net Winter 

Capacity

Number 

of 

Generators

Generator 

Nameplate 

Capacity

Net 

Summer 

Capacity

Net 

Winter 

Capacity

Generator 

Nameplate 

Capacity

Net 

Summer 

Capacity

Net Winter 

Capacity

Coal2....................... 13 2,021 1,793 1,793 12 537 529 528 -61 -291 -363 

Petroleum3 .............. 25 93 48 83 41 623 540 567 128 -172 -175

Natural Gas4

............ 76 10,760 9,403 10,170 79 5,940 5,634 5,657 335 43 67

Other Gases5 ........... -- -- -- -- 3 51 46 46 7 -17 -13 

Nuclear ................... -- -- -- -- -- -- -- -- 471 249 -5

Hydroelectric 

Conventional........... 8 26 26 26 5 14 3 4 166 565 410

Wind ...................... 120 9,581 9,410 9,443 1 2 2 2 125 236 210 

Solar Thermal and 

Photovoltaic............ 20 88 82 80 -- -- -- -- 13 1 1

Wood and Wood 

Derived Fuels6 ........ 3 99 89 89 4 22 21 21 22 7 20

Geothermal ............. 13 199 164 193 14 21 9 14 -- -2 -2

Other Biomass7 ....... 104 278 264 261 13 39 32 32 -86 -102 -110

Pumped Storage ...... -- -- -- -- -- -- -- -- 184 303 295 

Other8 ..................... -- -- -- -- -- -- -- -- 1 -54 -68

Total ................. 382 23,144 21,279 22,138 172 7,249 6,815 6,870 1,305 765 267 

1 Generator re-ratings, re-powering, and revisions/corrections to previously reported data.

2 Anthracite, bituminous coal, subbituminous coal, lignite, and waste coal.

3 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

4 Includes a small number of generators for which waste heat is the primary energy source.

5 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 6 Wood/wood waste solids (including paper pellets, railroad ties, utility poles, wood chips, bark, and wood waste solids), wood waste liquids (red liquor, sludge wood, spent sulfite liquor, 

and other wood-based liquids), and black liquor.

7 Municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, methane, and 

other biomass gases).

8 Batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies.

Notes: • Capacity by energy source is based on the capacity associated with the energy source reported as the most predominant (primary) one, where more than one energy source is 

associated with a generator. • Totals may not equal sum of components because of independent rounding. • In some reporting of capacity data, such as for wind, solar and wave energy 

sites, the capacity for multiple generators is reported in a single generator record and is presented as a single generator in the count of number of generators.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
20 U.S. Energy Information Administration/Electric Power Annual 2009

Table 1.6.A. Capacity of Dispersed Generators by Technology Type, 2004 through 2009 

(Count, Megawatts) 

Period

Internal 

Combustion

(MW)

Combustion 

Turbine

(MW)

Steam Turbine

(MW)

Hydroelectric

(MW)

Wind and Other

(MW)

Total

Number of 

Generators (MW)

2004............................. 3,366 210 552 26 2 11,123 4,156

2005............................. 4,290 335 126 2 13 11,373 4,766

2006............................. 6,524 346 157 3 8 9,536 7,037

2007............................. 7,866 268 102 31 30 11,057 8,297

2008............................. 9,335 86 248 34 70 12,262 9,773

2009............................. 9,751 329 204 81 108 13,928 10,475

Note: Dispersed generators are commercial and industrial generators which are not connected to the grid. They may be installed at or near a customer`s site, or at other locations. They 

may be owned by either the customers of the distribution utility or by the utility. Other includes generators for which technology is not specified.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 1.6.B. Capacity of Distributed Generators by Technology Type, 2004 through 2009 

(Count, Megawatts) 

Period

Internal 

Combustion

(MW)

Combustion 

Turbine

(MW)

Steam Turbine

(MW)

Hydroelectric

(MW)

Wind and Other

(MW)

Total

Number of 

Generators (MW)

2004............................. 2,168 1,028 1,085 1,004 138 5,863 5,423

20051 ........................... 4,025 1,917 1,830 999 995 17,371 9,766

2006............................. 3,646 1,298 2,582 806 1,081 5,044 9,411

2007............................. 4,624 1,990 3,596 1,051 1,441 7,103 12,702

2008............................. 5,112 1,949 3,060 1,154 1,588 9,591 12,863

2009............................. 4,339 4,147 4,621 1,166 1,729 13,006 16,002

1 Distributed generator data in 2005 include a significant number of generators reported by one respondent, which may be for residential applications.

Note: Distributed generators are commercial and industrial generators which are connected to the grid. They may be installed at or near a customer`s site, or at other locations. They may 

be owned by either the customers of the distribution utility or by the utility. Other includes generators for which technology is not specified.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 1.6.C. Total Capacity of Dispersed and Distributed Generators by Technology Type, 2004 

through 2009 

(Count, Megawatts) 

Period

Internal 

Combustion

(MW)

Combustion 

Turbine

(MW)

Steam Turbine

(MW)

Hydroelectric

(MW)

Wind and Other

(MW)

Total

Number of 

Generators (MW)

2004............................. 5,534 1,238 1,637 1,030 140 16,986 9,579

20051 ........................... 8,315 2,252 1,956 1,001 1,008 28,744 14,532

2006............................. 10,169 1,644 2,739 809 1,088 14,580 16,448

2007............................. 12,490 2,258 3,698 1,082 1,471 18,160 20,999

2008............................. 14,447 2,035 3,308 1,188 1,658 21,853 22,636

2009............................. 14,090 4,476 4,825 1,248 1,838 26,934 26,477

1 Distributed generator data in 2005 include a significant number of generators reported by one respondent, which may be for residential applications.

Note: Dispersed and distributed generators are commercial and industrial generators. Dispersed generators are not connected to the grid. Distributed generators are connected to the grid. 

Both types of generators may be installed at or near a customer`s site, or at other locations, and both types of generators may be owned by either the customers of the distribution utility or 

by the utility. Other includes generators for which technology is not specified.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
U.S. Energy Information Administration/Electric Power Annual 2009 21

Table 1.7. Fuel Switching Capacity of Operable Generators Reporting Natural Gas as the Primary 

Fuel, by Producer Type, 2009 

(Megawatts, Percent)

Producer Type

Total Net Summer 

Capacity of All 

Generators 

Reporting Natural 

Gas as the Primary 

Fuel

Fuel-Switchable Part of Total

Net Summer 

Capacity of 

Natural Gas-Fired 

Generators 

Reporting the 

Ability to Switch to 

Petroleum Liquids1

Fuel Switchable 

Capacity as 

Percent of Total

Maximum 

Achievable Net 

Summer Capacity 

Using Petroleum 

Liquids

Fuel Switchable 

Net Summer 

Capacity Reported 

to Have No Factors 

that Limit the 

Ability to Switch to 

Petroleum Liquids

Electric Utility................................................ 180,571 76,700 42.5 75,023 26,360

Independent Power Producers ........................ 176,035 40,395 22.9 39,545 11,176

Combined Heat and Power, Electric Power2

... 28,875 5,961 20.6 5,759 572

Electric Power Sector Subtotal.................... 385,481 123,056 31.9 120,327 38,108 

Combined Heat and Power, Commercial3 ...... 1,105 532 48.2 526 139

Combined Heat and Power, Industrial3

........... 14,686 1,263 8.6 1,207 270

All Sectors..................................................... 401,272 124,851 31.1 122,060 38,517

 1 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, and waste oil. 2 Electric Utility CHP plants are included in Electric Utilities.

3 Small number of electricity-only, non-Combined Heat and Power plants may be included.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."

Table 1.8. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum 

Liquids by Type of Prime Mover, 2009 

(Megawatts, Percent)

Producer Type

Total Net Summer 

Capacity of All Generators 

Reporting Petroleum as the 

Primary Fuel1

Fuel-Switchable Part of Total

Net Summer Capacity 

of Petroleum-Fired 

Generators Reporting 

the Ability to Switch to 

Natural Gas

Fuel Switchable 

Capacity as Percent of 

Total

Maximum Achievable 

Net Summer Capacity 

Using Natural Gas

Electric Utility................................................ 30,174 11,117 36.8 10,654

Independent Power Producers ........................ 24,657 12,115 49.1 10,270

Combined Heat and Power Electric Power2 ... 897 445 49.6 195

Electric Power Sector Subtotal.................... 55,728 23,677 42.5 21,119

Combined Heat and Power Commercial3 ....... 348 19 5.6 19

Combined Heat and Power Industrial3

............ 704 59 8.3 39

All Sectors..................................................... 56,781 23,755 41.8 21,177  1 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, and waste oil. 2 Electric Utility CHP plants are included in Electric Utilities.

3 Small number of electricity-only, non-Combined Heat and Power plants may be included.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
22 U.S. Energy Information Administration/Electric Power Annual 2009

Table 1.9. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum 

Liquids by Type of Prime Mover, 2009 

(Count, Megawatts) 

Prime Mover Type Number of 

Generators Net Summer Capacity

Fuel Switchable Net Summer 

Capacity Reported to Have No 

Factors that Limit the Ability 

to Switch to Petroleum 

Liquids1

Steam Generator ............................................................. 205 28,193 16,642

Combined Cycle ............................................................. 396 41,055 6,820

Internal Combustion........................................................ 332 922 349

Gas Turbine .................................................................... 933 54,680 14,707

All Fuel Switchable Prime Movers.................................. 1,866 124,851 38,517

1  Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, and waste oil.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."

Table 1.10. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum 

Liquids, by Year of Initial Commercial Operation, 2009 

(Count, Megawatts) 

Year of Initial Commercial Operation Number of 

Generators Net Summer Capacity

Fuel Switchable Net Summer 

Capacity Reported to Have No 

Factors that Limit the Ability 

to Switch to Petroleum 

Liquids1

pre-1970.......................................................................... 377 15,505 9,610

1970-1974....................................................................... 391 17,976 9,668

1975-1979....................................................................... 105 9,889 5,574

1980-1984....................................................................... 47 943 213

1985-1989....................................................................... 111 3,317 493

1990-1994....................................................................... 215 12,987 2,259

1995-1999....................................................................... 134 10,023 2,288

2000-2004....................................................................... 381 39,773 6,345

2005-2009....................................................................... 105 14,439 2,067

Total................................................................................ 1,866 124,851 38,517

 1 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, and waste oil.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
U.S. Energy Information Administration/Electric Power Annual 2009 23

Table 1.11. Interconnection Cost and Capacity for New Generators, by Producer Type, 2008 and 2009 

Sector Units1 Nameplate Capacity

(megawatts)1

Cost

(thousand dollars)1

2008

Total .................................................... 433R 19,062R 523,846

Electric Utilities2

.................................. 123R 8,831R 185,955

Independent Power Producers3

............. 293R 10,212R 337,145

Commercial4 ........................................ 16R 16R 745

Industrial4

............................................. 1 3 1

2009

Total .................................................... 382 23,144 819,680

Electric Utilities2

.................................. 106 10,939 237,751

Independent Power Producers3

............. 244 11,590 561,057

Commercial4 ........................................ 20 58 10,587

Industrial4

............................................. 12 557 10,285

1 Cost is the total cost incurred for the direct, physical interconnection of generators that started commercial operation in the respective years. These generator-specific costs may include 

costs for transmission or distribution lines, transformers, protective devices, substations, switching stations and other equipment necessary for interconnection. Units and Nameplate 

Capacity represent the number of units and associated capacity for which interconnection costs were incurred and reported.

2 Electric utility CHP plants are included in Electric Generators, Electric Utilities.

3 Includes only independent power producers` combined heat and power facilities.

4 Small number of electricity-only, non-Combined Heat and Power plants may be included.

R = Revised. 

Notes: • See Glossary reference for definitions. • Totals may not equal sum of components because of independent rounding. • In some reporting of capacity data, such as for wind, solar 

and wave energy sites, the capacity for multiple generators is reported in a single generator record and is presented as a single generator in the count of number of generators.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
24 U.S. Energy Information Administration/Electric Power Annual 2009

Table 1.12. Interconnection Cost and Capacity for New Generators, by Grid Voltage Class, 2008 and 

2009

Voltage Class Units1 Nameplate Capacity

(megawatts)1

Cost

(thousand dollars)1

2008

Total .................................................... 433R 19,062R 523,846

Distribution (< 35 kV) ......................... 153R 540R 25,198

SubTransmission (35 kV - 138 kV) ..... 185R 7,090R 181,061

Transmission (> 138 kV) ..................... 95R 11,432R 317,587

2009

Total .................................................... 382 23,144 819,680

Distribution (< 35 kV) ......................... 147 464 36,927

SubTransmission (35 kV - 138 kV) ..... 131 6,423 315,874

Transmission (> 138 kV) ..................... 104 16,257 466,879

1 Cost is the total cost incurred for the direct, physical interconnection of generators that started commercial operation in the respective years. These generator-specific costs may include 

costs for transmission or distribution lines, transformers, protective devices, substations, switching stations and other equipment necessary for interconnection. Units and Nameplate 

Capacity represent the number of units and associated capacity for which interconnection costs were incurred and reported.

R = Revised. 

Notes: • See Glossary reference for definitions. • Totals may not equal sum of components because of independent rounding. • In some reporting of capacity data, such as for wind, solar 

and wave energy sites, the capacity for multiple generators is reported in a single generator record and is presented as a single generator in the count of number of generators.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
U.S. Energy Information Administration/Electric Power Annual 2009 25

Chapter 2. Generation and Useful Thermal Output
26 U.S. Energy Information Administration/Electric Power Annual 2009

Table 2.1. Net Generation by Energy Source by Type of Producer, 1998 through 2009

(Thousand Megawatthours)

Period Coal1 Petroleum 2 Natural 

Gas

Other 

Gases3 Nuclear Hydroelectric 

Conventional4

Other 

Renewables5

Hydroelectric 

Pumped 

Storage6

Other7 Total

Total (All Sectors)

1998................... 1,873,516 128,800 531,257 13,492 673,702 323,336 77,088 -4,467 3,571 3,620,295

1999................... 1,881,087 118,061 556,396 14,126 728,254 319,536 79,423 -6,097 4,024 3,694,810

2000................... 1,966,265 111,221 601,038 13,955 753,893 275,573 80,906 -5,539 4,794 3,802,105

2001................... 1,903,956 124,880 639,129 9,039 768,826 216,961 70,769 -8,823 11,906 3,736,644

2002................... 1,933,130 94,567 691,006 11,463 780,064 264,329 79,109 -8,743 13,527 3,858,452

2003................... 1,973,737 119,406 649,908 15,600 763,733 275,806 79,487 -8,535 14,045 3,883,185

2004................... 1,978,301 121,145 710,100 15,252 788,528 268,417 83,067 -8,488 14,232 3,970,555 

2005................... 2,012,873 122,225 760,960 13,464 781,986 270,321 87,329 -6,558 12,821 4,055,423

2006................... 1,990,511 64,166 816,441 14,177 787,219 289,246 96,525 -6,558 12,974 4,064,702

2007................... 2,016,456 65,739 896,590 13,453 806,425 247,510 105,238 -6,896 12,231 4,156,745

2008................... 1,985,801 46,243 882,981 11,707 806,208 254,831 126,101R -6,288 11,804R 4,119,388

2009................... 1,755,904 38,938 920,797 10,629 798,855 273,445 143,824 -4,627 11,929 3,949,694

Electricity Generators, Electric Utilities

1998................... 1,807,480 110,158 309,222 -- 673,702 308,844 7,206 -4,441 -- 3,212,171

1999................... 1,767,679 86,929 296,381 -- 725,036 299,914 3,716 -5,982 -- 3,173,674

2000................... 1,696,619 72,180 290,715 -- 705,433 253,155 2,241 -4,960 -- 3,015,383

2001................... 1,560,146 78,908 264,434 -- 534,207 197,804 1,666 -7,704 486 2,629,946

2002................... 1,514,670 59,125 229,639 206 507,380 242,302 3,089 -7,434 480 2,549,457

2003................... 1,500,281 69,930 186,967 243 458,829 249,622 3,421 -7,532 519 2,462,281

2004................... 1,513,641 73,694 199,662 374 475,682 245,546 3,692 -7,526 467 2,505,231 

2005................... 1,484,855 69,722 238,204 10 436,296 245,553 4,945 -5,383 643 2,474,846

2006................... 1,471,421 40,903 282,088 30 425,341 261,864 6,588 -5,281 700 2,483,656

2007................... 1,490,985 40,719 313,785 141 427,555 226,734 8,953 -5,328 586 2,504,131

2008................... 1,466,395 28,124 320,190 46 424,256 229,645 11,308 -5,143 545 2,475,367

2009................... 1,322,092 25,217 349,166 96 417,275 247,198 14,617 -3,369 483 2,372,776

Electricity Generators, Independent Power Producers

1998................... 15,539 5,503 26,657 55 -- 9,023 34,703 -26 -- 91,455

1999................... 64,387 17,906 60,264 36 3,218 14,749 40,460 -115 -- 200,905

2000................... 213,956 25,795 108,712 181 48,460 18,183 42,831 -579 -- 457,540

2001................... 291,678 34,257 162,540 10 234,619 15,945 37,200 -1,119 5,460 780,592

2002................... 366,535 24,150 227,155 29 272,684 18,189 40,729 -1,309 7,168 955,331

2003................... 415,498 38,571 234,240 13 304,904 21,890 42,058 -1,003 7,035 1,063,205

2004................... 407,418 35,665 291,527 7 312,846 19,518 45,743 -962 7,108 1,118,870

2005................... 470,658 41,485 314,970 3 345,690 21,477 48,294 -1,174 5,569 1,246,971

2006................... 462,302 14,340 335,898 3 361,877 24,383 55,890 -1,277 5,646 1,259,062

2007................... 470,978 16,189 372,523 3 378,869 19,103 62,301 -1,569 5,458 1,323,856

2008................... 465,558 11,145 363,138 1 381,952 23,444 82,358R -1,145 5,616R 1,332,068

2009................... 389,783 6,689 373,448 1 381,579 24,304 97,928 -1,259 5,341 1,277,815

Combined Heat and Power, Electric Power8

1998................... 27,174 6,550 113,413 2,260 -- -- 4,234 -- 159 153,790

1999................... 26,551 6,704 116,351 1,571 -- -- 4,088 -- 139 155,404

2000................... 32,536 7,217 118,551 1,847 -- -- 4,330 -- 125 164,606

2001................... 31,003 5,984 127,966 576 -- -- 3,393 -- 595 169,515

2002................... 29,408 6,458 150,889 1,734 -- -- 3,737 -- 1,444 193,670

2003................... 36,935 5,195 146,097 2,392 -- -- 4,002 -- 1,053 195,674

2004................... 36,128 5,320 135,983 3,187 -- -- 2,893 -- 747 184,259

2005................... 36,541 5,275 130,655 3,765 -- 10 3,415 -- 716 180,375

2006................... 36,014 4,465 116,430 4,220 -- 8 3,456 -- 766 165,359

2007................... 36,428 4,398 128,444 3,898 -- 6 3,450 -- 733 177,356

2008................... 36,884 3,612 119,043 3,153 -- 6 3,417 -- 798 166,915

2009................... 29,248 3,910 118,286 2,958 -- 4 3,932 -- 808 159,146

Combined Heat and Power, Commercial9

1998................... 985 383 4,879 7 -- 120 2,373 -- -- 8,748

1999................... 995 434 4,607 * -- 115 2,412 -- * 8,563

2000................... 1,097 432 4,262 * -- 100 2,012 -- * 7,903

2001................... 995 438 4,434 * -- 66 1,025 -- 457 7,416

2002................... 992 431 4,310 * -- 13 1,065 -- 603 7,415

2003................... 1,206 423 3,899 -- -- 72 1,302 -- 594 7,496

2004................... 1,340 499 3,969 -- -- 105 1,575 -- 781 8,270

2005................... 1,353 375 4,249 -- -- 86 1,673 -- 756 8,492 

2006................... 1,310 235 4,355 * -- 93 1,619 -- 758 8,371

2007................... 1,371 189 4,257 -- -- 77 1,614 -- 764 8,273

2008................... 1,261 142 4,188 -- -- 60 1,555 -- 720 7,926

2009................... 1,096 163 4,225 -- -- 71 1,769 -- 842 8,165

Combined Heat and Power, Industrial9

1998................... 22,337 6,206 77,085 11,170 -- 5,349 28,572 -- 3,412 154,132

1999................... 21,474 6,088 78,793 12,519 -- 4,758 28,747 -- 3,885 156,264 

2000................... 22,056 5,597 78,798 11,927 -- 4,135 29,491 -- 4,669 156,673

2001................... 20,135 5,293 79,755 8,454 -- 3,145 27,485 -- 4,908 149,175

2002................... 21,525 4,403 79,013 9,493 -- 3,825 30,489 -- 3,832 152,580

2003................... 19,817 5,285 78,705 12,953 -- 4,222 28,704 -- 4,843 154,530

2004................... 19,773 5,967 78,959 11,684 -- 3,248 29,164 -- 5,129 153,925

2005................... 19,466 5,368 72,882 9,687 -- 3,195 29,003 -- 5,137 144,739 

2006................... 19,464 4,223 77,669 9,923 -- 2,899 28,972 -- 5,103 148,254

2007................... 16,694 4,243 77,580 9,411 -- 1,590 28,919 -- 4,690 143,128

2008................... 15,703 3,219 76,421 8,507 -- 1,676 27,462 -- 4,125 137,113

2009................... 13,686 2,960 75,672 7,574 -- 1,868 25,578 -- 4,455 131,793



1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 4 Conventional hydroelectric power excluding pumped storage facilities.

5 Other renewables represents the summation of the sub-categories of Wind, Solar Thermal and Photovoltaic, Wood and Wood Derived Fuels, Geothermal, and Other Biomass. 6 The quantity of output from a hydroelectric pumped storage facility represents production minus energy used for pumping.

7

 Non-biogenic municipal solid waste, batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies. 8 Electric utility CHP plants are included in Electricity Generators, Electric Utilities.

9 Small number of electricity-only, non-Combined Heat and Power plants may be included.

* = Value is less than half of the smallest unit of measure.

R = Revised. 

Note: Totals may not equal sum of components because of independent rounding

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report.
U.S. Energy Information Administration/Electric Power Annual 2009 27

Figure 2.1. U.S. Electric Industry Net Generation by State, 2009
28 U.S. Energy Information Administration/Electric Power Annual 2009

Table 2.1.A. Net Generation by Selected Renewables by Type of Producer, 1998 through 2009

(Thousand Megawatthours)

Period Wind

Solar Thermal

and Photovoltaic

Wood and WoodDerived Fuels1 Geothermal

Other

Biomass2

Total 

(Other Renewables)

Total (All Sectors)

1998.................................. 3,026 502 36,338 14,774 22,448 77,088

1999.................................. 4,488 495 37,041 14,827 22,572 79,423

2000.................................. 5,593 493 37,595 14,093 23,131 80,906

2001.................................. 6,737 543 35,200 13,741 14,548 70,769

2002.................................. 10,354 555 38,665 14,491 15,044 79,109

2003.................................. 11,187 534 37,529 14,424 15,812 79,487

2004.................................. 14,144 575 38,117 14,811 15,421 83,067

2005.................................. 17,811 550 38,856 14,692 15,420 87,329

2006.................................. 26,589 508 38,762 14,568 16,099 96,525

2007.................................. 34,450 612 39,014 14,637 16,525 105,238

2008.................................. 55,363 864 37,300 14,840R 17,734 126,101R

2009.................................. 73,886 891 35,596 15,009 18,443 143,824

Electricity Generators, Electric Utilities

1998.................................. 3 3 719 5,176 1,305 7,206

1999.................................. 23 3 684 1,698 1,307 3,716

2000.................................. 29 3 700 151 1,358 2,241

2001.................................. 135 3 560 152 815 1,666

2002.................................. 213 3 709 1,402 761 3,089

2003.................................. 354 2 882 1,249 934 3,421 

2004.................................. 405 6 1,209 1,248 824 3,692

2005.................................. 1,046 16 1,829 1,126 929 4,945

2006.................................. 2,351 15 1,937 1,162 1,123 6,588

2007.................................. 4,361 11 2,226 1,139 1,217 8,953

2008.................................. 6,899 17 1,888 1,197 1,307 11,308

2009.................................. 10,348 28 1,748 1,182 1,312 14,617

Electricity Generators, Independent Power Producers

1998.................................. 3,023 500 5,925 9,598 15,658 34,703

1999.................................. 4,465 492 6,569 13,129 15,805 40,460

2000.................................. 5,565 491 6,601 13,942 16,234 42,831 

2001.................................. 6,602 539 6,011 13,588 10,460 37,200

2002.................................. 10,141 552 6,556 13,089 10,391 40,729

2003.................................. 10,834 532 6,520 13,175 10,998 42,058

2004.................................. 13,739 569 6,940 13,563 10,932 45,743

2005.................................. 16,764 535 6,668 13,566 10,761 48,294

2006.................................. 24,238 493 6,374 13,406 11,379 55,890

2007.................................. 30,089 601 6,451 13,498 11,662 62,301

2008.................................. 48,464 847 6,746 13,643R 12,659 82,358R

2009.................................. 63,538 863 6,733 13,826 12,968 97,928

Combined Heat and Power, Electric Power3

1998.................................. -- -- 1,964 -- 2,270 4,234

1999.................................. -- -- 1,707 -- 2,381 4,088

2000.................................. -- -- 1,615 -- 2,715 4,330 

2001.................................. -- -- 1,723 -- 1,669 3,393 

2002.................................. -- -- 1,744 -- 1,993 3,737

2003.................................. -- -- 2,126 -- 1,876 4,002

2004.................................. -- -- 1,588 -- 1,306 2,893

2005.................................. -- -- 2,073 -- 1,341 3,415

2006.................................. -- -- 2,030 -- 1,426 3,456

2007.................................. -- -- 2,034 -- 1,416 3,450

2008.................................. -- -- 2,004 -- 1,413 3,417

2009.................................. -- -- 2,258 -- 1,674 3,932

Combined Heat and Power, Commercial4

1998.................................. -- -- 38 -- 2,335 2,373

1999.................................. -- -- 20 -- 2,393 2,412 

2000.................................. -- -- 27 -- 1,985 2,012

2001.................................. -- -- 18 -- 1,007 1,025

2002.................................. -- -- 13 -- 1,053 1,065

2003.................................. -- -- 13 -- 1,289 1,302

2004.................................. -- -- 13 -- 1,562 1,575

2005.................................. -- -- 16 -- 1,657 1,673

2006.................................. -- -- 21 -- 1,599 1,619

2007.................................. -- -- 15 -- 1,599 1,614

2008.................................. -- * 21 -- 1,534 1,555

2009.................................. * * 20 -- 1,748 1,769

Combined Heat and Power, Industrial4

1998.................................. -- -- 27,693 -- 880 28,572

1999.................................. -- -- 28,060 -- 686 28,747

2000.................................. -- -- 28,652 -- 839 29,491

2001.................................. -- -- 26,888 -- 596 27,485

2002.................................. -- -- 29,643 -- 846 30,489

2003.................................. -- -- 27,988 -- 715 28,704

2004.................................. -- -- 28,367 -- 797 29,164

2005.................................. -- -- 28,271 -- 733 29,003

2006.................................. -- -- 28,400 -- 572 28,972

2007.................................. -- -- 28,287 -- 631 28,919

2008.................................. -- -- 26,641 -- 821 27,462

2009.................................. -- -- 24,838 -- 740 25,578



1 Wood/wood waste solids (including paper pellets, railroad ties, utility poles, wood chips, bark, and wood waste solids), wood waste liquids (red liquor, sludge wood, spent sulfite liquor, 

and other wood-based liquids), and black liquor.

2 Biogenic municipal solid waste, landfill gas, sludge waste, agricultural byproducts, other biomass solids, other biomass liquids, and other biomass gases (including digester gases, 

methane, and other biomass gases). 

3 Electric utility CHP plants are included in Electricity Generators, Electric Utilities. 

4 Small number of electricity-only, non-Combined Heat and Power plants may be included.

* = Value is less than half of the smallest unit of measure.

R = Revised. 

Note: Totals may not equal sum of components because of independent rounding

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report.
U.S. Energy Information Administration/Electric Power Annual 2009 29

Table 2.2. Useful Thermal Output by Energy Source by Combined Heat and Power Producers, 1998 

through 2009 

(Billion Btus)

Period Coal1 Petroleum2 Natural Gas Other Gases3 Other 

Renewables4 Other5 Total

Total Combined Heat and Power

1998.................................. 381,546 135,519 781,637 167,064 757,131 46,437 2,269,334

1999.................................. 385,926 125,486 810,918 178,971 744,470 47,871 2,293,642

2000.................................. 383,687 108,045 812,036 184,062 763,674 50,459 2,301,963

2001.................................. 354,204 90,308 740,979 132,937 584,560 55,162 1,958,151

2002.................................. 336,848 72,826 708,738 117,513 571,507 48,264 1,855,697

2003.................................. 333,361 85,263 610,122 110,263 632,368 54,960 1,826,335

2004.................................. 351,871 97,484 654,242 126,157 667,341 45,456 1,942,550

2005.................................. 341,806 92,383 624,008 138,469 664,691 41,400 1,902,757

2006.................................. 332,548 78,232 603,288 126,049 689,549 49,308 1,878,973

2007.................................. 326,803 76,255 554,394 116,313 651,230 46,822 1,771,816

2008.................................. 315,244 47,817 509,330 110,680 610,131 23,729 1,616,931

2009.................................. 281,557 52,910 513,002 99,556 593,670 33,287 1,573,983

Combined Heat and Power, Electric Power

1998.................................. 43,256 6,261 141,834 5,064 25,969 68 222,452

1999.................................. 52,061 6,718 145,525 3,548 30,172 28 238,052

2000.................................. 53,329 6,610 157,886 5,312 25,661 39 248,837

2001.................................. 51,515 6,087 164,206 4,681 12,676 3,343 242,508

2002.................................. 40,020 3,869 214,137 5,961 12,550 4,732 281,269

2003.................................. 38,249 7,379 200,077 9,282 19,786 3,296 278,068

2004.................................. 39,014 8,217 239,416 18,200 17,347 3,822 326,017

2005.................................. 39,652 7,809 239,324 36,694 18,240 3,884 345,605

2006.................................. 38,133 7,065 207,095 22,567 17,284 4,435 296,579

2007.................................. 38,260 7,156 212,705 20,473 19,166 4,459 302,219

2008.................................. 37,220 6,832 204,167 22,109 17,052 4,854 292,234

2009.................................. 38,015 6,786 190,875 19,830 17,625 5,055 278,187

Combined Heat and Power, Commercial

1998.................................. 20,185 4,853 38,510 34 18,426 -- 82,008

1999.................................. 20,479 3,298 36,857 -- 17,145 -- 77,779

2000.................................. 21,001 3,827 39,293 -- 17,613 -- 81,734

2001.................................. 18,495 4,118 34,923 -- 8,253 5,770 71,560

2002.................................. 18,477 2,743 36,265 -- 6,901 4,801 69,188

2003.................................. 22,780 2,716 16,955 -- 8,297 6,142 56,889

2004.................................. 22,450 4,283 21,851 -- 8,936 6,350 63,871

2005.................................. 22,601 3,684 20,227 -- 8,647 5,921 61,081

2006.................................. 22,186 2,264 19,370 0 9,359 6,242 59,422

2007.................................. 22,595 1,861 20,040 -- 6,651 3,983 55,131

2008 .................................. 22,991 1,999 20,183 -- 8,863 6,054 60,091 

2009.................................. 20,057 1,250 25,902 -- 8,450 5,761 61,420

Combined Heat and Power, Industrial

1998.................................. 318,105 124,405 601,293 161,966 712,736 46,369 1,964,874

1999.................................. 313,386 115,470 628,536 175,423 697,153 47,843 1,977,811

2000.................................. 309,357 97,608 614,857 178,750 720,400 50,420 1,971,392

2001.................................. 284,194 80,103 541,850 128,256 563,631 46,049 1,644,083

2002.................................. 278,351 66,214 458,336 111,552 552,056 38,731 1,505,240

2003.................................. 272,332 75,168 393,090 100,981 604,285 45,522 1,491,378

2004.................................. 290,407 84,984 392,974 107,956 641,058 35,284 1,552,663

2005.................................. 279,552 80,889 364,457 101,775 637,803 31,594 1,496,071

2006.................................. 272,229 68,903 376,822 103,481 662,906 38,630 1,522,971

2007.................................. 265,948 67,238 321,648 95,840 625,413 38,380 1,414,466

2008.................................. 255,032 38,986 284,980 88,571 584,216 12,821 1,264,606

2009.................................. 223,485 44,874 296,225 79,726 567,595 22,471 1,234,376

1 Anthracite, bituminous coal, subbituminous coal, lignite, waste coal, and synthetic coal. 2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology) and waste oil.

3 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 4 Other renewables represents the summation of the sub-categories of Wind, Solar Thermal and Photovoltaic, Wood and Wood Derived Fuels, Geothermal, and Other Biomass. 5

 Non-biogenic municipal solid waste, batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and miscellaneous technologies.

Notes: • The methodology to allocate fuel use by combined heat and power plants to electric power generation and useful thermal output was modified beginning in 2007, and 

retroactively applied to data from 2004 to 2006. For more information, please see the Technical Notes in the Appendices. • Totals may not equal sum of components because of 

independent rounding.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report.
30 U.S. Energy Information Administration/Electric Power Annual 2009

Chapter 3. Fuel and Emissions
U.S. Energy Information Administration/Electric Power Annual 2009 31

Table 3.1. Consumption of Fossil Fuels for Electricity Generation by Type of Power Producer, 1998 

through 2009 

Type of Power Producer and Period Coal

(Thousand Tons)1

Petroleum

(Thousand Barrels)2

Natural Gas

(Thousand Mcf)

Other Gases

(Billion Btu)3

Total (All Sectors)

1998 ............................................................................. 946,295 222,640 5,081,384 124,988

1999 ............................................................................. 949,802 207,871 5,321,984 126,387

2000 ............................................................................. 994,933 195,228 5,691,481 125,971

2001 ............................................................................. 972,691 216,672 5,832,305 97,308

2002 ............................................................................. 987,583 168,597 6,126,062 131,230

2003 ............................................................................. 1,014,058 206,653 5,616,135 156,306

2004 ............................................................................. 1,020,523 203,494 5,674,580 135,144 2005 ............................................................................. 1,041,448 206,785 6,036,370 109,916

2006 ............................................................................. 1,030,556 110,634 6,461,615 114,665

2007 ............................................................................. 1,046,795 112,615 7,089,342 114,904

2008 ............................................................................. 1,042,335 80,932 6,895,843 96,757

2009 ............................................................................. 934,683 67,666 7,120,585 83,593

Electricity Generators, Electric Utilities

1998 ............................................................................. 910,867 187,461 3,258,054 --

1999 ............................................................................. 894,120 151,868 3,113,419 --

2000 ............................................................................. 859,335 125,788 3,043,094 --

2001 ............................................................................. 806,269 133,456 2,686,287 --

2002 ............................................................................. 767,803 99,219 2,259,684 5,182

2003 ............................................................................. 757,384 118,087 1,763,764 6,078

2004 ............................................................................. 772,224 124,541 1,809,443 5,163 2005 ............................................................................. 761,349 118,874 2,134,859 91

2006 ............................................................................. 753,390 71,624 2,478,396 358

2007 ............................................................................. 764,765 70,950 2,736,418 1,523

2008 ............................................................................. 760,326 50,475 2,730,134 1,818

2009 ............................................................................. 695,615 45,651 2,911,279 2,209

Electricity Generators, Independent Power Producers

1998 ............................................................................. 9,486 9,676 285,878 1,345

1999 ............................................................................. 30,572 30,037 615,756 696

2000 ............................................................................. 107,745 45,011 1,049,636 1,951

2001 ............................................................................. 139,799 60,489 1,477,643 92

2002 ............................................................................. 192,274 44,993 1,998,782 354

2003 ............................................................................. 226,154 68,817 2,016,550 171

2004 ............................................................................. 222,550 63,060 2,332,092 86 2005 ............................................................................. 254,291 72,953 2,457,412 43

2006 ............................................................................. 251,379 26,873 2,612,653 49

2007 ............................................................................. 258,075 29,868 2,875,183 62

2008 ............................................................................. 257,480 21,284 2,790,358 19

2009 ............................................................................. 217,951 12,547 2,838,826 16

Combined Heat and Power, Electric Power4

1998 ............................................................................. 13,773 12,310 871,881 21,406

1999 ............................................................................. 13,197 12,440 914,600 13,627

2000 ............................................................................. 15,634 13,147 921,341 16,871

2001 ............................................................................. 15,455 11,175 978,563 9,352

2002 ............................................................................. 15,174 11,942 1,149,812 19,958

2003 ............................................................................. 19,498 8,431 1,128,935 23,317

2004 ............................................................................. 17,685 8,209 933,804 21,899 2005 ............................................................................. 17,927 7,933 892,509 24,289

2006 ............................................................................. 18,033 6,738 800,173 27,173

2007 ............................................................................. 18,506 6,498 890,012 25,428

2008 ............................................................................. 19,085 5,389 821,839 21,513

2009 ............................................................................. 16,126 5,953 816,402 19,098

Combined Heat and Power, Commercial5

1998 ............................................................................. 440 802 40,693 54

1999 ............................................................................. 481 931 39,045 *

2000 ............................................................................. 514 823 37,029 *

2001 ............................................................................. 532 1,023 36,248 *

2002 ............................................................................. 477 834 32,545 *

2003 ............................................................................. 582 894 38,480 --

2004 ............................................................................. 377 766 32,839 -- 2005 ............................................................................. 377 585 33,785 --

2006 ............................................................................. 347 333 34,623 --

2007 ............................................................................. 361 258 34,087 --

2008 ............................................................................. 369 166 33,403 --

2009 ............................................................................. 317 190 34,279 --

Combined Heat and Power, Industrial5

1998 ............................................................................. 11,728 12,392 624,878 102,183

1999 ............................................................................. 11,432 12,595 639,165 112,064

2000 ............................................................................. 11,706 10,459 640,381 107,149

2001 ............................................................................. 10,636 10,530 653,565 87,864

2002 ............................................................................. 11,855 11,608 685,239 105,737

2003 ............................................................................. 10,440 10,424 668,407 126,739

2004 ............................................................................. 7,687 6,919 566,401 107,995 2005 ............................................................................. 7,504 6,440 517,805 85,492

2006 ............................................................................. 7,408 5,066 535,770 87,084

2007 ............................................................................. 5,089 5,041 553,643 87,892

2008 ............................................................................. 5,075 3,617 520,109 73,407

2009 ............................................................................. 4,674 3,326 519,799 62,269

1 Includes anthracite, bituminous, subbituminous and lignite coal. Waste and synthetic coal were included starting in 2002. 2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 4 Electric utility CHP plants are included in Electricity Generators, Electric Utilities. 

5 Small number of electricity-only, non-Combined Heat and Power plants may be included.

* = Value is less than half of the smallest unit of measure.

Notes: • See Glossary reference for definitions • A new method of allocating fuel consumption between electric power generation and useful thermal output (UTO) was implemented with 

publication of the preliminary 2008 data, and retroactively applied to 2004-2007 data. The new methodology evenly distributes a combined heat and power (CHP) plant`s losses between 

the two output products (electric power and UTO). In the historical data, UTO was consistently assumed to be 80 percent efficient and all other losses at the plant were allocated to electric 

power. This change results in the fuel for electric power to be lower while the fuel for UTO is higher than the prior set of data as both are given the same efficiency. This results in the 

appearance of an increase in efficiency of production of electric power after 2003.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report.
32 U.S. Energy Information Administration/Electric Power Annual 2009

Table 3.2. Consumption of Fossil Fuels for Useful Thermal Output by Type of Combined Heat and 

Power Producers, 1998 through 2009 

Type of Power Producer and Year Coal

(Thousand Tons)1

Petroleum

(Thousand Barrels)2

Natural Gas

(Thousand Mcf)

Other Gases

(Billion Btu)3

Total Combined Heat and Power

1998....................................................................... 20,320 28,845 949,106 208,828

1999....................................................................... 20,373 26,822 982,958 223,713

2000....................................................................... 20,466 22,266 985,263 230,082

2001....................................................................... 18,944 18,268 898,286 166,161

2002....................................................................... 17,561 14,811 860,019 146,882

2003....................................................................... 17,720 17,939 721,267 137,837

2004....................................................................... 24,275 25,870 1,052,100 218,295

2005....................................................................... 23,833 24,408 984,340 238,396

2006....................................................................... 23,227 20,371 942,817 226,464

2007....................................................................... 22,810 19,775 872,579 214,321

2008....................................................................... 22,168 12,016 793,537 203,236

2009....................................................................... 20,507 13,164 816,787 175,671

Electric Power4

1998....................................................................... 2,493 1,322 172,471 6,329

1999....................................................................... 3,033 1,423 175,757 4,435

2000 ....................................................................... 3,107 1,412 192,253 6,641 

2001....................................................................... 2,910 1,171 199,808 5,849

2002....................................................................... 2,255 841 263,619 7,448

2003....................................................................... 2,080 1,596 225,967 11,601

2004....................................................................... 3,809 2,688 388,424 31,132

2005....................................................................... 3,918 2,424 384,365 59,569

2006....................................................................... 3,834 2,129 330,878 36,963

2007....................................................................... 3,795 2,114 339,796 34,384

2008....................................................................... 3,689 1,907 326,048 37,899

2009....................................................................... 3,935 1,930 305,542 33,812

Commercial

1998....................................................................... 1,002 1,006 46,527 41

1999....................................................................... 1,009 682 44,991 --

2000....................................................................... 1,034 792 47,844 --

2001....................................................................... 916 809 42,407 --

2002....................................................................... 929 416 41,430 --

2003....................................................................... 1,234 555 19,973 --

2004....................................................................... 1,540 1,243 39,233 --

2005....................................................................... 1,544 1,045 34,172 --

2006....................................................................... 1,539 601 33,112 1

2007....................................................................... 1,566 494 35,987 --

2008....................................................................... 1,652 504 32,813 --

2009....................................................................... 1,481 331 41,275 --

Industrial

1998....................................................................... 16,824 26,518 730,108 202,458

1999....................................................................... 16,330 24,718 762,210 219,278

2000....................................................................... 16,325 20,062 745,165 223,441

2001....................................................................... 15,119 16,287 656,071 160,312

2002....................................................................... 14,377 13,555 554,970 139,434

2003....................................................................... 14,406 15,788 475,327 126,236

2004....................................................................... 18,926 21,939 624,443 187,162

2005....................................................................... 18,371 20,940 565,803 178,827

2006....................................................................... 17,854 17,640 578,828 189,501

2007....................................................................... 17,449 17,166 496,796 179,937

2008....................................................................... 16,827 9,605 434,676 165,337

2009....................................................................... 15,091 10,902 469,970 141,859

1 Includes anthracite, bituminous, subbituminous and lignite coal. Waste and synthetic coal were included starting in 2002. 2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 4 Electric utility CHP plants are included in Table 4.1 with Electric Generators, Electric Utilities.

Notes: • Totals may not equal sum of components because of independent rounding. • A new method of allocating fuel consumption between electric power generation and useful thermal 

output (UTO) was implemented with publication of the preliminary 2008 data, and retroactively applied to 2004-2007 data. The new methodology evenly distributes a combined heat and 

power (CHP) plant`s losses between the two output products (electric power and UTO). In the historical data, UTO was consistently assumed to be 80 percent efficient and all other losses 

at the plant were allocated to electric power. This change results in the fuel for electric power to be lower while the fuel for UTO is higher than the prior set of data as both are given the 

same efficiency. This results in the appearance of an increase in efficiency of production of electric power after 2003.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report.
U.S. Energy Information Administration/Electric Power Annual 2009 33

Table 3.3. Consumption of Fossil Fuels for Electricity Generation and for Useful Thermal Output, 

1998 through 2009 

Period Coal

(Thousand Tons)1

Petroleum

(Thousand Barrels)2

Natural Gas

(Thousand Mcf)

Other Gases

(Billion Btu)3

Total (All Sectors)

1998 ............................................................................. 966,615 251,486 6,030,490 333,816 

1999 ............................................................................. 970,175 234,694 6,304,942 350,100

2000 ............................................................................. 1,015,398 217,494 6,676,744 356,053 

2001 ............................................................................. 991,635 234,940 6,730,591 263,469

2002 ............................................................................. 1,005,144 183,408 6,986,081 278,111 

2003 ............................................................................. 1,031,778 224,593 6,337,402 294,143

2004 ............................................................................. 1,044,798 229,364 6,726,679 353,438 

2005 ............................................................................. 1,065,281 231,193 7,020,709 348,312

2006 ............................................................................. 1,053,783 131,005 7,404,432 341,129

2007 ............................................................................. 1,069,606 132,389 7,961,922 329,225

2008 ............................................................................. 1,064,503 92,948 7,689,380 299,993

2009 ............................................................................. 955,190 80,830 7,937,372 259,264

Electricity Generators, Electric Utilities

1998 ............................................................................. 910,867 187,461 3,258,054 --

1999 ............................................................................. 894,120 151,868 3,113,419 --

2000 ............................................................................. 859,335 125,788 3,043,094 --

2001 ............................................................................. 806,269 133,456 2,686,287 --

2002 ............................................................................. 767,803 99,219 2,259,684 5,182 

2003 ............................................................................. 757,384 118,087 1,763,764 6,078

2004 ............................................................................. 772,224 124,541 1,809,443 5,163 

2005 ............................................................................. 761,349 118,874 2,134,859 91

2006 ............................................................................. 753,390 71,624 2,478,396 358

2007 ............................................................................. 764,765 70,950 2,736,418 1,523

2008 ............................................................................. 760,326 50,475 2,730,134 1,818 

2009 ............................................................................. 695,615 45,651 2,911,279 2,209

Electricity Generators, Independent Power Producers

1998 ............................................................................. 9,486 9,676 285,878 1,345

1999 ............................................................................. 30,572 30,037 615,756 696

2000 ............................................................................. 107,745 45,011 1,049,636 1,951

2001 ............................................................................. 139,799 60,489 1,477,643 92

2002 ............................................................................. 192,274 44,993 1,998,782 354

2003 ............................................................................. 226,154 68,817 2,016,550 171

2004 ............................................................................. 222,550 63,060 2,332,092 86

2005 ............................................................................. 254,291 72,953 2,457,412 43

2006 ............................................................................. 251,379 26,873 2,612,653 49

2007 ............................................................................. 258,075 29,868 2,875,183 62

2008 ............................................................................. 257,480 21,284 2,790,358 19

2009 ............................................................................. 217,951 12,547 2,838,826 16

Combined Heat and Power, Electric Power4

1998 ............................................................................. 16,266 13,632 1,044,352 27,735 

1999 ............................................................................. 16,230 13,864 1,090,356 18,062

2000 ............................................................................. 18,741 14,559 1,113,595 23,512 

2001 ............................................................................. 18,365 12,346 1,178,371 15,201

2002 ............................................................................. 17,430 12,783 1,413,431 27,406 

2003 ............................................................................. 21,578 10,028 1,354,901 34,918

2004 ............................................................................. 21,494 10,897 1,322,228 53,031 

2005 ............................................................................. 21,845 10,357 1,276,874 83,858

2006 ............................................................................. 21,867 8,867 1,131,051 64,136 

2007 ............................................................................. 22,301 8,613 1,229,808 59,812

2008 ............................................................................. 22,774 7,296 1,147,887 59,412 

2009 ............................................................................. 20,061 7,883 1,121,944 52,911

Combined Heat and Power, Commercial5

1998 ............................................................................. 1,443 1,807 87,220 95

1999 ............................................................................. 1,490 1,613 84,037 *

2000 ............................................................................. 1,547 1,615 84,874 *

2001 ............................................................................. 1,448 1,832 78,655 *

2002 ............................................................................. 1,405 1,250 73,975 *

2003 ............................................................................. 1,816 1,449 58,453 --

2004 ............................................................................. 1,917 2,009 72,072 --

2005 ............................................................................. 1,922 1,630 67,957 --

2006 ............................................................................. 1,886 935 67,735 1

2007 ............................................................................. 1,927 752 70,074 --

2008 ............................................................................. 2,021 671 66,216 --

2009 ............................................................................. 1,798 521 75,555 --

Combined Heat and Power, Industrial5

1998 ............................................................................. 28,553 38,910 1,354,986 304,641

1999 ............................................................................. 27,763 37,312 1,401,374 331,342 

2000 ............................................................................. 28,031 30,520 1,385,546 330,590

2001 ............................................................................. 25,755 26,817 1,309,636 248,176 

2002 ............................................................................. 26,232 25,163 1,240,209 245,171

2003 ............................................................................. 24,846 26,212 1,143,734 252,975 

2004 ............................................................................. 26,613 28,857 1,190,844 295,158

2005 ............................................................................. 25,875 27,380 1,083,607 264,319 

2006 ............................................................................. 25,262 22,706 1,114,597 276,585

2007 ............................................................................. 22,537 22,207 1,050,439 267,829

2008 ............................................................................. 21,902 13,222 954,785 238,744

2009 ............................................................................. 19,766 14,228 989,769 204,128



1 Includes anthracite, bituminous, subbituminous and lignite coal. Waste and synthetic coal were included starting in 2002. 2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Blast furnace gas, propane gas, and other manufactured and waste gases derived from fossil fuels. 4 Electric utility CHP plants are included in Electricity Generators, Electric Utilities. 

5 Small number of electricity-only, non-Combined Heat and Power plants may be included.

* = Value is less than half of the smallest unit of measure.

Note: Totals may not equal sum of components because of independent rounding 

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report.
34 U.S. Energy Information Administration/Electric Power Annual 2009

Table 3.4. End-of-Year Stocks of Coal and Petroleum by Type of Producer, 1998 through 2009 

Period

Electric Power Sector Electric Utilities Independent Power Producers

Coal

(Thousand 

Tons)1

Petroleum

(Thousand 

Barrels)2

Coal

(Thousand 

Tons)1

Petroleum

(Thousand 

Barrels)2

Coal

(Thousand Tons)

Petroleum

(Thousand 

Barrels)

1998............................ 120,501 56,591 120,501 56,591 NA NA

1999............................ 141,604 54,109 129,041 46,169 12,563 7,940

2000............................ 102,296 40,932 90,115 30,502 12,180 10,430

2001............................ 138,496 57,031 117,147 37,308 21,349 19,723

2002............................ 141,714 52,490 116,952 31,243 24,761 21,247

2003............................ 121,567 53,170 97,831 29,953 23,736 23,218

2004............................ 106,669 51,434 84,917 32,281 21,751 19,153

2005............................ 101,137 50,062 77,457 31,400 23,680 18,661

2006............................ 140,964 51,583 110,277 32,082 30,688 19,502

2007............................ 151,221 47,203 120,504 29,297 30,717 17,906

2008............................ 161,589 44,498 127,463 28,450 34,126 16,048

2009............................ 189,467 46,181 154,815 31,778 34,652 14,402

1 Anthracite, bituminous, subbituminous, lignite, and synthetic coal, excludes waste coal.

2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology). Data prior to 2005 includes small quantities of waste oil.

NA = Not available. 

Note: Totals may not equal sum of components because of independent rounding.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report.
U.S. Energy Information Administration/Electric Power Annual 2009 35

Table 3.5. Receipts, Average Cost, and Quality of Fossil Fuels for the Electric Power Industry, 1998 

through 2009 

Period

Coal1 Petroleum2 Natural Gas3 All Fossil 

Fuels

Receipts Average Cost Avg. 

Sulfur 

Percent 

by 

Weight

Receipts Average Cost Avg. 

Sulfur 

Percent 

by 

Weight4

Receipts Average 

Cost

Average 

Cost

(thousand 

tons)

(cents per 

MMBtu)

(dollars/

ton)

(thousand 

barrels)

(cents per 

MMBtu)

(dollars/ 

barrel)

(thousand 

Mcf)

(cents per 

MMBtu)

(cents per 

MMBtu)

1998........................ 929,448 125 25.64 1.06 181,276 202 12.71 1.48 2,922,957 238 144

1999........................ 908,232 122 24.72 1.01 145,939 236 14.81 1.51 2,809,455 257 144

2000........................ 790,274 120 24.28 .93 108,272 418 26.30 1.33 2,629,986 430 174

2001........................ 762,815 123 24.68 .89 124,618 369 23.20 1.42 2,148,924 449 173

2002........................ 884,287 125 25.52 .94 120,851 334 20.77 1.64 5,607,737 356 186

20035 ...................... 986,026 128 26.00 .97 185,567 433 26.78 1.53 5,500,704 539 228

2004........................ 1,002,032 136 27.42 .97 186,655 429 26.56 1.66 5,734,054 596 248

2005........................ 1,021,437 154 31.20 .98 194,733 644 39.65 1.61 6,181,717 821 325

2006........................ 1,079,943 169 34.09 .97 100,965 623 37.66 2.31 6,675,246 694 302

2007........................ 1,054,664 177 35.48 .96 88,347 717 43.50 2.10 7,200,316 711 323

2008........................ 1,069,709 207 41.14 .97 96,341 1,087 64.89 2.21 7,879,046 902 411

2009........................ 981,477 221 43.74 1.01 88,951 702 41.64 2.14 8,118,550 474 304

1 Anthracite, bituminous, subbituminous, lignite, waste coal, and synthetic coal.

2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately. Natural gas values for 2001 forward do not include blast furnace gas or other 

gas.

4 Beginning in 2006, receipts of petroleum liquids went down substantially, while the receipts of petroleum coke remained the nearly the same. The Average Sulfur Percent by Weight is 

higher beginning in 2006 as a result the greater influence by petroleum coke receipts, which has higher sulfur content, than the petroleum liquid receipts. 5

 Beginning in 2002, data from the historical Form EIA-423 for independent power producers and combined heat and power producers are included in this table. Prior to 2002, these data 

were not collected; the data for 2001 and previous years include only data collected from electric utilities via the historical FERC Form 423.

Notes: • Mcf equals 1,000 cubic feet. Totals may not equal sum of components because of independent rounding. • Beginning in 2008 with the Form EIA-923, receipts, cost, and quality 

data are imputed for plants between 1 and 50 MW, in addition to the data collected from plants above the 50 MW threshold. Therefore, there may be a notable increase in fuel receipts 

beginning with 2008 data.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report;" Federal Energy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for 

Electric Plants."

Table 3.6. Receipts and Quality of Coal Delivered for the Electric Power Industry, 1998 through 

2009

Period

Anthracite1 Bituminous1 Subbituminous Lignite 

Receipts

(thousand 

tons)

Avg.

Sulfur 

Percent 

by 

Weight

Avg.

Ash 

Percent 

by 

Weight

Receipts

(thousand 

tons)

Avg.

Sulfur 

Percent 

by 

Weight

Avg.

Ash 

Percent 

by 

Weight

Receipts

(thousand 

tons)

Avg.

Sulfur 

Percent 

by 

Weight

Avg.

Ash 

Percent 

by 

Weight

Receipts

(thousand 

tons)

Avg.

Sulfur 

Percent 

by 

Weight

Avg.

Ash 

Percent 

by 

Weight

1998........................ 511 .55 37.6 478,252 1.61 10.5 373,496 .38 6.6 77,189 .95 13.8

1999........................ 137 .64 37.8 444,399 1.57 10.2 386,271 .38 6.6 77,425 .90 14.2

2000........................ 11 .64 37.2 375,673 1.45 10.1 341,242 .35 6.3 73,349 .91 14.2

2001........................ -- -- -- 348,703 1.42 10.4 349,340 .35 6.1 64,772 .98 13.9

2002........................ -- -- -- 412,589 1.47 10.1 391,785 .36 6.2 65,555 .93 13.3

20032 ...................... -- -- -- 436,809 1.49 9.9 432,513 .38 6.4 79,869 1.03 14.4

2004........................ -- -- -- 441,186 1.50 10.3 445,603 .36 6.0 78,268 1.05 14.2

2005........................ -- -- -- 451,680 1.55 10.5 456,856 .36 6.2 77,677 1.02 14.0

2006........................ -- -- -- 462,992 1.57 10.5 504,947 .35 6.1 75,742 .95 14.4

2007........................ -- -- -- 439,154 1.61 10.3 505,155 .34 6.0 71,930 .90 14.0

2008........................ -- -- -- 463,943 1.68 10.6 522,228 .34 5.8 68,945 .86 13.8

2009........................ -- -- -- 418,688 1.77 10.5 484,007 .34 5.8 64,966 .95 14.0

1 Beginning in 2001, anthracite coal receipts were no longer reported separately. From 2001 forward, all anthracite coal receipts have been combined with bituminous coal receipts. 2 Beginning in 2002, data from the historical Form EIA-423 for independent power producers and combined heat and power producers are included in this table. Prior to 2002, these data 

were not collected; the data for 2001 and previous years include only data collected from electric utilities via the historical FERC Form 423.

Notes: • Totals may not equal sum of components because of independent rounding. • Beginning in 2008 with the Form EIA-923, receipts, cost, and quality data are imputed for plants 

between 1 and 50 MW, in addition to the data collected from plants above the 50 MW threshold. Therefore, there may be a notable increase in fuel receipts beginning with 2008 data.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report;" Federal Energy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for 

Electric Plants."
36 U.S. Energy Information Administration/Electric Power Annual 2009

Table 3.7. Average Quality of Fossil Fuel Receipts for the Electric Power Industry, 1998 through 

2009

Year

Coal1 Petroleum2 Natural Gas3

Average Btu 

per Pound

Average

Sulfur 

Percent by 

Weight

Average

Ash Percent 

by Weight

Average Btu 

per Gallon

Average

Sulfur Percent 

by Weight

Average Btu per 

Cubic Foot

1998.............................. 10,241 1.06 9.18 149,736 1.48 1,022

1999.............................. 10,163 1.01 9.01 149,407 1.51 1,019

2000.............................. 10,115 .93 8.84 149,857 1.33 1,020

2001.............................. 10,200 .89 8.80 147,857 1.42 1,020

2002.............................. 10,168 .94 8.74 147,902 1.64 1,025

20034 ............................ 10,137 .97 8.98 147,086 1.53 1,030

2004.............................. 10,074 .97 8.97 147,286 1.66 1,027

2005.............................. 10,107 .98 9.02 146,481 1.61 1,028

2006.............................. 10,063 .97 9.03 143,883 2.31 1,027

2007.............................. 10,028 .96 8.84 144,545 2.10 1,027

2008.............................. 9,947 .97 8.95 142,205 2.21 1,027

2009.............................. 9,902 1.01 8.94 141,321 2.14 1,025 

1 Anthracite, bituminous, subbituminous, lignite, waste coal, and synthetic coal.

2 Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquid 

petroleum, see Technical Notes for conversion methodology), and waste oil.

3 Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately. Natural gas values for 2001 forward do not include blast furnace gas or other 

gas.

4 Beginning in 2002, data from the historical Form EIA-423 for independent power producers and combined heat and power producers are included in this table. Prior to 2002, these data 

were not collected; the data for 2001 and previous years include only data collected from electric utilities via the historical FERC Form 423.

Note: Totals may not equal sum of components because of independent rounding.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report;" Federal Energy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for 

Electric Plants."
U.S. Energy Information Administration/Electric Power Annual 2009 37

Table 3.8. Weighted Average Cost of Fossil Fuels for the Electric Power Industry, 1998 through 2009 

Period

Coal Petroleum Natural Gas Total Fossil Fuels Bituminous Subbituminous Lignite All Coal Ranks

Receipts 

(trillion 

Btu)

Average 

Cost 

(cents per 

MMBtu)

Receipts 

(trillion 

Btu)

Average 

Cost 

(cents per 

MMBtu)

Receipts 

(trillion 

Btu)

Average 

Cost 

(cents per 

MMBtu)

Receipts 

(trillion 

Btu)

Average 

Cost 

(cents per 

MMBtu)

Receipts 

(trillion 

Btu)

Average 

Cost 

(cents per 

MMBtu)

Receipts 

(trillion 

Btu)

Average 

Cost 

(cents per 

MMBtu)

Receipts 

(trillion 

Btu)

Average 

Cost 

(cents per 

MMBtu)

1998 ........... 11,510 135 6,520 113 999 94 19,036 125 1,140 202 2,986 238 23,162 144 

1999........... 10,722 131 6,740 110 996 93 18,461 122 916 236 2,862 257 22,238 144

2000........... 9,050 130 5,991 108 947 94 15,988 120 681 418 2,682 430 19,351 174

2001........... 8,312 139 6,134 104 839 109 15,286 123 783 369 2,209 449 18,278 173

2002........... 9,932 142 6,878 105 851 104 17,982 125 751 334 5,750 356 24,483 186

2003........... 10,543 144 7,598 110 1,026 103 19,990 128 1,146 433 5,663 539 26,799 228

2004........... 10,538 156 7,817 112 1,012 106 20,189 136 1,155 429 5,891 596 27,234 248

2005........... 10,833 184 8,004 119 1,008 107 20,647 154 1,198 644 6,357 821 28,202 325

2006........... 11,129 204 8,842 131 982 115 21,735 169 610 623 6,856 694 29,201 302

2007........... 10,580 208 8,826 145 925 128 21,152 177 536 717 7,396 711 29,085 323

2008........... 11,110 250 9,087 162 896 141 21,280 207 575 1,087 8,089 902 29,945 411

2009........... 10,010 275 8,421 164 835 158 19,438 221 528 702 8,319 474 28,285 304

Notes: • Totals may not equal sum of components because of independent rounding. • Beginning in 2008 with the Form EIA-923, receipts, cost, and quality data are imputed for plants 

between 1 and 50 MW, in addition to the data collected from plants above the 50 MW threshold. Therefore, there may be a notable increase in fuel receipts beginning with 2008 data.

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-423, "Monthly Cost and Quality of Fuels for Electric Plants Report;" Federal Energy Regulatory Commission, FERC Form 423, "Monthly Report of Cost and Quality of Fuels for 

Electric Plants."


38 U.S. Energy Information Administration/Electric Power Annual 2009

Table 3.9. Emissions from Energy Consumption at Conventional Power Plants and Combined-Heatand-Power Plants, 1998 through 2009 

(Thousand Metric Tons) 

Emission 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Carbon Dioxide (CO2)....... 2,269,508 2,484,012R 2,547,032R 2,488,918R 2,543,838R 2,486,982R 2,445,094R 2,423,963R 2,418,607R 2,470,834R 2,366,302R 2,351,600R

Sulfur Dioxide (SO2) ........ 5,970 7,830 9,042 9,524 10,340 10,309 10,646 10,881 11,174 11,963 12,843 13,464

Nitrogen Oxides (NOx) ..... 2,395 3,330 3,650 3,799 3,961 4,143 4,532 5,194 5,290 5,638 5,955 6,459 

R = Revised. 

Notes: • The emissions data presented include total emissions from both electricity generation and the production of useful thermal output. • See Appendix A, Technical Notes, for a 

description of the sources and methodology used to develop the emissions estimates. • CO2 emissions for the historical years 1998-2008 have been revised due to changes in emission 

factors.

Source: Calculations made by the Office of Electricity, Renewables, and Uranium Statistics, U.S. Energy Information Administration.

Table 3.10. Number and Capacity of Existing Fossil-Fuel Steam-Electric Generators with 

Environmental Equipment, 1998 through 2009 

Year

Flue Gas Desulfurization

(Scrubbers) Particulate Collectors Cooling Towers Total1

Number of 

Generators

Capacity2 Number of 

Generators

Capacity2 Number of 

Generators

Capacity2 Number of 

Generators

Capacity

(megawatts) (megawatts) (megawatts) (megawatts)

1998.................................. 186 87,783 1,130 351,790 474 166,896 1,294 377,117

1999.................................. 192 89,666 1,148 353,480 505 175,520 1,343 387,192

2000.................................. 192 89,675 1,141 352,727 505 175,520 1,336 386,438

2001.................................. 236 97,988 1,273 360,762 616 189,396 1,485 390,821

2002.................................. 243 98,673 1,256 359,338 670 200,670 1,522 401,341

2003.................................. 246 99,567 1,244 358,009 695 210,928 1,546 409,954

2004.................................. 248 101,492 1,217 355,782 732 214,989 1,536 409,769

2005.................................. 248 101,648 1,216 355,599 730 217,646 1,535 411,840

2006.................................. NA NA NA NA NA NA NA NA

2007R ................................ 278 119,024 1,188 354,407 771 228,704 1,547 421,120

2008R ................................ 327 140,223 1,187 355,517 789 234,254 1,556 426,073

2009.................................. 384 167,517 1,188 358,342 818 241,347 1,573 430,956

1 Components are not additive since some generators are included in more than one category.

2 Nameplate capacity.

NA = Not available. Form EIA-767 data collection was suspended in the data year 2006.

R = Revised. 

Notes: • Data for 2007 through 2009 reflect a minor revision to the aggregation methodology as compared to previous years. The new methodology takes generator status into account 

where previously the data only reflected boiler and flue gas desulfurization unit statuses. • Data for Independent Power Producer and Combined Heat and Power plants are included 

beginning with 2001 data. • Totals may not equal sum of components because of independent rounding.

Sources: Through 2005, U.S. Energy Information Administration, Form EIA-767, "Steam-Electric Plant Operation and Design Report;" and from 2007 forward, U.S. Energy Information 

Administration, Form EIA-860, "Annual Electric Generator Report."

Table 3.11. Average Costs of Existing Flue Gas Desulfurization Units, 1998 through 2009 

Year Average Operation & Maintenance Costs

(mills per kilowatthour)1

Average Installed Capital Costs

(dollars per kilowatt)

1998................................................. 1.12 126.00

1999................................................. 1.13 125.00

2000................................................. .96 124.00

2001................................................. 1.27 130.80

2002................................................. 1.11 124.18

2003................................................. 1.23 123.75

2004................................................. 1.38 144.64

2005................................................. 1.23 141.34

2006................................................. NA NA

2007................................................. 1.51R 135.29R

2008................................................. 1.55 150.74R

2009................................................. 1.61 186.73

1 A mill is one tenth of one cent.

NA = Not available. Form EIA-767 data collection was suspended in the data year 2006.

R = Revised. 

Notes: • Data for 2007 through 2009 reflect a minor revision to the aggregation methodology as compared to previous years. The new methodology takes generator status into account 

where previously the data only reflected boiler and flue gas desulfurization unit statuses. • Data for Independent Power Producer and Combined Heat and Power plants are included 

beginning with 2001 data. • Totals may not equal sum of components because of independent rounding.

Sources: Through 2005, U.S. Energy Information Administration, Form EIA-767, "Steam-Electric Plant Operation and Design Report;" and from 2007 forward, U.S. Energy Information 

Administration, Form EIA-860, "Annual Electric Generator Report" for Average Installed Capital Costs, and Form EIA-923, "Power Plant Operations Report" for Average Operation & 

Maintenance Costs.
U.S. Energy Information Administration/Electric Power Annual 2009 39

Chapter 4. Demand, Capacity Resources, and Capacity Margins
40 U.S. Energy Information Administration/Electric Power Annual 2009

Table 4.1. Noncoincident Peak Load, Actual and Projected by North American Electric Reliability 

Corporation Region, 2005 through 2014 

(Megawatts)

North American Electric 

Reliability Corporation Regional 

Entity 

Actual

2005 2006 2007 2008 2009

Summer

ECAR1............................................................... NA NA NA NA NA

ERCOT.............................................................. 60,210 62,339 62,188 62,174 63,518

FRCC................................................................. 46,396 45,751 46,676 44,836 46,550

MAAC1

.............................................................. NA NA NA NA NA

MAIN1

............................................................... NA NA NA NA NA

MRO (U.S.) 2 ..................................................... 39,918 42,194 41,684 39,677 37,963

NPCC (U.S.) ..................................................... 58,960 63,241 58,314 58,543 55,944

ReliabilityFirst3 ................................................. 190,200 191,920 181,700 169,155 161,241

SERC................................................................. 190,705 199,052 209,109 199,779 191,032

SPP .................................................................... 41,727 42,882 43,167 43,476 41,465

WECC (U.S.) .................................................... 130,760 142,096 139,389 134,829 128,245

Contiguous U.S. ............................................... 758,876 789,475 782,227 752,470 725,958

Winter

ECAR1 ............................................................... NA NA NA NA NA

ERCOT.............................................................. 48,141 50,402 50,408 47,806 56,191

FRCC................................................................. 42,657 42,526 41,701 45,275 53,022

MAAC1

.............................................................. NA NA NA NA NA

MAIN1 ............................................................... NA NA NA NA NA

MRO (U.S.) 2 ..................................................... 33,748 34,677 33,191 36,029 35,351

NPCC (U.S.) ..................................................... 46,828 46,697 46,795 46,043 44,864

ReliabilityFirst3 ................................................. 151,600 149,631 141,900 142,395 143,827

SERC................................................................. 164,638 175,163 179,888 179,596 193,135

SPP .................................................................... 31,260 30,792 31,322 32,809 32,863

WECC (U.S.) .................................................... 107,493 111,093 112,700 113,605 109,565

Contiguous U.S. ............................................... 626,365 640,981 637,905 643,557 668,818

North American Electric 

Reliability Corporation Regional 

Entity

Projected

2010 2011 2012 2013 2014

Summer

TRE (formerly ERCOT) .................................... 63,810 64,964 66,416 68,023 69,209

FRCC................................................................. 46,006 46,124 46,825 47,469 48,059

MRO (U.S.) 2 ..................................................... 42,240 42,733 43,549 44,164 44,627

NPCC (U.S.) ..................................................... 60,215 60,820 61,532 62,307 62,922

ReliabilityFirst3 ................................................. 177,688 181,867 186,900 189,900 192,000

SERC................................................................. 201,350 205,351 210,521 214,295 218,126

SPP .................................................................... 43,395 44,005 45,289 46,012 46,579

WECC (U.S.) .................................................... 137,385 139,205 132,868 133,216 136,402

Contiguous U.S. ............................................... 772,089 785,069 793,900 805,386 817,924

Winter

TRE (formerly ERCOT) .................................... 43,823 43,823 44,804 45,819 46,578

FRCC................................................................. 46,235 46,821 47,558 48,219 48,992

MRO (U.S.) 2 ..................................................... 35,722 36,816 37,359 37,876 38,324

NPCC (U.S.) ..................................................... 46,374 46,529 46,753 47,154 47,401 

ReliabilityFirst3 ................................................. 143,040 146,591 149,000 150,300 151,400

SERC................................................................. 183,614 186,364 190,065 193,158 195,703

SPP .................................................................... 31,415 33,047 33,884 34,423 34,951

WECC (U.S.) .................................................... 108,850 106,854 108,416 110,789 112,673

Contiguous U.S. ............................................... 639,073 646,845 657,839 667,738 676,022

1 ECAR, MAAC, and MAIN dissolved at the end of 2005. Utility membership joined other reliability regional councils. Also, see Footnote 3. 2 Regional name has changed from Mid-Continent Area Power Pool to Midwest Reliability Organization.

3 ReliabilityFirst Corporation (RFC) came into existence on January 1, 2006, and submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN. 

Many of the former utility members joined RFC.

NA = Not available. 

Notes: • Projected data are updated annually, so revision superscript is not used. • NERC Regions are provided in Appendix A., Technical Notes. • Represents an hour of a day during the 

associated peak period. • The summer peak period begins on June 1 and extends through September 30. • The winter peak period begins on December 1 and extends through the end of 

February of the following year • The MRO, SERC, and SPP regional boundaries were altered as a variety of utilities changed reliability organizations. The historical data series have not 

been adjusted. • Totals may not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program Report."
U.S. Energy Information Administration/Electric Power Annual 2009 41

Table 4.2. Net Internal Demand, Capacity Resources, and Capacity Margins by North American 

Electric Reliability Corporation Region, Summer, 1998 through 2009 

(Megawatts)

Regional Entity and 

Item 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

ECAR1

Net Internal Demand2 ................ NA NA NA NA NA 95,300 98,487 101,251 100,235 98,651 94,072 92,359

Capacity Resources3 .................. NA NA NA NA NA 127,919 123,755 119,736 113,136 115,379 107,451 105,545

Capacity Margin (percent)4 ........ NA NA NA NA NA 25.5 20.4 15.4 11.4 14.5 12.5 12.5

TRE (formerly ERCOT)

Net Internal Demand2 ................ 63,518 61,049 61,063 61,214 59,060 58,531 59,282 55,833 55,106 53,649 51,697 50,254

Capacity Resources3................... 76,280 74,274 75,912 70,664 66,724 73,850 74,764 76,849 70,797 69,622 65,423 59,788

Capacity Margin (percent)4 ........ 16.7 17.8 19.6 13.4 11.5 20.7 20.7 27.3 22.2 22.9 21.0 15.9 

FRCC

Net Internal Demand2 ................ 46,263 44,660 46,434 45,345 45,950 42,243 40,387 37,951 38,932 35,666 34,832 34,562

Capacity Resources3................... 49,239 51,541 53,027 50,909 50,200 48,579 46,806 43,342 42,290 43,083 40,645 39,708

Capacity Margin (percent) ......... 6.0 13.4 12.4 10.9 8.5 13.0 13.7 12.4 7.9 17.2 14.3 13.0

MAAC1

Net Internal Demand2 ................ NA NA NA NA NA 52,049 53,566 54,296 54,015 51,358 49,325 47,626

Capacity Resources3................... NA NA NA NA NA 66,167 65,897 63,619 59,533 60,679 57,831 55,511

Capacity Margin (percent)4 ........ NA NA NA NA NA 21.3 18.7 14.7 9.3 15.4 14.7 14.2

MAIN1

Net Internal Demand2 ................ NA NA NA NA NA 50,499 53,617 53,267 53,032 51,845 47,165 45,570

Capacity Resources3................... NA NA NA NA NA 65,677 67,410 67,025 65,950 64,170 55,984 52,722

Capacity Margin (percent)4 ........ NA NA NA NA NA 23.1 20.5 20.5 19.6 19.2 15.8 13.6

MRO (U.S.)5

Net Internal Demand2 ................ 35,849 38,857 40,249 40,661 38,266 29,094 28,775 28,825 27,125 28,006 30,606 29,766

Capacity Resources3................... 47,529 48,180 47,259 50,116 46,792 35,830 33,287 34,259 32,271 34,236 35,373 34,773

Capacity Margin (percent)4 ........ 24.6 19.3 14.8 18.9 18.2 18.8 13.6 15.9 15.9 18.2 13.5 14.4

NPCC (U.S.)

Net Internal Demand2 ................ 55,730 59,896 58,221 60,879 57,402 51,580 53,936 55,164 55,888 54,270 53,450 51,760

Capacity Resources3................... 78,639 75,894 73,771 73,095 72,258 71,532 70,902 66,208 63,760 63,376 63,077 60,439

Capacity Margin (percent)4 ........ 29.1 21.1 21.1 16.7 20.6 27.9 23.9 16.7 12.3 14.4 15.3 14.4

ReliabilityFirst6

Net Internal Demand2 ................ 161,241 169,155 177,200 190,800 190,200 NA NA NA NA NA NA NA

Capacity Resources3................... 215,700 215,477 213,544 214,693 220,000 NA NA NA NA NA NA NA

Capacity Margin (percent)4 ........ 25.2 21.5 17.0 11.1 13.5 NA NA NA NA NA NA NA

SERC

Net Internal Demand2 ................ 186,507 196,711 205,321 196,196 186,049 153,024 148,380 154,459 144,399 151,527 142,726 138,146

Capacity Resources3................... 247,400 228,169 234,232 223,630 219,749 182,861 177,231 172,485 171,530 169,760 160,575 158,360

Capacity Margin (percent)4 ........ 24.6 13.8 12.3 12.3 15.3 16.3 16.3 10.5 15.8 10.7 11.1 12.8

SPP

Net Internal Demand2 ................ 41,117 42,906 42,459 41,982 41,079 39,383 39,428 38,298 38,807 39,056 37,807 36,402

Capacity Resources3................... 49,194 48,110 48,573 45,831 46,376 48,000 45,802 47,233 45,530 46,109 43,111 42,554

Capacity Margin (percent)4 ........ 16.4 10.8 12.6 8.4 11.4 18.0 13.9 18.9 14.8 15.3 12.3 14.5

WECC (U.S.)

Net Internal Demand2 ................ 122,881 130,916 135,839 139,402 128,464 121,205 120,894 117,032 107,294 116,913 112,177 111,641

Capacity Resources3................... 152,467 167,860 168,080 162,288 160,026 155,455 150,277 142,624 124,193 141,640 136,274 135,270

Capacity Margin (percent)4 ........ 19.4 22.0 19.2 14.1 19.7 22.0 19.6 17.9 13.6 17.5 17.7 17.5

Contiguous U.S.

Net Internal Demand2 .............. 713,106 744,151 766,786 776,479 746,470 692,908 696,752 696,376 674,833 680,941 653,857 638,086

Capacity Resources3................. 916,449 909,504 914,397 891,226 882,125 875,870 856,131 833,380 788,990 808,054 765,744 744,670

Capacity Margin (percent)4

..... 22.2 18.2 16.1 12.9 15.4 20.9 18.6 16.4 14.5 15.7 14.6 14.3 

1 ECAR, MAAC, and MAIN dissolved at the end of 2005. Utility membership joined other reliability regional councils. Also, see Footnote 6. 2 Net Internal Demand represent the system demand that is planned for by the electric power industry`s reliability authority and is equal to Internal Demand less Direct Control Load 

Management and Interruptible Demand.

3 Capacity Resources: Utility- and IPP-owned generating capacity that is existing or in various stages of planning or construction, less inoperable capacity, plus planned capacity purchases 

from other resources, less planned capacity sales.

4 Capacity Margin is the amount of unused available capability of an electric power system at peak load as a percentage of capacity resources. 5 Regional name has changed from Mid-Continent Area Power Pool to Midwest Reliability Organization.

6 ReliabilityFirst Corporation (RFC) came into existence on January 1, 2006, and submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN. 

Many of the former utility members joined RFC.

NA = Not available. 

Notes: • NERC Regions are provided in Appendix A., Technical Notes. • Represents an hour of a day during the associated peak period. • The summer peak period begins on June 1 and 

extends through September 30. • The MRO, SERC, and SPP regional boundaries were altered as a variety of utilities changed reliability organizations. The historical data series have not 

been adjusted. • Totals may not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program Report."
42 U.S. Energy Information Administration/Electric Power Annual 2009

Table 4.3. Net Internal Demand, Actual or Planned Capacity Resources, and Capacity Margins by 

North American Electric Reliability Corporation Region, Summer, 2009 through 2014 

(Megawatts)

North American Electric 

Reliability Corporation Regional 

Entity 

Net Internal 

Demand1

Capacity 

Resources2

Capacity 

Margin 

(percent)3

Net Internal 

Demand1

Capacity 

Resources2

Capacity 

Margin 

(percent)3

2009 2010

TRE (formerly ERCOT)............................. 63,518 76,280 16.7 62,412 75,181 17.0

FRCC....................................................... 46,263 49,239 6.0 42,820 53,826 20.4

MRO (U.S.)4............................................. 35,849 47,529 24.6 39,343 50,633 22.3

NPCC (U.S.) ............................................ 55,730 78,639 29.1 60,001 73,341 18.2

ReliabilityFirst5

........................................ 161,241 215,700 25.2 171,488 219,583 21.9

SERC ....................................................... 186,507 247,400 24.6 195,833 247,674 20.9

SPP .......................................................... 41,117 49,194 16.4 42,976 53,298 19.4

WECC (U.S.) ........................................... 122,881 152,467 19.4 124,924 161,358 22.6

Contiguous U.S....................................... 713,106 916,449 22.2 739,798 934,894 20.9

2011 2012

TRE (formerly ERCOT)............................. 63,532 73,075 13.1 64,947 74,733 13.1

FRCC....................................................... 42,831 54,441 21.3 43,409 55,117 21.2

MRO (U.S.)4............................................. 39,823 51,748 23.0 40,618 51,645 21.4

NPCC (U.S.) ............................................ 60,606 74,602 18.8 61,318 79,319 22.7

ReliabilityFirst5

........................................ 175,367 226,033 22.4 177,600 230,107 22.8

SERC ....................................................... 199,297 252,732 21.1 204,045 256,713 20.5

SPP .......................................................... 43,567 55,576 21.6 44,834 56,477 20.6

WECC (U.S.) ........................................... 126,318 170,649 26.0 127,495 176,431 27.7

Contiguous U.S....................................... 751,342 958,855 21.6 764,267 980,542 22.1

2013 2014

TRE (formerly ERCOT)............................. 66,514 75,435 11.8 67,655 76,191 11.2

FRCC....................................................... 43,899 56,923 22.9 44,451 57,097 22.1

MRO (U.S.)4............................................. 41,224 51,967 20.7 41,675 51,986 19.8

NPCC (U.S.) ............................................ 62,093 78,424 20.8 62,708 78,374 20.0

ReliabilityFirst5

........................................ 180,600 232,543 22.3 182,700 232,924 21.6

SERC ....................................................... 207,756 260,524 20.3 211,512 262,024 19.3

SPP .......................................................... 45,544 57,154 20.3 46,102 58,368 21.0

WECC (U.S.) ........................................... 127,459 179,803 29.1 130,302 181,327 28.1

Contiguous U.S....................................... 775,088 992,773 21.9 787,105 998,292 21.2

1 Net Internal Demand represent the system demand that is planned for by the electric power industry`s reliability authority and is equal to Internal Demand less Direct Control Load 

Management and Interruptible Demand.

2 Capacity Resources: Utility- and IPP-owned generating capacity that is existing or in various stages of planning or construction, less inoperable capacity, plus planned capacity purchases 

from other resources, less planned capacity sales.

3 Capacity Margin is the amount of unused available capability of an electric power system at peak load as a percentage of capacity resources. 4 Regional name has changed from Mid-Continent Area Power Pool to Midwest Reliability Organization.

5 ReliabilityFirst Corporation (RFC) came into existence on January 1, 2006, and submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN. 

Many of the former utility members joined RFC.

Notes: • 2009 data are final. • Projected data are updated annually, so revision superscript is not used. • Represents an hour of a day during the associated peak period. • The summer peak 

period begins on June 1 and extends through September 30. • The MRO, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical data 

series have not been adjusted. • Totals may not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program Report."
U.S. Energy Information Administration/Electric Power Annual 2009 43

Table 4.4. Net Internal Demand, Actual or Planned Capacity Resources, and Capacity Margins by 

North American Electric Reliability Corporation Region, Winter, 2009 through 2014 

(Megawatts)

North American Electric 

Reliability Corporation Regional 

Entity 

Net Internal 

Demand1

Capacity 

Resources2

Capacity 

Margin 

(percent)3

Net Internal 

Demand1

Capacity 

Resources2

Capacity 

Margin 

(percent)2

2009/ 2010 2010/ 2011

TRE (formerly ERCOT)................................. 56,191 69,490 19.1 43,487 76,385 43.1

FRCC........................................................... 51,703 52,751 2.0 42,716 57,952 26.3

MRO (U.S.)4................................................. 33,983 46,422 26.8 34,091 52,585 35.2

NPCC (U.S.) ................................................ 44,864 78,992 43.2 46,374 73,083 36.5

ReliabilityFirst5

............................................ 143,827 215,700 33.3 143,040 218,752 34.6

SERC ........................................................... 188,653 255,527 26.2 178,614 253,918 29.7

SPP .............................................................. 32,741 50,097 34.6 31,197 56,009 44.3

WECC (U.S.) ............................................... 106,256 151,022 29.6 100,580 159,643 37.0

Contiguous U.S........................................... 658,219 920,002 28.5 620,100 948,326 34.6

2011/ 2012 2012/ 2013

TRE (formerly ERCOT)................................. 43,453 77,343 43.8 44,397 78,381 43.4

FRCC........................................................... 43,197 58,972 26.8 43,801 59,696 26.6

MRO (U.S.)4................................................. 35,178 53,567 34.3 35,687 53,567 33.4

NPCC (U.S.) ................................................ 46,529 75,244 38.2 46,753 79,602 41.3

ReliabilityFirst5

............................................ 146,591 225,259 34.9 149,000 229,644 35.1

SERC ........................................................... 181,129 260,021 30.3 184,379 262,157 29.7

SPP .............................................................. 32,819 56,435 41.8 33,645 57,674 41.7

WECC (U.S.) ............................................... 103,663 168,753 38.6 105,211 174,613 39.7

Contiguous U.S........................................... 632,559 975,595 35.2 642,873 995,334 35.4

2013/ 2014 2014/ 2015

TRE (formerly ERCOT)................................. 45,372 79,199 42.7 46,086 79,976 42.4

FRCC........................................................... 44,457 61,113 27.3 45,174 61,628 26.7

MRO (U.S.)4................................................. 36,187 53,592 32.5 36,614 53,475 31.5

NPCC (U.S.) ................................................ 47,154 78,942 40.3 47,401 78,943 40.0

ReliabilityFirst5

............................................ 150,300 231,415 35.1 151,400 231,795 34.7

SERC ........................................................... 187,415 267,999 30.1 189,890 269,724 29.6

SPP .............................................................. 34,177 58,004 41.1 34,703 59,245 41.4

WECC (U.S.) ............................................... 107,438 178,495 39.8 109,208 179,961 39.3

Contiguous U.S........................................... 652,500 1,008,759 35.3 660,476 1,014,748 34.9

1 Net Internal Demand represent the system demand that is planned for by the electric power industry`s reliability authority and is equal to Internal Demand less Direct Control Load

Management and Interruptible Demand.

2 Capacity Resources: Utility- and IPP-owned generating capacity that is existing or in various stages of planning or construction, less inoperable capacity, plus planned capacity purchases 

from other resources, less planned capacity sales.

3 Capacity Margin is the amount of unused available capability of an electric power system at peak load as a percentage of capacity resources. 4 Regional name has changed from Mid-Continent Area Power Pool to Midwest Reliability Organization.

5 ReliabilityFirst Corporation (RFC) came into existence on January 1, 2006, and submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN. 

Many of the former utility members joined RFC.

Notes: • 2009/2010 data are final. • Projected data are updated annually, so revision superscript is not used. • Represents an hour of a day during the associated peak period. • The winter 

peak period begins on December 1 and extends through the end of February of the following year. For example, winter 2004/2005 begins December 1, 2004, and extends to February 28, 

2005 • The MRO, SERC, and SPP regional boundaries were altered as a variety of utilities changed reliability organizations. The historical data series have not been adjusted. • Totals may 

not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program Report."
44 U.S. Energy Information Administration/Electric Power Annual 2009

Figure 4.1 Historical North American Electric Reliability Council Regions for

the Contiguous U.S., 2005
U.S. Energy Information Administration/Electric Power Annual 2009 45

Figure 4.2 Consolidated North American Electric Reliability Corporation 

Regional Entities, 2009
46 U.S. Energy Information Administration/Electric Power Annual 2009

Chapter 5. Characteristics of the Electric Power Industry
U.S. Energy Information Administration/Electric Power Annual 2009 47

Table 5.1. Count of Electric Power Industry Power Plants, by Sector, by Predominant Energy Sources within Plant, 2001 

through 2009

(Count)

Period Coal Petroleum Natural Gas Other Gases Nuclear Hydroelectric 

Conventional

Other 

Renewables

Hydroelectric 

Pumped 

Storage

Other

Total (All Sectors)

2001.................. 645 1,160 1,576 35 66 1,421 672 37 14

2002.................. 633 1,186 1,649 40 66 1,426 684 38 26

2003.................. 629 1,206 1,696 40 66 1,425 745 38 25

2004.................. 626 1,201 1,677 46 66 1,425 752 39 26

2005.................. 620 1,210 1,671 44 66 1,422 783 39 27

2006.................. 617 1,215 1,663 46 66 1,421 845 39 27

2007.................. 607 1,198 1,659 46 66 1,424 931 39 24

2008.................. 599 1,205 1,653 43 66 1,423 1,080 39 29

2009.................. 594 1,203 1,651 43 66 1,427 1,224 39 28

Electricity Generators, Electric Utilities

2001.................. 373 827 646 1 43 905 48 33 1

2002.................. 365 839 670 1 43 907 49 34 --

2003.................. 356 856 672 1 42 900 58 34 1

2004.................. 354 853 680 1 41 895 61 35 1

2005.................. 347 851 719 -- 37 896 66 34 1

2006.................. 345 858 741 1 36 894 83 34 1

2007.................. 341 854 746 1 34 890 91 34 1

2008.................. 338 872 765 -- 34 886 106 34 1

2009.................. 341 868 768 -- 34 887 130 34 1

Electricity Generators, Independent Power Producers

2001.................. 100 177 295 -- 23 447 429 4 --

2002.................. 102 189 351 2 23 451 438 4 2

2003.................. 100 191 391 1 24 463 475 4 --

2004.................. 103 186 400 1 25 467 483 4 --

2005.................. 108 196 383 2 29 464 506 5 --

2006.................. 109 188 373 2 30 465 554 5 --

2007.................. 109 189 381 1 32 477 628 5 --

2008.................. 106 187 372 -- 32 481 755 5 2

2009.................. 100 189 376 1 32 485 870 5 2

Combined Heat and Power, Electric Power

2001.................. 46 14 154 3 -- 1 30 -- 1

2002.................. 47 16 170 2 -- -- 31 -- --

2003.................. 49 18 192 3 -- 1 37 -- --

2004.................. 48 17 186 4 -- 1 33 -- --

2005.................. 47 15 184 4 -- 1 36 -- --

2006.................. 50 19 177 4 -- 1 35 -- --

2007.................. 50 15 175 4 -- -- 34 -- --

2008.................. 50 14 170 3 -- -- 38 -- --

2009.................. 51 12 166 3 -- -- 41 -- --

Combined Heat and Power, Commercial1

2001.................. 20 63 127 -- -- 9 39 -- --

2002.................. 20 63 123 -- -- 10 37 -- --

2003.................. 22 65 121 -- -- 10 41 -- --

2004.................. 21 68 121 1 -- 10 42 -- --

2005.................. 20 71 113 1 -- 9 45 -- --

2006.................. 22 71 109 1 -- 9 45 -- --

2007.................. 20 68 106 1 -- 9 45 -- 1

2008.................. 20 66 106 1 -- 9 48 -- 1

2009.................. 18 70 107 1 -- 9 49 -- 1

Combined Heat and Power, Industrial1

2001.................. 106 79 354 31 -- 59 126 -- 12

2002.................. 99 79 335 35 -- 58 129 -- 24

2003.................. 102 76 320 35 -- 51 134 -- 24

2004.................. 100 77 290 39 -- 52 133 -- 25

2005.................. 98 77 272 37 -- 52 130 -- 26

2006.................. 91 79 263 38 -- 52 128 -- 26

2007.................. 87 72 251 39 -- 48 133 -- 22

2008.................. 85 66 240 39 -- 47 133 -- 25

2009.................. 84 64 234 38 -- 46 134 -- 24



1 Small number of electricity-only, non-Combined Heat and Power plants may be included.

Note: The number of power plants for each energy source is the number of sites for which the respective energy source was reported as the most predominant energy source for at least 

one of its generators. If all generators for a site have the same energy source reported as the most predominant, that site will be counted once under that energy source. However, if the 

most predominant energy source is not the same for all generators within a site, the site is counted more than once, based on the number of most predominant energy sources for generators 

at a site. In general, this table translates the number of generators by energy source (Table 1.2) into the number of sites represented by the generators for an energy source. Therefore, the 

count for Total (All Sectors) is the sum of the counts for each sector by energy source and does not necessarily represent unique sites

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
48 U.S. Energy Information Administration/Electric Power Annual 2009

Table 5.2. Average Capacity Factors by Energy Source, 1998 through 2009 

(Percent)

Year Coal Petroleum Natural Gas 

CC1

Natural Gas 

Other Nuclear Hydroelectric 

Conventional

Other 

Renewables

All Energy 

Sources

1998................... 67.7 22.2 -- 34.2 79.2 46.6 57.0 54.6

1999................... 68.1 22.4 -- 33.2 85.3 45.9 56.9 54.9

2000................... 71.0 20.5 -- 37.1 87.7 39.5 59.1 54.6

2001................... 69.2 21.5 -- 35.7 89.4 31.4 50.2 51.4

2002 ................... 70.0 18.1 -- 38.2 90.3 38.0 54.0 49.7 

2003................... 72.0 22.4 33.5 12.1 87.9 40.0 50.0 47.7

2004................... 71.9 23.3 35.5 10.7 90.1 39.4 50.5 47.9

2005................... 73.3 23.8 36.8 10.6 89.3 39.8 47.0 48.3

2006................... 72.6 12.6 38.8 10.7 89.6 42.4 45.7 48.0

2007................... 73.6 13.4 42.0 11.4 91.8 36.3 40.0 48.7

2008................... 72.2 9.2 40.6 10.6 91.1 37.2 37.3 47.4

2009................... 63.8 7.8 42.5 9.8 90.3 39.8 33.8 44.9 1 Prior to 2003, the generation collected on Form EIA-906 did not have a distinction for combined cycle (CC) prime movers. All natural gas-fired plants of all types are included in

"Natural Gas Other" for 1998 to 2002.

Note: Technical Note: Average Capacity Factor is the ratio of actual generation to maximum potential output, expressed as a percent.

Average Capacity Factor = [(Net Generation)/(Net Summer Capacity* Number of Hours in the Year)] * 100

for the respective energy source and year

Sources: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report;" Form EIA-923, Power Plant Operations Report," and predecessor forms.
U.S. Energy Information Administration/Electric Power Annual 2009 49

Table 5.3. Average Operating Heat Rate for Selected Energy Sources, 2001 through 2009 

(Btu per Kilowatthour) 

Year Coal1 Petroleum2 Natural Gas Nuclear

2001............................................................... 10,378 10,742 10,051 10,443

2002 ............................................................... 10,314 10,641 9,533 10,442 

2003............................................................... 10,297 10,610 9,207 10,421

2004............................................................... 10,331 10,571 8,647 10,427

2005............................................................... 10,373 10,631 8,551 10,436

2006............................................................... 10,351 10,809 8,471 10,436

2007............................................................... 10,375 10,794 8,403 10,485

2008............................................................... 10,378 11,015 8,305 10,453

2009............................................................... 10,414 11,002 8,157 10,460 1 Includes anthracite, bituminous, subbituminous and lignite coal. Waste coal and synthetic coal are included starting in 2002. 2 Includes distillate fuel oil (all diesel and No. 1 and No. 2 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil, jet fuel, kerosene, petroleum coke, and waste oil.

Notes: • Included in the calculation for coal, petroleum, and natural gas average operating heat rate are electric power plants in the utility and independent power producer sectors. • 

Combined heat and power plants, and all plants in the commercial and industrial sectors are excluded from the calculations. • The nuclear average heat rate is the weighted average tested 

heat rate for nuclear units as reported on the Form EIA-860. 

Technical Note: The average operating heat rate for coal, petroleum and natural gas displayed in Table 5.3 is calculated by dividing the energy consumed (in BTUs) to generate 

electricity by the kilowatthours of power generated as reported on the Form EIA-923 and its predecessor forms. Included in the calculation for coal, petroleum and natural gas are utility 

and independent power producer plants. The calculation excludes combined heat and power plants, industrial plants, and commercial sector plants. The nuclear heat rate is a weighted 

average (by capacity) of the tested heat rate as reported on the Form EIA-860. 

Sources: U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report," and predecessor form(s) including U.S. Energy Information Administration, Form 

EIA-906, "Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report."
50 U.S. Energy Information Administration/Electric Power Annual 2009

Table 5.4. Average Heat Rates by Prime Mover and Energy Source, 2009 

(Btu per Kilowatthour) 

Prime Mover Coal Petroleum Natural Gas Nuclear

Steam Turbine.............................................. 10,148 10,351 10,399 10,460

Gas Turbine ................................................. -- 13,343 11,497 --

Internal Combustion..................................... -- 10,262 9,973 --

Combined Cycle .......................................... W 10,709 7,543 -- 

W = Withheld to avoid disclosure of individual company data.

Notes: • See Glossary reference for definitions. • Totals may not equal sum of components because of independent rounding. • Heat rate is reported at full load conditions for electric 

utilities and independent power producers. 

Technical Note: The heat rates reported on Form EIA-860 are weighted by Net Summer Capacity.

Average Heat Rate = Sum of [ Reported Heat Rate * (NSC/Total Capacity)] where 

NSC = Net Summer Capacity, and

Total Capacity = Sum of [NSC] of units for the respective prime mover and energy source categories.

Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
U.S. Energy Information Administration/Electric Power Annual 2009 51

Table 5.5. Planned Transmission Capacity Additions, by High-Voltage Size, 2010 through 2016

(Circuit Miles of Transmission)

Voltage Circuit Miles

Type Operating 

(kV) 2010 2011 2012 2013 2014 2015 2016

AC ..................................... 230 725 1,126 855 711 529 671 118

AC ..................................... 345 804 767 1,576 3,478 1,300 589 345

AC ..................................... 500 421 336 1,400 1,314 1,512 2,090 1,688 

AC ..................................... 765 -- -- -- -- 275 -- --

AC Total ........................... 1,950 2,230 3,831 5,503 3,616 3,350 2,151

DC ..................................... 100-299 -- -- -- -- -- -- --

DC ..................................... 300-399 -- -- -- -- -- -- --

DC ..................................... 400-599 -- -- -- -- -- 620 1,300

DC Total ........................... -- -- -- -- -- 620 1,300 

Grand Total...................... 1,950 2,230 3,831 5,503 3,616 3,970 3,451

Lines taken out of service 318 112 30 132 51 -- 116

Notes: • Circuit miles do not equal physical miles on the ground; the reference terminology for that concept is structural mile. • More than one circuit can be present on a structure. • Some 

structures were designed and then built to carry future transmission circuits in order to handle expected growth in new capability requirements. • Lines are taken out of service for a variety 

of reasons including intentional changes to the right-of-way to better use available land for different levels of voltage and types of poles and towers.

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program Report."
52 U.S. Energy Information Administration/Electric Power Annual 2009

Chapter 6. Trade
U.S. Energy Information Administration/Electric Power Annual 2009 53

Table 6.1. Electric Power Industry - Electricity Purchases, 1998 through 2009 

(Thousand Megawatthours) 

2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

U.S. Total..................... 5,028,647 5,612,781 5,411,422 5,502,584 6,092,285 6,998,549 6,979,669 8,754,807 7,555,276 2,345,540 2,039,969 2,020,622

Electric Utilities............ 2,364,648 2,483,927 2,504,002 2,605,315 2,760,043 2,725,694 2,610,525 2,620,712 3,045,854 2,250,382 1,949,574 1,927,198

Energy-Only 

Providers....................... 2,564,407 3,024,730 2,805,833 2,793,288 3,250,298 4,170,331 4,264,102 6,050,159 4,412,064 NA NA NA

IPP................................ 27,922 25,431 24,942 26,628 12,201 24,258 37,921 15,801 97,3571 10,622 4,358 4,089

CHP .............................. 71,669 78,693 76,646 77,353 69,744 78,267 67,122 68,135 NA 84,536 86,037 89,334

1 For 2001, CHP purchases are combined with IPP data above.

NA = Not available. 

R = Revised. 

Notes: • Energy-only providers are wholesale and retail power marketers. • IPP are independent power producers and CHP are combined heat and power producers. • Totals may not equal 

sum of components because of independent rounding. • The data collection instrument was changed in 2001 to collect data at the corporate level, rather than the plant level. As a result, 

comparisons with data prior to 2001 and after 2001 should be done with caution.

Sources: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report." For unregulated entities prior to 2001. Form EIA-860B, "Annual Electric 

Generator Report - Nonutility," and predecessor forms; and Form EIA-923, "Power Plant Operations Report" for 2007 and predecessor form(s) for earlier years.

Table 6.2. Electric Power Industry - Electricity Sales for Resale, 1998 through 2009 

(Thousand Megawatthours) 

2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

U.S. Total..................... 5,065,031 5,680,733 5,479,394 5,493,473 6,071,659 6,758,975 6,920,954 8,568,678 7,345,319 2,355,154 1,998,090 1,921,858

Electric Utilities............ 1,495,636 1,576,976 1,603,179 1,698,389 1,925,710 1,923,440 1,824,030 1,838,901 2,146,689 1,715,582 1,635,614 1,664,081

Energy-Only 

Providers....................... 2,240,399 2,718,661 2,476,740 2,446,104 2,867,048 3,756,175 3,906,220 5,757,283 4,386,632 NA NA NA

IPP................................ 1,295,857 1,355,017 1,368,310 1,321,342 1,252,796 1,053,364 1,156,796 943,531 811,9981 611,150 335,122 228,617

CHP .............................. 33,139 30,079 31,165 27,638 26,105 25,996 33,909 28,963 NA 28,421 27,354 29,160

1 For 2001, CHP sales are combined with IPP data above.

NA = Not available. 

R = Revised. 

Notes: • Energy-only providers are wholesale and retail power marketers. • IPP are independent power producers and CHP are combined heat and power producers. • The data collection 

instrument was changed in 2001 to collect data at the corporate level, rather than the plant level. As a result, comparisons with data prior to 2001, and after 2001 should be done with 

caution. • Totals may not equal sum of components because of independent rounding.

Sources: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report." For unregulated entities prior to 2001. Form EIA-860B, "Annual Electric 

Generator Report - Nonutility," and predecessor forms; and Form EIA-923, "Power Plant Operations Report" for 2007 and predecessor form(s) for earlier years.

Table 6.3. Electric Power Industry - U.S. Electricity Imports from and Electricity Exports to Canada 

and Mexico, 1998 through 2009 

(Megawatthours) 

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Electricity Imports and Exports

Canada 

Imports.................... 51,108,502 55,732,400R 50,118,056 41,544,052 42,332,039R 33,007,487 29,324,625 36,536,479 38,401,598 48,515,476 42,911,308 39,502,108 

Exports.................... 17,490,264 23,499,445R 19,559,417 23,405,387 18,680,237R 22,482,109 23,584,513 15,231,079 16,105,612 12,684,706 12,953,488 11,683,276 

Mexico

Imports1 .................. 1,082,093 1,286,981R 1,277,644 1,147,258 1,597,275 1,202,576 1,069,926 242,596 98,649 76,800 303,439 11,249

Exports.................... 647,720 698,714R 584,176 865,948 470,731 415,754 390,190 564,603 367,680 2,144,676 1,268,284 1,973,203 

Total Imports ........ 52,190,595 57,019,381R 51,395,702 42,691,310 43,929,314R 34,210,063 30,394,551 36,779,077 38,500,247 48,592,276 43,214,747 39,513,357 

Total Exports......... 18,137,984 24,198,159R 20,143,592 24,271,335 19,150,968R 22,897,863 23,974,703 15,795,681 16,473,292 14,829,382 14,221,772 13,656,479 

 1 Includes contract terminations in 2000.

R = Revised. 

Note: Totals may not equal sum of components because of independent rounding.

Sources: DOE, Office of Electricity Delivery and Energy Reliability, Form OE-781R, " Annual Report of International Electric Export/Import Data," predecessor forms, and National 

Energy Board of Canada. • For 2001 forward, data from the California Independent System Operator are used in combination with the Form OE-781R values to estimate electricity trade 

with Mexico.
54 U.S. Energy Information Administration/Electric Power Annual 2009

Chapter 7. Retail Customers, Sales, and Revenue
U.S. Energy Information Administration/Electric Power Annual 2009 55

Table 7.1. Number of Ultimate Customers Served by Sector, by Provider, 1998 through 2009 

(Number)

Period Residential Commercial Industrial Transportation Other All Sectors

Total Electric Industry

1998............................ 109,048,343 13,887,066 539,903 NA 932,838 124,408,150

1999............................ 110,383,238 14,073,764 552,690 NA 935,311 125,945,003

2000............................ 111,717,711 14,349,067 526,554 NA 974,185 127,567,517

2001............................ 114,890,240 14,867,490 571,463 NA 1,030,046 131,359,239

2002 ............................ 116,622,037 15,333,700 601,744 NA 1,066,554 133,624,035 

2003............................ 117,280,481 16,549,519 713,221 1,127 NA 134,544,348

2004............................ 118,763,768 16,606,783 747,600 1,025 NA 136,119,176

2005 ............................ 120,760,839 16,871,940 733,862 518 NA 138,367,159 

2006............................ 122,471,071 17,172,499 759,604 791 NA 140,403,965

2007............................ 123,949,916 17,377,219 793,767 750 NA 142,121,652

2008 ............................ 124,937,469 17,562,726 774,713 727 NA 143,275,635 

2009............................ 125,177,175 17,561,661 757,519 705 NA 143,497,060

Full-Service Providers1

1998 ............................ 108,736,845 13,832,662 538,167 NA 932,838 124,040,512 

1999............................ 109,817,057 13,963,937 527,329 NA 934,260 125,242,583

2000............................ 110,505,820 14,058,271 512,551 NA 953,756 126,030,398

2001 ............................ 112,472,629 14,364,578 553,280 NA 1,004,027 128,394,514 

2002............................ 113,790,812 14,899,747 586,217 NA 1,035,604 130,312,380

2003 ............................ 115,029,545 16,136,616 695,616 1,042 NA 131,862,819 

2004............................ 116,325,747 16,161,269 733,809 941 NA 133,221,766

2005............................ 118,469,928 16,389,549 719,219 496 NA 135,579,192

2006............................ 120,677,627 16,673,766 745,645 764 NA 138,097,802

2007 ............................ 121,782,003 16,767,635 771,637 710 NA 139,321,985 

2008............................ 122,595,644 16,952,660 756,294 664 NA 140,305,262

2009 ............................ 122,533,414 16,866,476 737,059 659 NA 140,137,608 

Energy-Only Providers

1998............................ 311,498 54,404 1,736 NA 0 367,638

1999 ............................ 566,181 109,827 25,361 NA 1,051 702,420 

2000............................ 1,211,891 290,796 14,003 NA 20,429 1,537,119

2001............................ 2,417,611 502,912 18,183 NA 26,019 2,964,725

2002 ............................ 2,831,225 433,953 15,527 NA 30,950 3,311,655 

2003............................ 2,250,936 412,903 17,605 85 NA 2,681,529

2004............................ 2,438,021 445,514 13,791 84 NA 2,897,410

2005 ............................ 2,290,911 482,391 14,643 22 NA 2,787,967 

2006............................ 1,793,444 498,733 13,959 27 NA 2,306,163

2007............................ 2,167,913 609,584 22,130 40 NA 2,799,667

2008 ............................ 2,341,825 610,066 18,419 63 NA 2,970,373 

2009............................ 2,643,761 695,185 20,460 46 NA 3,359,452

1 Pursuant to applicable Texas statutes establishing competitive electricity markets within the Electric Reliability Council of Texas, all customers served by Retail Energy Providers must 

be provided bundled energy and delivery services, so they are included under "Full-Service Providers."

NA = Not available. 

Notes: • See Technical Notes reference for definitions. • Full-Service Providers sell bundled electricity services (e.g., both energy and delivery) to end users. Full-Service Providers may 

purchase electricity from others (such as Independent Power Producers or other Full-Service Providers) prior to delivery. Direct sales from independent facility generators to end use 

consumers are reported under Full-Service Providers. Energy-Only Providers sell energy to end use customers; incumbent utility distribution firms provide Delivery-Only Services for 

these customers.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
U.S. Energy Information Administration/Electric Power Annual 2009 56

Figure 7.1. U.S. Electric Industry Total Ultimate Customers by State, 2009
U.S. Energy Information Administration/Electric Power Annual 2009 57

Table 7.2. Retail Sales and Direct Use of Electricity to Ultimate Customers by Sector, by Provider, 

1998 through 2009 

(Megawatthours) 

Period

Sales

Direct Use1

Total 

End Use Residential Commercial Industrial Transportation Other Total

Total Electric Industry

1998............ 1,130,109,120 979,400,928 1,051,203,115 NA 103,517,589 3,264,230,752 160,865,884 3,425,096,636

1999............ 1,144,923,069 1,001,995,720 1,058,216,608 NA 106,951,684 3,312,087,081 171,629,285 3,483,716,366

2000............ 1,192,446,491 1,055,232,090 1,064,239,393 NA 109,496,292 3,421,414,266 170,942,509 3,592,356,775

2001 ............ 1,201,606,593 1,083,068,516 996,609,310 NA 113,173,685 3,394,458,104 162,648,615 3,557,106,719 

2002............ 1,265,179,869 1,104,496,607 990,237,631 NA 105,551,904 3,465,466,011 166,184,296 3,631,650,307

2003............ 1,275,823,910 1,198,727,601 1,012,373,247 6,809,728 NA 3,493,734,486 168,294,526 3,662,029,012

2004............ 1,291,981,578 1,230,424,731 1,017,849,532 7,223,642 NA 3,547,479,483 168,470,002 3,715,949,485

2005............ 1,359,227,107 1,275,079,020 1,019,156,065 7,506,321 NA 3,660,968,513 150,015,531 3,810,984,044

2006............ 1,351,520,036 1,299,743,695 1,011,297,566 7,357,543 NA 3,669,918,840 146,926,612 3,816,845,452

2007............ 1,392,240,996 1,336,315,196 1,027,831,925 8,172,595 NA 3,764,560,712 125,670,185R 3,890,230,897R

2008............ 1,379,981,104 1,335,981,135 1,009,300,309 7,699,632 NA 3,732,962,180 132,196,685R 3,865,158,865R

2009............ 1,364,474,417 1,307,167,813 917,442,063 7,780,573 NA 3,596,864,866 126,937,958 3,723,802,824

Full-Service Providers2,3

1998............ 1,127,734,988 968,528,009 1,040,037,873 NA 103,517,589 3,239,818,459 NA 3,239,818,459

1999............ 1,140,761,016 970,600,943 1,017,783,037 NA 106,754,043 3,235,899,039 NA 3,235,899,039

2000............ 1,183,137,429 1,000,865,367 1,017,722,945 NA 107,824,323 3,309,550,064 NA 3,309,550,064

2001............ 1,188,219,590 1,037,998,484 961,812,417 NA 108,632,086 3,296,662,577 NA 3,296,662,577

2002............ 1,248,349,458 1,036,366,268 937,138,192 NA 102,238,786 3,324,092,704 NA 3,324,092,704

2003............ 1,257,766,998 1,112,206,121 931,661,404 3,315,043 NA 3,304,949,566 NA 3,304,949,566

2004............ 1,272,237,425 1,116,497,417 933,529,502 3,188,466 NA 3,325,452,810 NA 3,325,452,810

2005............ 1,339,568,275 1,151,327,861 929,675,932 3,341,814 NA 3,423,913,882 NA 3,423,913,882

2006............ 1,337,837,993 1,170,661,399 939,194,648 3,040,062 NA 3,450,734,102 NA 3,450,734,102

2007............ 1,375,450,126 1,180,789,042 923,148,031 2,635,498 NA 3,482,022,697 NA 3,482,022,697

2008............ 1,362,811,730 1,152,674,093 929,246,647 2,515,304 NA 3,447,247,774 NA 3,447,247,774

2009............ 1,345,127,459 1,122,993,934 830,670,472 2,447,384 NA 3,301,239,249 NA 3,301,239,249

Energy-Only Providers

1998............ 2,374,132 10,872,919 11,165,242 NA 0 24,412,293 NA 24,412,293

1999............ 4,162,053 31,394,777 40,433,571 NA 197,641 76,188,042 NA 76,188,042

2000............ 9,309,062 54,366,723 46,516,448 NA 1,671,969 111,864,202 NA 111,864,202

2001............ 13,387,003 45,070,032 34,796,893 NA 4,541,599 97,795,527 NA 97,795,527

2002............ 16,830,411 68,130,339 53,099,439 NA 3,313,118 141,373,307 NA 141,373,307

2003............ 18,056,912 86,521,480 80,711,843 3,494,685 NA 188,784,920 NA 188,784,920

2004............ 19,744,153 113,927,314 84,320,030 4,035,176 NA 222,026,673 NA 222,026,673

2005............ 19,658,832 123,751,159 89,480,133 4,164,507 NA 237,054,631 NA 237,054,631

2006............ 13,682,043 129,082,296 72,102,918 4,317,481 NA 219,184,738 NA 219,184,738

2007............ 16,790,870 155,526,154 104,683,894 5,537,097 NA 282,538,015 NA 282,538,015

2008............ 17,169,374 183,307,042 80,053,662 5,184,328 NA 285,714,406 NA 285,714,406

2009............ 19,346,958 184,173,879 86,771,591 5,333,189 NA 295,625,617 NA 295,625,617

1 Direct Use represents commercial and industrial facility use of onsite net electricity generation; and electricity sales or transfers to adjacent or co-located facilities for which revenue 

information is not available.

2 Pursuant to applicable Texas statutes establishing competitive electricity markets within the Electric Reliability Council of Texas, all customers served by Retail Energy Providers must 

be provided bundled energy and delivery services, so are included under "Full-Service Providers." 3 These data include Facility Direct Retail Sales.

NA = Not available. 

R = Revised. 

Notes: • See Technical Notes reference for definitions. • Full-Service Providers sell bundled electricity services (e.g., both energy and delivery) to end users. Full-Service Providers may 

purchase electricity from others (such as Independent Power Producers or other Full-Service Providers) prior to delivery. Direct sales from independent facility generators to end use 

consumers are reported under Full-Service Providers. Energy-Only Providers sell energy to end use customers; incumbent utility distribution firms provide Delivery-Only Services for 

these customers.

Sources: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report;" Form EIA-923, "Power Plant Operations Report" and predecessor form(s) 

including Form EIA-906, "Power Plant Report;" Form EIA-920, "Combined Heat and Power Plant Report."
U.S. Energy Information Administration/Electric Power Annual 2009 58

Figure 7.2. U.S. Electric Industry Total Retail Sales by State, 2009 
U.S. Energy Information Administration/Electric Power Annual 2009 59

Table 7.3. Revenue from Retail Sales of Electricity to Ultimate Customers by Sector, by Provider, 

1998 through 2009 

(Million Dollars)

Period Residential Commercial Industrial Transportation Other All Sectors

Total Electric Industry1

1998............................ 93,360 72,575 47,050 NA 6,863 219,848

1999............................ 93,483 72,771 46,846 NA 6,796 219,896

2000............................ 98,209 78,405 49,369 NA 7,179 233,163

2001............................ 103,158 85,741 50,293 NA 8,151 247,343

2002............................ 106,834 87,117 48,336 NA 7,124 249,411

2003............................ 111,249 96,263 51,741 514 NA 259,767

2004............................ 115,577 100,546 53,477 519 NA 270,119

2005............................ 128,393 110,522 58,445 643 NA 298,003

2006............................ 140,582 122,914 62,308 702 NA 326,506

2007............................ 148,295 128,903 65,712 792 NA 343,703

2008............................ 155,433 138,469 68,920 827 NA 363,650

2009............................ 157,008 134,106 61,459 829 NA 353,403

Full-Service Providers2

1998............................ 93,164 71,769 46,550 NA 6,863 218,346

1999............................ 93,142 70,492 45,056 NA 6,783 215,473

2000............................ 97,086 73,704 46,465 NA 6,988 224,243

2001............................ 101,541 81,385 48,182 NA 7,766 238,874

2002............................ 104,814 80,573 44,826 NA 6,803 237,014

2003............................ 109,165 87,764 46,686 226 NA 243,841

2004............................ 113,306 89,597 47,993 238 NA 251,134

2005............................ 125,983 97,405 52,113 249 NA 275,749

2006............................ 138,608 107,432 56,385 257 NA 302,683

2007............................ 145,642 109,703 56,950 232 NA 312,527

2008............................ 152,429 115,062 61,286 250 NA 329,027

2009............................ 153,723 111,809 53,514 226 NA 319,271

Restructured Retail Service Providers3

1998............................ 196 806 500 NA NA 1,502

1999............................ 340 2,279 1,791 NA 13 4,423

2000............................ 1,123 4,702 2,904 NA 191 8,920

2001............................ 1,617 4,356 2,111 NA 385 8,469

2002............................ 2,020 6,545 3,510 NA 321 12,396

2003............................ 2,084 8,499 5,055 288 NA 15,926

2004............................ 2,272 10,949 5,484 281 NA 18,985

2005............................ 2,410 13,117 6,333 394 NA 22,254

2006............................ 1,974 15,482 5,922 445 NA 23,823

2007............................ 2,653 19,200 8,762 560 NA 31,176

2008............................ 3,004 23,407 7,635 577 NA 34,622

2009............................ 3,286 22,297 7,946 603 NA 34,132

Energy-Only Providers4

1998............................ 196 806 500 NA 0 1,502

1999............................ 340 2,279 1,791 NA 13 4,423

2000............................ 530 3,175 2,374 NA 75 6,153

2001............................ 714 2,806 1,632 NA 237 5,390

2002............................ 914 3,989 2,408 NA 143 7,454

2003............................ 980 5,210 3,605 215 NA 10,011

2004............................ 1,086 6,859 3,881 201 NA 12,027

2005............................ 1,285 8,844 4,749 308 NA 15,186

2006............................ 1,127 10,792 4,510 356 NA 16,784

2007............................ 1,646 13,553 7,197 458 NA 22,854

2008............................ 1,873 17,126 6,212 455 NA 25,667

2009............................ 1,877 15,438 6,161 460 NA 23,936

Delivery-Only Service

1998............................ -- -- -- -- -- --

1999............................ -- -- -- -- -- --

2000............................ 593 1,527 531 NA 116 2,767

2001............................ 903 1,551 479 NA 147 3,080

2002............................ 1,106 2,556 1,102 NA 178 4,942

2003............................ 1,104 3,289 1,450 72 NA 5,915

2004............................ 1,186 4,090 1,603 79 NA 6,958

2005............................ 1,125 4,273 1,584 86 NA 7,068

2006............................ 847 4,690 1,412 90 NA 7,040

2007............................ 1,007 5,647 1,565 102 NA 8,322

2008............................ 1,131 6,281 1,422 121 NA 8,956

2009............................ 1,409 6,859 1,785 143 NA 10,196

1 Sum of Full-Service Providers and Restructured Retail Service Providers.

2 Pursuant to applicable Texas statutes establishing competitive electricity markets within the Electric Reliability Council of Texas, all customers served by Retail Energy Providers must

be provided bundled energy and delivery services, so are included under "Full-Service Providers." 3 Sum of Energy-Only Providers and Delivery-Only Service.

4 From 1996 to 1999, revenue was estimated based on retail sales reported on the Form EIA-861. 

NA = Not available. 

Notes: • See Technical Notes reference for definitions. • Full-Service Providers sell bundled electricity services (e.g., both energy and delivery) to end users. Full-Service Providers may 

purchase electricity from others (such as Independent Power Producers or other Full-Service Providers) prior to delivery. Direct sales from independent facility generators to end use 

consumers are reported under Full-Service Providers. Energy-Only Providers sell energy to end use customers; incumbent utility distribution firms provide Delivery-Only Services for 

these customers. Data reported under Restructured Retail Service Providers represent the sum of Energy-Only and Delivery-Only Services. • For historical data, see the State of California 

discussion in Technical Notes. • Totals may not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
U.S. Energy Information Administration/Electric Power Annual 2009 60

Figure 7.3. U.S. Electric Industry Total Revenues by State, 2009
U.S. Energy Information Administration/Electric Power Annual 2009 61

Table 7.4. Average Retail Price of Electricity to Ultimate Customers by End-Use Sector, 1998 

through 2009 

(Cents per kilowatthour) 

Period Residential Commercial Industrial Transportation Other All Sectors

Total Electric Industry1

1998............................ 8.26 7.41 4.48 NA 6.63 6.74

1999............................ 8.16 7.26 4.43 NA 6.35 6.64

2000............................ 8.24 7.43 4.64 NA 6.56 6.81

2001............................ 8.58 7.92 5.05 NA 7.20 7.29

2002............................ 8.44 7.89 4.88 NA 6.75 7.20

2003............................ 8.72 8.03 5.11 7.54 NA 7.44

2004............................ 8.95 8.17 5.25 7.18 NA 7.61

2005............................ 9.45 8.67 5.73 8.57 NA 8.14

2006............................ 10.40 9.46 6.16 9.54 NA 8.90

2007............................ 10.65 9.65 6.39 9.70 NA 9.13

2008............................ 11.26 10.36 6.83 10.74 NA 9.74

2009............................ 11.51 10.26 6.70 10.65 NA 9.83

Full-Service Providers2

1998............................ 8.26 7.41 4.48 NA 6.63 6.74

1999............................ 8.16 7.26 4.43 NA 6.35 6.66

2000............................ 8.21 7.36 4.57 NA 6.48 6.78

2001............................ 8.55 7.84 5.01 NA 7.15 7.25

2002............................ 8.40 7.77 4.78 NA 6.65 7.13

2003............................ 8.68 7.89 5.01 6.82 NA 7.38

2004............................ 8.91 8.02 5.14 7.47 NA 7.55

2005............................ 9.40 8.46 5.61 7.45 NA 8.05

2006............................ 10.36 9.18 6.00 8.44 NA 8.77

2007............................ 10.59 9.29 6.17 8.82 NA 8.98

2008............................ 11.18 9.98 6.60 9.96 NA 9.54

2009............................ 11.43 9.96 6.44 9.22 NA 9.67

Restructured Retail Service Providers3

1998............................ 8.26 7.41 4.48 NA NA 6.15

1999............................ 8.17 7.26 4.43 NA 6.45 5.81

2000............................ 12.07 8.65 6.24 NA 11.42 7.97

2001............................ 12.08 9.67 6.07 NA 8.47 8.66

2002............................ 12.00 9.61 6.61 NA 9.69 8.77

2003............................ 11.54 9.82 6.26 8.23 NA 8.44

2004............................ 11.51 9.61 6.50 6.95 NA 8.55

2005............................ 12.26 10.60 7.08 9.47 NA 9.39

2006............................ 14.43 11.99 8.21 10.32 NA 10.87

2007............................ 15.80 12.35 8.37 10.11 NA 11.03

2008............................ 17.49 12.77 9.54 11.12 NA 12.12

2009............................ 16.98 12.11 9.16 11.31 NA 11.55

Energy-Only Providers4

1998............................ 8.26 7.41 4.48 NA -- 6.15

1999............................ 8.17 7.26 4.43 NA 6.45 5.81

2000............................ 5.69 5.84 5.10 NA 4.47 5.50

2001............................ 5.34 6.22 4.69 NA 5.23 5.51

2002............................ 5.43 5.86 4.53 NA 4.30 5.27

2003............................ 5.43 6.02 4.47 6.16 NA 5.30

2004............................ 5.50 6.02 4.60 4.99 NA 5.42

2005............................ 6.54 7.15 5.31 7.40 NA 6.41

2006............................ 8.23 8.36 6.25 8.24 NA 7.66

2007............................ 9.80 8.71 6.87 8.28 NA 8.09

2008............................ 10.91 9.34 7.76 8.79 NA 8.98

2009............................ 9.70 8.38 7.10 8.63 NA 8.10

Delivery-Only Service

1998............................ -- -- -- -- -- --

1999............................ -- -- -- -- -- --

2000............................ 6.37 2.81 1.14 -- 6.95 2.47

2001............................ 6.74 3.44 1.38 -- 3.24 3.15

2002............................ 6.57 3.75 2.08 -- 5.39 3.50

2003............................ 6.11 3.80 1.80 2.07 -- 3.13

2004............................ 6.00 3.59 1.90 1.96 NA 3.13

2005............................ 5.72 3.45 1.77 2.07 NA 2.98

2006............................ 6.19 3.63 1.96 2.08 NA 3.21

2007............................ 6.00 3.63 1.50 1.84 NA 2.95

2008............................ 6.59 3.43 1.78 2.34 NA 3.13

2009............................ 7.28 3.72 2.06 2.68 NA 3.45

1 Weighted average of Full-Service Providers and Restructured Retail Service Providers.

2 Pursuant to applicable Texas statutes establishing competitive electricity markets within the Electric Reliability Council of Texas, all customers served by Retail Energy Providers must 

be provided bundled energy and delivery services, so are included under "Full-Service Providers." 3 Sum of Energy-Only Providers and Delivery-Only Service.

4

 From 1996 to 1999, average revenue was estimated based on retail sales reported on the Form EIA-861. 

NA = Not available. 

Notes: • See Glossary reference for definitions • Full-Service Providers sell bundled electricity services (e.g., both energy and delivery) to end users. Full-Service Providers may purchase 

electricity from others (such as Independent Power Producers or other Full-Service Providers) prior to delivery. Direct sales from independent facility generators to end use consumers are 

reported under Full-Service Providers. Energy-Only Providers sell energy to end use customers; incumbent utility distribution firms provide Delivery-Only Services for these customers. 

Data reported under Restructured Retail Service Providers represent the sum of Energy-Only and Delivery-Only Services.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
U.S. Energy Information Administration/Electric Power Annual 2009 62

Figure 7.4. Average Retail Price of Electricity by State, 2009
U.S. Energy Information Administration/Electric Power Annual 2009 63

Figure 7.5. Average Residential Price of Electricity by State, 2009
U.S. Energy Information Administration/Electric Power Annual 2009 64

Figure 7.6. Average Commercial Price of Electricity by State, 2009
U.S. Energy Information Administration/Electric Power Annual 2009 65

Figure 7.7. Average Industrial Price of Electricity by State, 2009
66 U.S. Energy Information Administration/Electric Power Annual 2009

Table 7.5. Net Metering and Green Pricing Customers by End Use Sector, 2002 - 2009 

Year

Green Pricing Net Metering

Residential Non Residential Total Residential Non Residential Total

2002............ 688,069 23,481 711,550 3,559 913 4,472

2003............ 819,579 57,547 877,126 5,870 943 6,813

2004............ 864,794 63,539 928,333 14,114 1,712 15,826

2005............ 871,774 70,998 942,772 19,244 1,902 21,146

20061 .......... 606,919 35,937 642,856 30,689 2,930 33,619

2007............ 773,391 62,260 835,651 44,886 3,943 48,829

2008............ 918,284 64,711 982,995 64,400 5,609 70,009

2009............ 1,058,185 65,593 1,123,778 88,222 8,284 96,506 

1 In 2006 the single largest provider of green pricing services in the country discontinued service in two States. More than 297,600 customers in green pricing programs reverted to 

standard service tariffs, predominantly in Ohio and Pennsylvania.

Notes: • Green Pricing programs allow electricity customers the opportunity to purchase electricity generated from renewable resources, thereby encouraging renewable energy 

development. Renewable resources include solar, wind, geothermal, hydroelectric power, and wood. • Net Metering arrangements permit facilities and residences (using a meter that reads 

inflows and outflows of electricity) to sell any excess power generated over its load requirement back to the distributor to offset consumption.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
U.S. Energy Information Administration/Electric Power Annual 2009 67

Chapter 8. Revenue and Expense Statistics 
68 U.S. Energy Information Administration/Electric Power Annual 2009

Table 8.1. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities, 1998 

through 2009 

(Million Dollars)

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Utility Operating Revenues 276,124 298,962 270,964R 275,501 265,652 238,759 230,151 219,609 267,276 233,915 213,090 214,849

Electric Utility ........................... 249,303 266,124 240,864R 246,736 234,909 213,012 206,268 200,360 243,982 213,634 197,010 199,643 

Other Utility .............................. 26,822 32,838 30,100R 28,765 30,743 25,747 23,883 19,250 23,294 20,281 16,081 15,206

Utility Operating Expenses 244,243 267,263 241,198R 245,589 236,786 206,960 201,057 189,062 234,910 210,250 180,467 183,954

Electric Utility ........................... 219,544 236,572 213,076R 218,445 207,830 183,121 179,044 171,604 213,458 191,564 165,942 170,162 

Operation................................. 154,925 175,887 153,885R 158,893 150,645 131,560 125,436 116,660 161,233 132,607 107,686 109,317

Production ............................. 118,816 140,974 121,700R 127,494 120,586 103,871 98,305 90,715 135,791 107,554 82,791 84,741 

Cost of Fuel ......................... 40,242 47,337 39,548R 37,945 36,106 28,544 26,871 24,149 29,434 32,407 29,605 30,945 

Purchased Power ................. 67,630 84,724 74,112R 79,205 77,902 67,126 63,749 58,810 98,020 62,608 42,663 41,789

Other ................................... 10,970 8,937 8,058R 10,371 6,599 8,226 7,709 7,776 8,359 12,561 10,551 12,036 

Transmission ......................... 6,742 6,950 6,051R 6,179 5,664 4,531 3,653 3,560 3,385 2,713 2,480 2,177 

Distribution............................ 3,947 3,997 3,765R 3,640 3,502 3,287 3,214 3,117 3,208 3,092 2,959 2,759

Customer Accounts................ 5,203 5,286 4,652R 4,409 4,229 4,077 4,262 4,168 4,432 4,239 4,190 3,964 

Customer Service................... 3,857 3,567 2,939R 2,536 2,291 2,013 1,902 1,820 1,855 1,826 1,854 1,937 

Sales ...................................... 178 225 239R 240 219 237 238 264 282 405 474 510

Administrative and General ... 15,991 14,718 14,346R 14,580 14,130 13,537 13,863 13,018 12,292 12,768 12,950 13,204 

Maintenance ............................ 14,092 14,192 13,181R 12,838 12,033 11,743 11,340 10,861 11,154 12,064 12,359 12,356 

Depreciation ............................ 20,095 19,049 17,936R 17,373 17,123 16,322 15,981 16,199 17,476 20,636 20,232 21,287

Taxes and Other ....................... 29,081 26,202 27,000R 28,149 26,805 22,190 25,027 26,716 21,765 24,479 23,786 25,695 

Other Utility .............................. 24,698 30,692 28,122R 27,143 28,956 23,839 22,013 17,457 21,452 18,686 14,525 13,791

Net Utility Operating Income..... 31,881 31,699 29,766R 29,912 28,866 31,799 29,094 30,548 32,366 23,665 32,623 30,896

R = Revised. 

Notes: • Data for the year 2007 was updated reflecting revisions reported by Ventyx Global Energy Velocity Suite. • 2007 financial data does not include information on Entergy Gulf 

State Louisiana LLC and Entergy Texas Inc. as both were not reported on the FERC Form for that year. • Missing or erroneous respondent data may result in slight imbalances in some of 

the expense account subtotals. Totals may not equal sum of components because of independent rounding.

Source: Federal Energy Regulatory Commission, FERC Form 1, "Annual Report of Major Electric Utilities, Licensees and Others, via Ventyx Global Energy Velocity Suite."

Table 8.2. Average Power Plant Operating Expenses for Major U.S. Investor-Owned Electric 

Utilities, 1998 through 2009 

(Mills per Kilowatthour)

Plant Type 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Operation

Nuclear ............................................................. 10.00 9.89R 9.54R 9.03R 8.26R 8.97R 9.12R 9.00R 8.44R 6.03R 8.17R 9.86R

Fossil Steam...................................................... 4.23 3.72R 3.63R 3.57R 3.21R 3.13R 2.74R 2.59 2.47R 2.17R 2.16R 2.19R

Hydroelectric1................................................... 4.88 5.78 5.44 3.76 3.95 3.83R 3.47 3.71 4.27 3.52 3.35 3.09

Gas Turbine and Small Scale2 ........................... 3.05 3.77R 3.26R 3.51R 3.69R 4.27R 3.50R 3.26R 3.65R 3.93R 5.01R 4.51R

Maintenance

Nuclear ............................................................. 6.34 6.20 5.79 5.69 5.27 5.38R 5.23 5.04 5.02 4.96 5.01 5.77

Fossil Steam...................................................... 3.96 3.59 3.37 3.19 2.98 2.96R 2.72 2.67 2.61 2.42 2.46 2.41

Hydroelectric1 ................................................... 3.50 3.89 3.87 2.70 2.73 2.76R 2.32 2.62 2.89 2.22 2.03 1.58

Gas Turbine and Small Scale2 ........................... 2.58 2.72 2.42 2.16 1.89 2.14R 2.26 2.38 3.33 3.26 4.78 3.42

Fuel

Nuclear ............................................................. 5.35 5.29 4.99 4.85 4.63 4.58R 4.60 4.60 4.67 4.90 5.16 5.39

Fossil Steam...................................................... 32.30 28.43 23.88 23.09 21.69 18.21R 17.29 16.09 18.15 17.73 15.50 15.86

Hydroelectric1 ................................................... -- -- -- -- -- -- -- -- -- -- -- --

Gas Turbine and Small Scale2

........................... 51.93 64.23 58.75 53.89 55.52 45.18R 43.89 31.84 43.55 41.76 27.95 22.85 

Total

Nuclear ............................................................. 21.69 21.37R 20.32R 19.57R 18.15R 18.93R 18.95R 18.65R 18.13R 15.89R 18.35R 21.02R

Fossil Steam...................................................... 40.48 35.75R 30.88R 29.85R 27.88R 24.31R 22.75R 21.36 23.23R 22.32R 20.12R 20.45R

Hydroelectric1 ................................................... 8.38 9.67 9.32 6.46 6.68 6.60R 5.79 6.33 7.16 5.74 5.38 4.67

Gas Turbine and Small Scale2 ........................... 57.55 70.72R 64.43R 59.56R 61.10R 51.59R 49.66R 37.47R 50.53R 48.94R 37.74R 30.79R

 1 Conventional hydro and pumped storage.

2 Gas turbine, internal combustion, photovoltaic, and wind plants.

R = Revised. 

Notes: • Data for the years 1998 - 2008 were updated reflecting revisions reported by Ventyx Global Energy Velocity Suite. • Expenses are average expenses weighted by net generation. • 

A mill is a monetary cost and billing unit equal to 1/1000 of the U.S. dollar (equivalent to 1/10 of one cent). • Totals may not equal sum of components because of independent rounding.

Source: Federal Energy Regulatory Commission, FERC Form 1, "Annual Report of Major Electric Utilities, Licensees and Others via Ventyx Global Energy Velocity Suite."
U.S. Energy Information Administration/Electric Power Annual 2009 69

Table 8.3. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (With 

Generation Facilities), 1998 through 2009 

(Million Dollars)

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Operating Revenue - Electric....... NA NA NA NA NA NA 33,906 32,776 38,028 31,843 26,767 26,155

Operating Expenses - Electric...... NA NA NA NA NA NA 29,637 28,638 32,789 26,244 21,274 20,880 

Operation Including Fuel............. NA NA NA NA NA NA 22,642 21,731 25,922 19,575 15,386 15,120 

Production ................................. NA NA NA NA NA NA 17,948 17,176 21,764 15,742 11,923 11,608

Transmission ............................. NA NA NA NA NA NA 872 858 785 781 732 773

Distribution................................ NA NA NA NA NA NA 696 680 605 574 516 603

Customer Accounts.................... NA NA NA NA NA NA 582 537 600 507 415 390

Customer Service....................... NA NA NA NA NA NA 280 315 263 211 160 127

Sales .......................................... NA NA NA NA NA NA 84 74 73 66 49 51

Administrative and General ....... NA NA NA NA NA NA 2,180 2,090 1,832 1,695 1,591 1,567

Maintenance................................... NA NA NA NA NA NA 2,086 1,926 1,904 1,815 1,686 1,631 

Depreciation and Amortization .... NA NA NA NA NA NA 3,844 3,907 4,009 3,919 3,505 3,459

Taxes and Tax Equivalents ........... NA NA NA NA NA NA 1,066 1,074 954 936 697 670 

Net Electric Operating Income ..... NA NA NA NA NA NA 4,268 4,138 5,238 5,598 5,493 5,275 



NA = Not available. 

Notes: • In 2004, Form EIA-412 was terminated. • Totals may not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, EIA Form-412, "Annual Electric Industry Financial Report," and predecessor forms.

Table 8.4. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (Without 

Generation Facilities), 1998 through 2009 

(Million Dollars)

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Operating Revenue - Electric ....... NA NA NA NA NA NA 12,454 11,546 10,417 9,904 9,354 8,790

Operating Expenses - Electric ...... NA NA NA NA NA NA 11,481 10,703 9,820 9,355 8,737 8,245 

Operation Including Fuel ............. NA NA NA NA NA NA 10,095 9,439 8,864 8,424 7,874 7,437 

Production ................................. NA NA NA NA NA NA 8,865 8,311 7,863 7,486 7,015 6,661

Transmission.............................. NA NA NA NA NA NA 105 93 61 64 48 44

Distribution................................ NA NA NA NA NA NA 348 320 311 280 261 230

Customer Accounts.................... NA NA NA NA NA NA 172 163 164 155 143 130

Customer Service....................... NA NA NA NA NA NA 31 39 26 22 22 21

Sales .......................................... NA NA NA NA NA NA 11 10 15 16 14 9

Administrative and General ....... NA NA NA NA NA NA 562 504 423 402 371 342

Maintenance .................................. NA NA NA NA NA NA 418 389 304 286 272 263 

Depreciation and Amortization.... NA NA NA NA NA NA 711 631 405 394 369 330

Taxes and Tax Equivalents .......... NA NA NA NA NA NA 257 244 247 251 223 215 

Net Electric Operating Income .... NA NA NA NA NA NA 974 843 597 549 617 545 



NA = Not available. 

Notes: • In 2004, Form EIA-412 was terminated. • Totals may not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, EIA Form-412, "Annual Electric Industry Financial Report," and predecessor forms.
70 U.S. Energy Information Administration/Electric Power Annual 2009

Table 8.5. Revenue and Expense Statistics for U.S. Federally Owned Electric Utilities, 1998 through 

2009

(Million Dollars) 

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Operating Revenue - Electric.......................... NA NA NA NA NA NA 11,798 11,470 12,458 10,685 10,186 9,780

Operating Expenses - Electric......................... NA NA NA NA NA NA 8,763 8,665 10,013 8,139 7,775 7,099 

Operation Including Fuel................................ NA NA NA NA NA NA 6,498 6,419 7,388 5,873 5,412 5,184 

Production .................................................... NA NA NA NA NA NA 5,175 5,236 6,247 5,497 4,890 4,735

Transmission ................................................ NA NA NA NA NA NA 307 244 354 332 349 323

Distribution................................................... NA NA NA NA NA NA 1 11222

Customer Accounts....................................... NA NA NA NA NA NA 4 10 16 6 1 1

Customer Service.......................................... NA NA NA NA NA NA 63 60 60 48 50 51

Sales ............................................................. NA NA NA NA NA NA 20 6 6 10 28 14

Administrative and General .......................... NA NA NA NA NA NA 927 862 705 467 528 535

Maintenance..................................................... NA NA NA NA NA NA 600 566 521 488 436 476 

Depreciation and Amortization ...................... NA NA NA NA NA NA 1,335 1,351 1,790 1,471 1,623 1,175

Taxes and Tax Equivalents ............................. NA NA NA NA NA NA 329 328 315 308 304 264 

Net Electric Operating Income ....................... NA NA NA NA NA NA 3,035 2,805 2,445 2,546 2,411 2,681 



NA = Not available. 

Notes: • In 2004, Form EIA-412 was terminated. • Totals may not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-412, "Annual Electric Industry Financial Report," and predecessor forms.

Table 8.6. Revenue and Expense Statistics for U.S. Cooperative Borrower Owned Electric Utilities, 

1998 through 2009 

(Million Dollars)

Description 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Operating Revenue - Electric .................... 42,189 42,087R 38,208 36,723 34,088 30,650 29,228 27,458 26,458 25,629 23,824 23,988 

Operation and Maintenance Expenses ..... 38,337 38,511R 34,843 33,550 31,209 27,828 26,361 24,561 23,763 22,982 21,283 21,223 

Operation Including Fuel .......................... 35,412 35,782R 32,229 30,920 28,723 25,420 24,076 22,383 21,703 20,942 19,336 19,280 

Production .............................................. 29,462 30,107R 26,929 25,799 23,921 20,752 19,559 18,143 17,714 17,080 15,706 15,683 

Transmission........................................... 862 799 754 748 679 665 637 579 524 525 466 452

Distribution............................................. 2,395 2,327R 2,161 2,037 1,895 1,860 1,787 1,681 1,589 1,530 1,451 1,440

Customer Accounts................................. 741 714R 677 655 612 595 579 545 532 487 455 446

Customer Service.................................... 186 176 163 158 147 141 140 136 119 133 132 132

Sales ....................................................... 81 81 78 80 76 80 79 79 88 82 81 77

Administrative and General .................... 1,686 1,577R 1,468 1,444 1,393 1,327 1,295 1,219 1,137 1,104 1,045 1,050

Depreciation and Amortization................. 2,656 2,462R 2,350 2,367 2,253 2,182 2,076 1,992 1,895 1,820 1,747 1,732 

Taxes and Tax Equivalents ....................... 269 267R 264 262 234 226 209 186 164 220 200 211

Net Electric Operating Income ................. 3,852 3,576R 3,365 3,173 2,879 2,822 2,867 2,897 2,696 2,647 2,541 2,764 



R = Revised. 

Note: Totals may not equal sum of components because of independent rounding.

Source: U.S. Department of Agriculture, Rural Utilities Service (prior Rural Electrification Administration), Statistical Report, Rural Electric Borrowers publications, as compiled from 

RUS Form 7 and RUS Form 12.
U.S. Energy Information Administration/Electric Power Annual 2009 71

Chapter 9. Demand-Side Management
72 U.S. Energy Information Administration/Electric Power Annual 2009

Table 9.1. Demand-Side Management Actual Peak Load Reductions by Program Category, 1998 

through 2009 

(Megawatts)

Item 2009 2008R 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Total Actual Peak Load Reduction........................ 31,682 31,735 30,253 27,240 25,710 23,532 22,904 22,936 24,955 22,901 26,455 27,231

Energy Efficiency................................................ 19,766 19,707 17,710 15,959 15,351 14,272 13,581 13,420 13,027 12,873 13,452 13,591

Load Management ............................................... 11,916 12,028 12,543 11,281 10,359 9,260 9,323 9,516 11,928 10,027 13,003 13,640

R = Revised. 

Notes: • Data presented are reflective of large utilities. • See Technical Notes for the Demand-Side Management definitions located within the Form EIA-861 section. • Totals may not 

equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 9.2. Demand-Side Management Program Annual Effects by Program Category, 1998 through 

2009

Item 2009 2008R 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Annual Effects – Energy Efficiency

Large Utilities

Actual Peak Load Reduction (MW)..................... 19,766 19,707 17,710 15,959 15,351 14,272 13,581 13,420 13,027 52,827 49,691 48,775

Energy Savings (Thousand MWh) ...................... 76,891 74,861 67,134 62,951 58,891 52,662 48,245 52,285 52,946 12,873 13,452 13,591

Annual Effects – Load Management

Large Utilities

Actual Peak Load Reduction (MW)..................... 11,916 12,028 12,543 11,281 10,359 9,260 9,323 9,516 11,928 10,027 13,003 13,640

Potential Peak Load Reductions (MW) ............... 26,178 26,246 23,087 21,270 21,282 20,998 25,290 26,888 27,730 28,496 30,118 27,840

Energy Savings (Thousand MWh) ...................... 1,015 1,813 1,857 865 1,006 2,047 2,020 1,790 990 875 872 392

R = Revised. 

Notes: • See Technical Notes for the Demand-Side Management definitions located within the Form EIA-861 section. • Totals may not equal sum of components because of independent 

rounding.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 9.3. Demand-Side Management Program Incremental Effects by Program Category, 1998 

through 2009 

Item 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Incremental Effects – Energy Efficiency

Large Utilities

Actual Peak Load Reduction (MW)..................... 2,941 5,764R 1,649 1,177 1,403 1,521 945 1,054 999 720 695 796

Energy Savings (Thousand MWh)....................... 12,698 10,407R 7,426 5,385 5,872 4,522 2,939 3,543 4,402 3,284 3,027 3,324

Small Utilities

Actual Peak Load Reduction (MW)..................... 777 567 349 91 302 204 90 49 20 25 22 12

Energy Savings (Thousand MWh)....................... 209 21 254 9 7 10 8 192 8 8 8 37

Incremental Effects – Load Management

Large Utilities

Actual Peak Load Reduction (MW) .................... 2,152 2,923R 1,356 1,495 1,009 907 1,084 1,160 1,297 919 1,568 1,821

Potential Peak Load Reductions (MW)................ 5,811 6,636R 3,342 2,544 2,005 2,622 1,981 2,655 2,448 2,439 6,457 2,832

Energy Savings (Thousand MWh)....................... 65 167R 132 95 133 2 29 65 79 63 67 37

Small Utilities

Actual Peak Load Reduction (MW) .................... 75 371 1,036 195 153 242 81 54 45 137 54 124

Potential Peak Load Reductions (MW) ............... 232 620 1,423 273 218 422 131 76 177 190 84 160

Energy Savings (Thousand MWh)....................... 1 1 5 4 5 4 4 2 4 9 2 7

R = Revised. 

Notes: • See Technical Notes for the Demand-Side Management definitions located within the Form EIA-861 section. • Totals may not equal sum of components because of independent 

rounding.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
U.S. Energy Information Administration/Electric Power Annual 2009 73

Table 9.4. Demand-Side Management Program Annual Effects by Sector, 1998 through 2009 

Item 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Actual Peak Load Reductions (MW) 

Large Utilities

Residential....................................... 12,605 12,910R 13,192 10,730 9,432 8,870 9,431 9,137 9,619 9,446 9,976 9,327

Commercial ..................................... 11,399 11,097R 8,054 7,779 7,926 7,194 6,774 6,839 8,210 6,987 7,777 9,482

Industrial ......................................... 7,666 7,602R 8,990 8,692 8,343 7,454 6,594 6,500 6,553 6,141 6,360 7,927

Transportation ................................. 12 126 17 39 9 14 105 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA 460 573 327 2,342 495

Total .......................................... 31,682 31,735R 30,253 27,240 25,710 23,532 22,904 22,936 24,955 22,901 26,455 27,231

Potential Peak Load Reductions (MW)

Large Utilities

Residential....................................... 15,986 16,831R 15,263 13,040 12,097 11,967 12,525 12,072 12,274 12,970 12,812 13,022

Commercial ..................................... 14,366 13,850R 10,201 10,006 10,214 9,624 8,943 9,298 10,469 9,114 8,868 12,210

Industrial ......................................... 15,502 15,103R 15,271 14,119 14,260 13,665 17,298 18,321 17,344 18,775 17,237 15,512

Transportation ................................. 90 169 62 64 62 14 105 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA 617 670 510 4,653 686

Total .......................................... 45,944 45,953R 40,797 37,229 36,633 35,270 38,871 40,308 40,757 41,369 43,570 41,430

Energy Savings (Thousand MWh)

Large Utilities

Residential....................................... 27,811 26,534R 23,688 21,437 19,255 17,763 13,469 15,438 16,027 16,287 16,263 16,564

Commercial ..................................... 35,019 34,869R 30,725 28,982 28,416 24,624 25,089 24,391 24,217 25,660 23,375 25,125

Industrial ......................................... 15,002 15,196R 14,470 13,348 12,178 12,273 11,156 11,339 10,487 9,160 8,156 3,347

Transportation ................................. 76 76 109 50 48 51 551 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA 2,907 3,206 2,593 2,770 831

Total .......................................... 77,907 76,674R 68,992 63,817 59,897 54,710 50,265 54,075 53,936 53,701 50,563 49,167

NA = Not available. 

R = Revised. 

Notes: • See Technical Notes for the Demand-Side Management definitions located within the Form EIA-861 section. • Totals may not equal sum of components because of independent 

rounding.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
74 U.S. Energy Information Administration/Electric Power Annual 2009

Table 9.5. Demand-Side Management Program Incremental Effects by Sector, 1998 through 2009 

Item 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Actual Peak Load Reductions (MW)

Large Utilities

Residential....................................... 2,055 5,507R 1,344 1,012 966 1,361 640 895 790 572 605 599

Commercial ..................................... 1,598 2,329R 983 759 715 560 528 527 742 515 684 1,176

Industrial ......................................... 1,436 849R 677 901 731 507 849 680 640 502 929 799

Transportation ................................. 4 2 1 0 0 0 12 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA 112 124 50 45 43

Total .......................................... 5,093 8,687R 3,005 2,672 2,412 2,428 2,029 2,214 2,296 1,640 2,263 2,617

Small Utilities

Residential....................................... 586 220 871 131 325 280 88 48 32 37 27 35

Commercial ..................................... 226 287 342 63 71 126 58 41 15 37 22 34

Industrial ......................................... 40 431 130 92 59 40 25 12 16 62 7 56

Transportation ................................. 0 0 42 0 0 0 0 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA 0 0 26 19 10

Total .......................................... 852 938 1,385 286 455 446 171 101 63 162 76 136

U.S. Total............................................. 5,945 9,625R 4,390 2,958 2,867 2,874 2,200 2,317 2,361 1,802 2,339 2,753

Potential Peak Load Reductions (MW)

Large Utilities

Residential....................................... 3,118 7,246R 2,374 1,406 1,311 1,680 752 1,311 900 699 753 751

Commercial ..................................... 2,762 3,025R 1,574 1,114 1,098 894 602 751 1,115 565 718 1,863

Industrial ......................................... 2,849 2,127R 1,042 1,201 999 1,569 1,551 1,506 1,277 1,815 5,612 1,438

Transportation ................................. 23 2 1 0 0 0 21 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA 141 155 79 68 76

Total .......................................... 8,752 12,400R 4,991 3,721 3,408 4,143 2,926 3,709 3,447 3,159 7,151 3,628

Small Utilities

Residential....................................... 653 315 962 164 367 395 116 64 158 55 41 49

Commercial ..................................... 251 304 513 95 100 154 73 43 19 51 25 41

Industrial ......................................... 105 568 243 105 53 77 32 15 18 64 9 70

Transportation ................................. 0 0 54 0 0 0 0 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA 3 2 44 31 12

Total .......................................... 1,009 1,187 1,772 364 520 626 221 125 197 215 106 172

U.S. Total............................................. 9,761 13,587R 6,763 4,085 3,928 4,769 3,147 3,834 3,644 3,374 7,257 3,800

Energy Savings (Thousand MWh)

Large Utilities

Residential....................................... 4,867 4,584R 3,515 2,141 2,276 1,842 868 1,203 1,365 856 990 909

Commercial ..................................... 4,975 4,440R 2,831 2,339 2,638 1,815 1,356 1,583 1,867 1,780 1,502 1,703

Industrial ......................................... 2,920 1,549R 1,199 999 1,090 867 732 706 872 547 475 645

Transportation ................................. 1 1 13 0 * 0 12 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA 116 376 164 127 104

Total .......................................... 12,763 10,574R 7,558 5,479 6,004 4,524 2,968 3,608 4,481 3,347 3,094 3,361

Small Utilities

Residential....................................... 197 16 157 9 6 6 7 45 5 9 4 8

Commercial ..................................... 5 4 98 3 5 7 5 148 3 4 3 6

Industrial ......................................... 8 2 4 1*2122113

Transportation ................................. * * 0 0 0 0 0 NA NA NA NA NA

Other ............................................... NA NA NA NA NA NA NA * 3311

Total .......................................... 210 22 259 13 12 14 13 194 13 17 9 18

U.S. Total............................................. 12,972 10,596R 7,817 5,492 6,016 4,539 2,981 3,802 4,492 3,364 3,103 3,379

* = Value is less than half of the smallest unit of measure.

NA = Not available. 

R = Revised. 

Notes: • See Technical Notes for the Demand-Side Management definitions located within the Form EIA-861 section. • Totals may not equal sum of components because of independent 

rounding.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
U.S. Energy Information Administration/Electric Power Annual 2009 75

Table 9.6. Demand-Side Management Program Energy Savings, 1998 through 2009 

(Thousand Megawatthours) 

Item 2009 2008R 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Total Energy Savings......................... 77,907 76,674 68,992 63,817 59,897 54,710 50,265 54,075 53,936 53,701 50,563 49,167

Energy Efficiency................................ 76,891 74,861 67,134 62,951 58,891 52,662 48,245 52,285 52,946 52,827 49,691 48,775

Load Management ............................... 1,015 1,813 1,857 865 1,006 2,047 2,020 1,790 990 875 872 392



R = Revised. 

Notes: • Data presented are reflective of large utilities. • Totals may not equal sum of components because of independent rounding. 

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."

Table 9.7. Demand-Side Management Program Direct and Indirect Costs, 1998 through 2009 

(Thousand Dollars) 

Item 2009 2008R 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998

Direct Cost 1 ............................... 2, 3,199,568 994,280 2,364,739 1,923,891 1,794,809 1,425,172 1,159,540 1,420,937 1,455,602 1,384,232 1,250,689 1,233,018 

Energy Efficiency .................. 2,255,451 2,158,242 1,664,563 1,258,158 1,169,241 910,115 807,403 1,007,323 1,097,504 938,666 820,108 766,384 

Load Management ................. 944,117 836,038 700,176 665,733 625,568 515,057 352,137 413,614 358,098 445,566 430,581 466,634

Indirect Cost2 ............................ 394,182 181,131 158,378 127,499 126,543 132,294 137,670 204,600 174,684 180,669 172,955 187,902 

Total DSM Cost3 ....................... 3, 3,593,750 175,410 2,523,117 2,051,394 1,921,352 1,557,466 1,297,210 1,625,537 1,630,286 1,564,901 1,423,644 1,420,920 

 1 Reflects electric utility costs incurred during the year that are identified with one of the demand-side program categories.

2 Reflects costs not directly attributable to specific programs.

3 Reflects the sum of the total incurred direct and indirect cost for the year.

R = Revised. 

Notes: • Data presented are reflective of large utilities. • Includes expenditures reported by large electric utilities, only. See the data files for Demand Side Management expenditures of 

small utilities. • Totals may not equal sum of components because of independent rounding.

Source: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."
76 U.S. Energy Information Administration/Electric Power Annual 2009

Appendices
U.S. Energy Information Administration/Electric Power Annual 2009 77

44#!91

Technical Notes

This appendix describes how the U.S. Energy 

Information Administration (EIA) collects, estimates, 

and reports electric power data in the Electric Power 

Annual. Following is a description of the ongoing data 

quality efforts and sources of data for the Electric 

Power Annual. 

':$!'%

The Electric Power Annual (EPA) is prepared by the 

Office of Electricity, Renewables, and Uranium 

Statistics (ERUS), U.S. Energy Information 

Administration (EIA), U.S. Department of Energy 

(DOE). ERUS performs routine reviews of the data 

collected and the forms on which they are collected. 

Additionally, to assure that the data are collected from 

the complete set of respondents, ERUS routinely 

reviews the frames for each data collection. 

2#!8!'0$!!#

(&

Data are entered directly by respondents into the 

ERUS e-filing system. A small number of hard copy 

forms are keyed by ERUS. All data are subject to 

review via edits built into the system, additional 

quality assurance reports, and review by subject 

matter experts. Questionable data values are verified 

through contacts with respondents. Also, survey nonrespondents are identified and contacted. 

Initial edit checks of the data are performed through 

the system by the respondent. Other program edits 

include both deterministic checks, in which records 

are checked for the presence of data in required fields, 

and statistical checks, in which the data are checked 

against a range of values based on historical data 

values and for logical or mathematical consistency 

with data elements reported in the survey. 

Discrepancies found in the data, as a result of these 

checks, are resolved either by the processing staff or 

by further information obtained from a telephone call 

to the respondent company.

Those respondents unable to use the electronic 

reporting method provide the data in hard copy, 

typically via fax and e-mail. These data are manually 

entered into the computerized database and are 

subjected to the same data edits as those that are 

electronically submitted. Resolution of questionable 

data is accomplished via telephone or e-mail contact 

with the respondents.

!!!'%8'

Annual survey data have nonsampling errors. Nonsampling errors can be attributed to many sources: (1) 

inability to obtain complete information about all 

cases (i.e., nonresponse); (2) response errors; (3) 

definitional difficulties; (4) differences in the 

interpretation of questions; (5) mistakes in recording 

or coding the data; and (6) other errors of collection, 

response, coverage, and estimation for missing data. 

Although no direct measurement of the biases due to 

nonsampling errors can be obtained, precautionary 

steps were taken in all phases of the frame 

development and data collection, processing, and 

tabulation processes, in an effort to minimize their 

influence. 

Imputation. If the reported values appeared to be in 

error and the data issue could not be resolved with the 

respondent, or if the facility was a nonrespondent, a 

regression methodology was used to impute for the 

facility. 1,2,3,4,5 The regression methodology relies on 

other data to make estimates for erroneous or missing 

responses.

The basic technique employed is described in the 

paper “Model-Based Sampling and Inference2

,” on the 

EIA website. Additional references can be found on 

the InterStat website. The basis for the current 

methodology involves a 'borrowing of strength' 

technique for small domains.1,6 ,7

'!!#(&$

ERUS has adopted the following procedures with 

respect to the revision of data disseminated in energy 

data products:

Annual survey data are disseminated either as 

preliminary or final when first appearing in a 

data product. Data initially released as 

preliminary will be so noted in the data 

1 Knaub, J.R., Jr. (1999a), “Using Prediction-Oriented Software for Survey 

Estimation,” InterStat, August 1999, http://interstat.statjournals.net/ 2 Knaub, J.R. Jr. (1999b), “Model-Based Sampling, Inference and 

Imputation,” EIA web site:

http://www.eia.gov/cneaf/electricity/forms/eiawebme.pdf

3 Knaub, J.R., Jr. (2005), “Classical Ratio Estimator,” InterStat, October 

2005, http://interstat.statjournals.net/. 4 Knaub, J.R., Jr. (2007a), “Cutoff Sampling and Inference,” InterStat, April 

2007, http://interstat.statjournals.net/. 5 Knaub, J.R., Jr. (2008), forthcoming. “Cutoff Sampling.” Definition in 

Encyclopedia of Survey Research Methods, Editor: Paul J. Lavrakas, Sage, to 

appear.

6 Knaub, J.R., Jr. (2000), “Using Prediction-Oriented Software for Survey 

Estimation - Part II: Ratios of Totals,” InterStat, June 2000,

http://interstat.statjournals.net/

7 Knaub, J.R., Jr. (2001), “Using Prediction-Oriented Software for Survey 

Estimation - Part III: Full-Scale Study of Variance and Bias,”

InterStat, June 2001, http://interstat.statjournals.net/
78 U.S. Energy Information Administration/Electric Power Annual 2009

x 100,

x (t )

x (t )- x (t )

1

2 1















	

product. These data are typically released as 

final by the next dissemination of the same 

product; however, if final data are available 

at an earlier interval they may be released in 

another product. 

After data are disseminated as final, further 

revisions will be considered if they make a 

difference of 1 percent or greater at the 

national level. Revisions for differences that 

do not meet the 1 percent or greater threshold 

will be determined by the Office Director. In 

either case, the proposed revision will be 

subject to the EIA revision policy concerning 

how it affects other EIA products. 

The magnitudes of changes due to revisions 

experienced in the past will be included 

periodically in the data products, so that the 

reader can assess the accuracy of the data.

The Electric Power Annual presents the most current 

annual data available to the EIA. The statistics may 

differ from those published previously in EIA 

publications due to corrections, revisions, or other 

adjustments to the data subsequent to its original 

release. 

Sensitive Data (Formerly Identified as Data 

Confidentiality). Most of the data collected on the 

electric power surveys are not considered business 

sensitive. However, the data that are classified as 

sensitive are handled by ERUS consistent with EIA's 

“Policy on the Disclosure of Individually Identifiable 

Energy Information in the Possession of the EIA” (45 

Federal Register 59812 (1980)). 

$#!#,#(&#'3-#,

3&$'!#

Rounding Rules for Data. To round a number to n 

digits (decimal places), add one unit to the nth digit if 

the (n+1) digit is 5 or larger and keep the nth digit 

unchanged if the (n+1) digit is less than 5. The symbol 

for a number rounded to zero is (*).

Percent Change. The following formula is used to 

calculate percent differences.

Percent Change = 

where x (t1) and x (t2) denote the quantity at year t1

and subsequent year t2. 

'0$&8Electric Power 

Annual

Data published in the Electric Power Annual are 

compiled from forms filed annually or aggregated to 

an annual basis from monthly forms by electric 

utilities and electricity generators (see figure on EIA 

Electric Industry Data Collection at the end of 

Appendix A.) The EIA forms used are: 

Form EIA-411, “Coordinated Bulk Power 

Supply Program Report;” 

Form EIA-860, “Annual Electric Generator 

Report;” [Modified]

Form EIA-861, “Annual Electric Power 

Industry Report;” 

Form EIA-923, "Power Plant Operations 

Report," 

These forms can be found on the EIA Internet website 

at: http://www.eia.gov/cneaf/electricity/page/forms.html. 

The purpose of each form follows.

Survey data from other Federal sources are also 

utilized for this publication. They include: 

Department of Energy Form OE-781R,

“Annual Report of International Electric 

Export/Import Data” (Office of Electricity 

Delivery and Energy Reliability); 

Federal Energy Regulatory Commission 

Form 1, “Annual Report of Major Electric

Utilities, Licensees, and Others;” 

Rural Utility Service Form 7, “Financial and 

Statistical Report;” and 

Rural Utility Service Form 12, “Operating 

Report – Financial.”

In addition to the above-named forms, the historical 

data published in the EPA are compiled from the 

following sources: 

Form EIA-412, “Annual Electric Industry 

Financial Report,” 

Federal Energy Regulatory Commission 

Form 423, “Cost and Quality of Fuels for 

Electric Plants,” 

Form EIA-423, “Monthly Cost and Quality 

of Fuels for Electric Plants Report;” 

[Replaced]

Form EIA-759, “Monthly Power Plant 

Report,” 

Form EIA-767, “Steam-Electric Plant 

Operation and Design Report;” [Replaced]
U.S. Energy Information Administration/Electric Power Annual 2009 79

Form EIA-860A, “Annual Electric Generator 

Report–Utility,” 

Form EIA-860B, “Annual Electric Generator 

Report–Nonutility,” 

Form EIA-867, “Annual Non-utility Power 

Producer Report,”

Form EIA-900, “Monthly Nonutility Power 

Report,” 

Form EIA-906, “Power Plant Report;” 

[Replaced] and

Form EIA-920, “Combined Heat and Power 

Plant Report.” [Replaced] 

Additionally, some data reported in this publication 

were acquired from the National Energy Board of 

Canada.

Meanings of Symbols Appearing in Tables

Some symbols appearing in the data tables have 

further standardized to describe all data collected by 

the Office of Electricity, Renewables, and Uranium 

Statistics of EIA. The meanings are indicated in 

footnotes on the applicable tables and include the 

following: 

* The value reported is less than half of the 

smallest unit of measure, but is greater than 

zero.

P Usage of this symbol indicates a preliminary

value. The P is defined in endnotes as 

"P=Preliminary data."

NM Data value is not meaningful when compared 

to the same value for the previous month or 

the previous year. This symbol is also used 

to indicate a data value is not meaningful due 

to having a high Relative Standard Error 

(RSE).

Form EIA-411

The Form EIA-411 is filed as a mandatory report 

except for Schedule 7 (Transmission Outages) that is 

still voluntary reported. The information reported 

includes: (1) actual energy and peak demand for the 

preceding year and five additional years; (2) existing 

and future generating capacity; (3) scheduled capacity 

transfers; (4) projections of capacity, demand, 

purchases, sales, and scheduled maintenance; and (5) 

bulk power system maps. The report presents various 

North American Electric Reliability Corporation 

(NERC) regional council aggregate totals for their 

member electric utilities, with some nonmember 

information included. The eight NERC councils 

submit data for the Form EIA-411 to NERC. A joint 

response, through the NERC Headquarters, is filed 

annually on July 15. The forms are compiled from 

data furnished by electricity generators and electric 

utilities (members, associates, and nonmembers) 

within the council areas. 

Instrument and Design History. The Form EIA-411

program was initiated under the Federal Power 

Commission Docket R-362, Reliability and Adequacy 

of Electric Service, and Orders 383-2, 383-3, and 383-

4. The Department of Energy, established in October 

1977, assumed the responsibility for this activity. 

Until 2008, this form was considered voluntary under 

the authority of the Federal Power Act (Public Law 

88-280), The Federal Energy Administration Act of 

1974 (Public Law 93-275), and the Department of 

Energy Organization Act (Public Law 95-91). The 

responsibility for collecting these data had been 

delegated to the Office of Emergency Planning and 

Operations within the Department of Energy and was 

transferred to EIA for the reporting year 1996.

Issues within Historical Data Series

The Florida Reliability Coordinating Council 

(FRCC) separated itself from the Southeastern Electric 

Reliability Council (SERC) in the mid-1990s and all 

time series data have been adjusted. In 1998, several 

utilities realigned from Southwest Power Pool (SPP) 

to SERC. Adjustments were made to the information 

to account for the separation and to address the 

tracking of shared reserve capacity that was under 

long-term contracts with multiple members. Name 

changes altered both the Mid-Continent Area Power 

Pool (MAPP) to the Midwest Reliability Organization 

(MRO) and the Western Systems Coordinating 

Council (WSCC) to the Western Electricity 

Coordinating Council (WECC). The MRO 

membership boundaries have altered over time, but 

WECC membership boundaries have not. The utilities 

in the associated regional entity identified as the 

Alaska System Coordination Council (ASCC) 

dropped their formal participation in NERC. Both the 

States of Alaska and Hawaii are not contiguous with 

the other continental States and have no electrical 

interconnections. At the close of calendar year 2005, 

the following reliability regional councils were 

dissolved: East Central Area Reliability Coordination

Agreement (ECAR), Mid-Atlantic Area Council 

(MAAC), and Mid-America Interconnected Network 

(MAIN). 

On January 1, 2006, the ReliabilityFirst Corporation 

(RFC) came into existence as a new regional 

reliability council. Individual utility membership in 

the former ECAR, MAAC, and MAIN councils 

mostly shifted to RFC. However, adjustments in 

membership as utilities joined or left various 

reliability councils impacted MRO, SERC, and SPP. 

The Texas Regional Entity (TRE) was formed from a 

delegation of authority from NERC to handle the 

regional responsibilities of the Electric Reliability 
80 U.S. Energy Information Administration/Electric Power Annual 2009

Council of Texas (ERCOT). The revised delegation 

agreements covering all the regions were approved by 

the Federal Energy Regulatory Commission on March 

21, 2008. Reliability Councils that are unchanged 

include: Florida Reliability Coordinating Council 

(FRCC), Northeast Power Coordinating Council

(NPCC), and the Western Electricity Coordinating 

Council (WECC). The historical time series have not 

been adjusted to account for individual membership 

shifts.

The new NERC Regional Entity names are as follows: 

 

Florida Reliability Coordinating Council 

(FRCC),

Midwest Reliability Organization (MRO),

Northeast Power Coordinating Council 

(NPCC),

ReliabilityFirst Corporation (RFC),

Southeastern Electric Reliability Council 

(SERC),

Southwest Power Pool (SPP), 

Texas Regional Entity (TRE), and

Western Electricity Coordinating Council 

(WECC). 

Concept of Demand within the EIA-411: Historically, 

the Form EIA-411 has used the electric power 

industry's methodology for examining aggregated 

supply and demand. To get to the megawatts of 

power that are determined to be available for planning 

purposes each year, different categories are subtracted 

from the theoretical true totals. The definitions for 

demand are as follows:

Net Internal Demand: Internal Demand 

less Direct Control Load Management and 

Interruptible Demand.

Internal Demand: To collect these data, 

NERC develops a Total Internal Demand that 

is the sum of the metered (net) outputs of all 

generators within the system and the metered 

line flows into the system, less the metered 

line flows out of the system. The demand of 

station service or auxiliary needs (such as fan 

motors, pump motors, and other equipment 

essential to the operation of the generating 

units ) is not included nor are any 

requirement customer (utility) load or 

capacity found behind the line meters on the 

system.

Direct Control Load Management:

Demand-Side Management that is under the 

direct control of the system operator. DCLM 

may control the electric supply to individual 

appliances or equipment on customer 

premises; it does not included Interruptible 

Demand. 

Interruptible Demand: The magnitude of 

customer demand that, in accordance with 

contractual arrangements, can be interrupted 

at the time of the Regional Council’s 

seasonal peak by direct control of the System 

Operator or by action of the customer at the 

direct request of the System Operator.

Sensitive Data (Formerly Identified as Data 

Confidentiality). Power flow cases and maps are considered business sensitive. 

Form EIA-412 [Terminated]

The Form EIA-412 was used annually to collect 

accounting, financial, and operating data from major 

publicly owned electric utilities in the United States. 

Those publicly owned electric utilities engaged in the 

generation, transmission, or distribution of electricity 

which had 150,000 megawatthours of sales to ultimate 

consumers and/or 150,000 megawatthours of sales for 

resale for the two previous years, as reported on the 

Form EIA-861, “Annual Electric Utility Report,” were 

required to submit the Form EIA-412. The Form EIA412 was made available in January to collect data as 

of the end of the preceding calendar year. The 

completed surveys were due to EIA on or before April 

30. 

Instrument and Design History. The Federal Power 

Commission (FPC) created the FPC Form 1M in 1961 

as a mandatory survey. It became the responsibility of 

the EIA in October 1977 when the FPC was merged 

with DOE. In 1979, the FPC Form 1M was 

superseded by the Economic Regulatory 

Administration (ERA) Form ERA-412, and in January 

1980 by the Form EIA-412. 

Beginning in 1996 data represent those electric 

utilities meeting a threshold of 120,000 

megawatthours for ultimate consumers' sales and/or 

resales. The criteria used to select the respondents for 

this survey fit approximately 500 publicly owned 

electric utilities. Federal electric utilities are required 

to file the Form EIA-412. The financial data for the 

U.S. Army Corps of Engineers (except for Saint 

Mary's Falls at Sault Ste. Marie, Michigan); the U.S. 

Department of Interior, Bureau of Reclamation; and 

the U.S. International Boundary and Water 

Commission were collected on the Form EIA-412

from the Federal power marketing administrations. 

The form was terminated after the 2003 data year.

Issues within Historical Data Series

Beginning with the 2001 data collection, the plant 

statistics reported on Schedule 9 were also collected 

from unregulated entities that own plants with a 

nameplate capacity of 10 megawatts or greater. Also 

beginning with the 2003 collection, the transmission 
U.S. Energy Information Administration/Electric Power Annual 2009 81

data reported in Schedules 10 and 11 were collected 

from each generation and transmission cooperative 

owning transmission lines having a nominal voltage of 

132 kilovolts or greater. 

For 2001 - 2003, California Department of Water 

Resources - Electric Energy Fund data were included 

in the EIA-412 data tables. In response to the energy 

shortfall in California, in 2001 the California State 

legislature authorized the California Department of 

Water Resources, using its undamaged borrowing 

capability, to enter the wholesale markets on behalf of 

the California retail customers effective on January 

17, 2001 and for the period ending December 31, 

2002. Their 2001 revenue collected was 

$5,501,000,000 with purchased power costs of 

$12,055,000,000. Their 2002 revenue collected was 

$4,210,000,000 with purchased power costs of 

$3,827,749,811. Their 2003 revenue collected was 

$4,627,000,000 with purchased power costs of 

$4,732,000,000. The California Public Utility 

Commission was required by statute to establish the 

procedures for retail revenue recovery mechanisms for 

their purchase power costs in the future.

Sensitive Data (Formerly Identified as Data 

Confidentiality). The nonutility data collected on 

Schedule 9 “Electric Generating Plant Statistics” for 

“Cost of Plant” and “Production Expenses,” are 

considered business sensitive. 

Form EIA-423 [Replaced in 2008 by 

the Form EIA-923]

The Form EIA-423, “Monthly Cost and Quality of 

Fuels for Electric Plants Report,” collected 

information from selected electric generating plants in 

the United States. The data collected on this survey 

included the cost and quality of fossil fuels delivered 

to nonutility plants to produce electricity. These plants 

included independent power producers (including 

those facilities that formerly reported on the FERC 

Form 423) and commercial and industrial combined 

heat and power producers whose total fossil-fueled 

nameplate generating capacity is 50 or more 

megawatts. 

Instrument and Design History. The Form EIA-4238

was originally implemented in January 2002 to collect 

monthly cost and quality data for fossil fuel receipts 

from owners or operators of nonutility electricity 

generating plants. It was terminated on January 1, 

2008, and replaced by the Form EIA-923, "Power 

Plant Operations Report."

8 Due to the restructuring of the electric power industry, many plants which 

had historically submitted this information for utility plants on the FERC 

Form 423 (see subsequent section) were being transferred to the nonutility 

sector. As a result, a large percentage of fossil fuel receipts were no longer 

being reported. The Form EIA-423 was implemented to fill this void and to 

capture the data associated with existing nonregulated power producers. Its 

design closely follows that of the FERC Form 423.

Issues within Historical Data Series

Natural gas values for 2001 forward do not include 

blast furnace gas or other gas.

Sensitive Data (Formerly Identified as Data 

Confidentiality). Plant fuel cost data collected on the 

survey are considered business sensitive. State and 

national level aggregations will be published in this 

report if sufficient data are available to avoid 

disclosure of individual company and plant level 

costs. 

FERC Form 423 [Replaced in 2008 by 

Form EIA-923]

The Federal Energy Regulatory Commission (FERC) 

Form 423, “Monthly Report of Cost and Quality of 

Fuels for Electric Plants,” was administered by FERC. 

The data were downloaded from the Commission’s 

website into an EIA database. The Form was filed by 

approximately 600 regulated plants. To meet the old 

criteria for filing, a plant must have had a total steam 

turbine electric generating capacity and/or combinedcycle (gas turbine with associated steam turbine) 

generating capacity of 50 or more megawatts. Only 

fuel delivered for use in steam-turbine and combinedcycle units was reported. Fuel received for use in gasturbine or internal-combustion units that was not 

associated with a combined-cycle operation is not 

reported. The 2007 data collection represents the last 

year where the information came from the FERC 

Form 423. 

Instrument and Design History. On July 7, 1972, the 

Federal Power Commission (FPC) issued Order 

Number 453 enacting the New Code of 

Federal Regulations, Section 141.61, legally creating 

the FPC Form 423. Originally, the form was used to 

collect data only on fossil-steam plants, but was 

amended in 1974 to include data on internalcombustion and combustion-turbine units. The FERC 

Form 423 replaced the FPC Form 423 in January 

1983. The FERC Form 423 eliminated peaking units, 

for which data were previously collected on the FPC 

Form 423. In addition, the generator nameplate 

capacity threshold was changed from 25 megawatts to 

50 megawatts. This reduction in coverage eliminated 

approximately 50 utilities and 250 plants. All 

historical FPC Form 423 data in this publication were 

revised to reflect the new generator-nameplatecapacity threshold of 50 or more megawatts reported 

on the FERC Form 423. In January 1991, the 

collection of data on the FERC Form 423 was 

extended to include combined-cycle units. Historical 

data have not been revised to include these units. 

Starting with the January 1993 data, the FERC began 

to collect the data directly from the respondents. On 

January 1, 2008, EIA assumed responsibility for 

collection and the information is now under the Form 

EIA-923, "Power Plant Operations Report."
82 U.S. Energy Information Administration/Electric Power Annual 2009

Formulas and Methodologies. Data for the FERC 

Form 423 were collected at the plant level. These data 

were then used in the same formulas used by the Form 

EIA-423 to produce aggregates and averages for each 

fuel type at the State, Census division, and U.S. levels.

Issues within Historical Data Series. The FERC 

Form 423 data published by EIA have been reviewed 

for consistency between volumes and prices and for 

their consistency over time. 

Receipts data for regulated utilities were compiled by 

EIA from data collected by the Federal Energy 

Regulatory Commission (FERC) on the FERC Form 

423. These data were collected by FERC for 

regulatory rather than statistical and publication 

purposes. EIA did not attempt to resolve any late 

filing issues in the FERC Form 423 data. Due to the 

estimation procedure discussed previously, 2003 and 

later data cannot be directly compared to previous 

years’ data. 

Sensitive Data (Formerly Identified as Data 

Confidentiality). Data collected on FERC Form 423 

are not considered to be business sensitive.

Form EIA-767 [Replaced by Forms 

EIA-860 and EIA-923]

The Form EIA-767 was used to collect data annually 

on plant operations and equipment design, including 

boiler, generator, cooling system, air pollution control 

equipment, and stack characteristics. Data were 

collected from a mandatory restricted-universe census 

of all electric power plants with a total existing or 

planned organic-fueled or combustible renewable 

steam-electric generator nameplate rating of 10 or 

more megawatts. The entire form was filed by 

approximately 800 power plants with a nameplate 

capacity of 100 or more megawatts. An additional 600 

power plants with a nameplate capacity under 100 

megawatts submitted information only on fuel 

consumption and quality, boiler and generator 

configuration, and nitrogen oxides, mercury, 

particulate matter, and sulfur dioxide controls.

Instrument and Design History. The Federal Energy 

Administration Act of 1974 (Public Law 93-275) 

defines the legislative authority to collect these data. 

The predecessor form, FPC-67, “Steam-Electric Plant 

Air and Water Quality Control Data,” was used to 

collect data from 1969 to 1980, when the form number 

was changed to Form EIA-767. In 1982, the form was 

completely redesigned and retitled Form EIA-767, 

“Steam-Electric Plant Operation and Design Report.” 

In 1986, the respondent universe of 700 was increased 

to 900 to include plants with nameplate capacity from 

10 megawatts to 100 megawatts. In 2002, the 

respondent universe was increased by almost 1,370 

plants with the addition of non-utility plants. 

Collection of data via the form was suspended for the 

2006 data year

Estimation of EIA-767 Data. No estimation of Form 

EIA-767 data was performed, as 100 percent of the 

forms were collected.

. Starting for the collection of 2007 

calendar year data, most of the Form EIA-767

information is now collected on either the revised 

Form EIA-860, "Annual Electric Generator Report" or 

the new Form EIA-923, "Power Plant Operations 

Report." 

Issues within Historical Data Series

None.

Sensitive Data (Formerly Identified as Data 

Confidentiality). Historical latitude and longitude 

data collected on the Form EIA-767 are considered

business sensitive.

Form EIA-860

The Form EIA-860 is a mandatory census of all 

existing and planned electric generating facilities in 

the United States with a total generator nameplate 

capacity of 1 or more megawatts. The survey is used 

to collect data on existing power plants and 5-year 

plans for constructing new plants, generating unit 

additions, modifications, and retirements in existing 

plants. Data on the survey are collected at the 

individual generator level. Certain power plant 

environmental related data are now collected at the 

boiler level. These data include environmental 

equipment design parameters and boiler air emission 

standards and boiler emission controls. The Form 

EIA-860 is made available in January to collect data 

for the previous year and is due to EIA by February 15 

of each year. 

Instrument and Design History. The Form EIA-860

was originally implemented in January 1985 to collect 

plant data on electric utilities as of year-end 1984. In 

January 1999, the Form EIA-860 was renamed the 

Form EIA-860A and was implemented to collect data 

as of January 1, 1999.

In 1989, the Form EIA-867, "Annual Nonutility 

Power Producer Report," was initiated to collect plant 

data on unregulated entities with a total generator 

nameplate capacity of 5 or more megawatts. In 1992, 

the reporting threshold of the Form EIA-867 was 

lowered to include all facilities with a combined 

nameplate capacity of 1 or more megawatts. 

Previously, data were collected every 3 years from 

facilities with a nameplate capacity between 1 and 5 

megawatts. In 1998, the Form EIA-867, was renamed 

Form EIA-860B, "Annual Electric Generator Report – 

Nonutility." The Form EIA-860B was a mandatory 

survey of all existing and planned nonutility electric 

generating facilities in the United States with a total 

generator nameplate capacity of 1 or more megawatts. 

Beginning with data collected for the year 2001, the 

infrastructure data collected on the Form EIA-860A 
U.S. Energy Information Administration/Electric Power Annual 2009 83

and the Form EIA-860B were combined into the new 

Form EIA-860 and the monthly and annual versions of 

the Form EIA-906. The Federal Energy 

Administration Act of 1974 (Public Law 93-275) 

defines the legislative authority to collect these data. 

Starting with the 2007 data,, design parameters data 

formerly collected on Form EIA-767 are collected on 

Form EIA-860. These include design parameters 

associated with certain steam-electric plants’ boilers, 

cooling systems, flue gas particulate collectors, flue 

gas desulfurization units and stacks and flues.

Estimation of EIA-860 Data. Of the 17,879 existing 

generators in the 2009 For EIA-860 frame, imputation 

was performed on 5 generators. These 5 generators 

account for less than 0.0006% of the existing 

capacity. Imputation was performed at the 

generators levels using the respondents’ 2008 data.

Issues within Historical Data Series

Categorization of Capacity by Business Sector

Some capacity in 2001 through 2004 is classified 

based on the operating company's classification as an 

electric utility or an independent power producer. 

Starting in the Electric Power Annual 2006, capacity 

by producer type was determined at the generating 

plant level for 2005 and 2006, based on whether the 

plant is an electric utility plant or an electric nonutility 

plant. Therefore, the revised capacity by producer 

type for 2005 is comparable to the capacity for 2006 

and later years, by producer type. The previously 

published 2005 capacity by producer type was 

determined based on the operating company’s 

classification of electric utility or electric nonutility.

: There 

are a small number of electric utility combined heat 

and power plants, as well as a small number of 

industrial and commercial generating facilities that are 

not combined heat and power. For the purposes of 

this report the data for these plants are included, 

respectively, in the following categories: “Electricity 

Generators, Electric Utilities,” “Combined Heat and 

Power, Industrial,” and “Combined Heat and Power, 

Commercial.”

Planned Capacity: Delays and cancellations may have 

occurred subsequent to respondent data reporting as of 

December 31 of the data year.

Capacity by Energy Source:

In the Electric Power Annual 2005, certain petroleumfired capacity was misclassified as natural gas-fired 

capacity for 1995 – 2003. This has been corrected in 

the Electric Power Annual 2006. Corrections were 

noted as revised data.

Prior to the Electric 

Power Annual 2005, the capacity for generators for 

which natural gas or petroleum was the most 

predominant energy source was presented in the 

categories “petroleum only,” “natural gas only” and 

“dual-fired.” The “dual-fired” category, which was 

EIA’s effort to infer which generators could fuelswitch between natural gas and fuel oil, included only 

the capacity of generators for which the most 

predominant energy source and second most 

predominant energy source were reported as natural 

gas or petroleum. Beginning in 2005 capacity is 

assigned to energy source based solely on the most 

predominant (primary) energy source reported for a 

generator. The “dual-fired” category was eliminated. 

Separately, summaries of capacity associated with 

generators with fuel-switching capability are 

presented for 2005 and later years.. These 

summaries are based on data collected from new 

questions added to the Form EIA-860 survey that 

directly address the ability of generators to switch 

fuels and co-fire fuels.

Sensitive Data (Formerly Identified as Data 

Confidentiality). The tested heat rate data collected 

on the Form EIA-860 are considered business 

sensitive. 

Form EIA-861

The Form EIA-861 is a mandatory census of electric 

power industry participants in the United States. The 

survey is used to collect information on power 

production and sales data from approximately 3,300 

respondents. About 3,200 are electric utilities, and the 

remainder is nontraditional entities such as energy 

service providers, or the unregulated subsidiaries of 

electric utilities and power marketers. The data 

collected are used to maintain and update the ERUS 

electric power industry participant frame database. 

The Form EIA-861 is made available in January of 

each year to collect data as of the end of the preceding 

calendar year and is due by April 30.

Transportation Sector. Prior to 2003, sales of 

electric power to the Transportation sector of the U. S. 

economy were included in the Other sector, along 

with sales to customers for public buildings, traffic 

signals, public street lighting, and sales to irrigation 

consumers. Beginning with the 2003 collection cycle, 

sales to the Transportation sector are collected 

separately. Sales to public-sector customers for public 

buildings, traffic signals and street lighting, previously 

reported in the Other sector, were reclassified as 

Commercial sector sales. Sales to irrigation customers, 

where separately identified, were reclassified to the 

Industrial sector.

On the Form EIA-861, the Transportation sector is 

defined as electrified rail, primarily urban transit, light 

rail, automated guideway, and other rail systems 

whose primary propulsive energy source is electricity. 

Electricity sales to transportation sector consumers 

whose primary propulsive energy source is not 
84 U.S. Energy Information Administration/Electric Power Annual 2009

electricity (i.e., gasoline, diesel fuel, etc.) are not 

included.

Benchmark statistics were reviewed from outside 

surveys, most notably the U.S. Department of 

Transportation, Federal Transit Administration’s 

National Transportation Database, a source previously 

used by EIA to estimate electricity transportation 

consumption. The U.S. Department of Transportation 

(DOT) survey indicated the State and city locations of 

expected respondents. The EIA-861 survey 

methodology assumed that sales, revenue, and 

customer counts associated with these mass transit 

systems would be provided by the incumbent utilities 

in these areas, relying on information drawn routinely 

from rate schedules and classifications designed to 

serve the sector separately and distinctly. In 2007, 72 

respondents reported transportation data in 28 States. 

Imputation. The Electric Power Annual (EPA) 

reports total retail sales volumes (megawatthours) and 

customer counts in States with deregulated markets as 

the sum of bundled sales reported by full-service 

providers and delivery reported by transmission and 

distribution utilities. ERUS has concluded that the 

retail sales data reported by delivery utilities are more 

reliable than data reported by power marketers and 

Energy Service Providers (ESPs). 

The reporting methodology change uses sales volumes 

and customer counts reported by distribution utilities, 

and add only an incremental revenue value, 

representing revenue associated with missing sales 

assumed to be attributable to the ESPs that were 

under-represented in the survey frame. In some cases, 

adjustments are also made to retail sales, revenue, and 

customer counts associated with underreporting of 

delivery volumes by one or more of the distribution 

utilities. In those cases, EIA assumes that total load 

served by those utilities is accurate, and that any 

underreporting of delivery volumes resulted from 

misclassifying actual delivery volumes as bundled 

sales. Therefore, in those instances EIA adjusted 

upwards the delivery volumes, revenues, and customer 

counts and made a corresponding equivalent offset 

(reduction) to the bundled sales by State and end-use 

sector. 

Data for 2009 reflect imputed retail sales data to 

account for non-respondents on Form EIA-861. The 

imputation methodology used is the same as that used 

in preparing the Electric Power Monthly (whose retail 

sales data are drawn from Form EIA-826). Form EIA826 is a monthly stratified sample of approximately 

475 investor-owned and public utilities, as well as a 

census of energy service providers and power 

marketers. If an EIA-861 respondent did not file an 

annual form for 2009, their data were assumed to be 

the amount imputed during the year using the EIA-826 

sample form collection and imputation process. 

Instrument and Design History. The Form EIA-861

was implemented in January 1985 for collection of 

data as of year-end 1984. The Federal Energy 

Administration Act of 1974 (Public Law 93-275) 

defines the legislative authority to collect these data.

Data Reconciliation. The EPA reports total retail 

sales volumes (megawatthours) and customer counts 

in States with deregulated markets as the sum of 

bundled sales reported by full-service providers and 

delivery reported by transmission and distribution 

utilities. ERUS has concluded that the retail sales data 

reported by delivery utilities are more reliable than 

data reported by power marketers and ESPs. 

Average Retail Price of Electricity. This represents

the cost per unit of electricity sold and is calculated by 

dividing retail electric revenue by the corresponding 

sales of electricity. The average retail price of 

electricity is calculated for all consumers and for each 

end-use sector. State-level weighted average prices 

per unit of sales are calculated as the ratio of revenue 

to sales.

The electric revenue used to calculate the average 

retail price of electricity is the operating revenue 

reported by the electric power industry participant.

Operating revenue includes energy charges, demand 

charges, consumer service charges, environmental 

surcharges, fuel adjustments, and other miscellaneous 

charges. Electric power industry participant operating 

revenues also include ratepayer reimbursements for 

State and Federal income taxes and taxes other than 

income taxes paid by the utility. 

The average retail price of electricity reported in this 

publication by sector represents a weighted average of 

consumer revenue and sales within sectors and across 

sectors for all consumers, and does not reflect the per 

kWh rate charged by the electric power industry 

participant to the individual consumers. Electric 

utilities typically employ a number of rate schedules 

within a single sector. These alternative rate schedules 

reflect the varying consumption levels and patterns of 

consumers and their associated impact on the costs to 

the electric power industry participant for providing 

electrical service. 

Issues within Historical Data Series

Beginning in 2003 the Other sector has been 

eliminated. Data previously assigned to the Other 

sector have been reclassified as follows: lighting for 

public buildings, streets, and highways, 

interdepartmental sales, and other sales to public 

authorities are now included in the Commercial 

sector; agricultural and irrigation sales where 

separately identified are now included in the Industrial 
U.S. Energy Information Administration/Electric Power Annual 2009 85

sector; and a new sector, Transportation, includes 

electrified rail and various urban transit systems (such 

as automated guideway, trolley, and cable) where the 

principal propulsive energy source is electricity. 

Comparisons of data across years should include 

consideration of these reclassification changes. 

Changes from year to year in consumer counts, sales 

and revenues, particularly involving the commercial 

and industrial consumer sectors, may result from 

respondent implementation of changes in the 

definitions of consumers, and reclassifications. 

Utilities and energy service providers may classify 

commercial and industrial customers based on either 

NAICS codes or demands or usage falling within 

specified limits by rate schedule. Also, the number of 

ultimate customers is an average of the number of 

customers at the close of each month.

Demand-Side Management: The following 

definitions are supplied to assist in interpreting Tables 

9.1 through 9.5. Utility costs reflect the total cash 

expenditures for the year, in nominal dollars, that flow 

out to support demand-side management (DSM) 

programs.

Actual Peak Load Reduction. The actual 

reduction in annual peak load achieved by all 

program participants during the reporting year, at 

the time of annual peak load, as opposed to the 

installed peak load reduction capability (Potential 

Peak Load Reduction). Actual peak load 

reduction is reported by large utilities only.

Energy Savings. The change in aggregate 

electricity use (measured in megawatthours) for 

consumers that participate in a utility DSM 

program. These savings represent changes at the 

consumer's meter (i.e., exclude transmission and 

distribution effects) and reflect only activities that 

are undertaken specifically in response to utilityadministered programs, including those activities 

implemented by third parties under contract to the 

utility.

Large Utilities. Those electric utilities with

annual sales to ultimate customers or sales for 

resale greater than or equal to 150 million 

kilowatthours in 1998-2009 and, for years prior, 

the threshold was set at 120 million 

kilowatthours.

Potential Peak Load Reductions. The potential 

peak load reduction as a result of load 

management, and also the actual peak load 

reduction achieved by energy efficiency 

programs.

Wholesale Trade

Sensitive Data (Formerly Identified as Data 

Confidentiality). Data collected on the Form EIA861 are not considered to be business sensitive.

: Alaska and Hawaii are not included.

Form EIA-906 [Replaced in 2007 by 

Form EIA-923]

The Form EIA-906 was used to collect plant-level 

data on generation, fuel consumption, stocks, and fuel 

heat content, from electric utilities and nonutilities. 

Data were collected monthly from a model-based 

sample of approximately 1,700 utility and nonutility 

electric power plants. The form was also used to 

collect these statistics from another 2,667 plants (i.e., 

all other generators 1 MW or greater) on an annual 

basis. The 2007 data collection represents the last year 

where the information came from the Form EIA-906. 

Starting with the collection of 2008 calendar year 

data, the Form EIA-906 information is now collected 

on a replacement form (the Form EIA-923). The 

monthly data for Form EIA-906 is now being 

collected on the replacement form starting in January 

of 2008. 

Instrument and Design History. The Bureau of 

Census and the U.S. Geological Survey collected, 

compiled, and published data on the electric power 

industry prior to 1936. After 1936, the Federal Power 

Commission (FPC) assumed all data collection and 

publication responsibilities for the electric power 

industry and implemented the Form FPC-4. The 

Federal Power Act, Section 311 and 312, and FPC 

Order 141 defined the legislative authority to collect 

power production data. The Form EIA-759 replaced 

the Form FPC-4 in January 1982. In 1996, the Form 

EIA-900 was initiated to collect sales for resale data

from unregulated entities. In 1998, the form was 

modified to collect sales for resale, gross generation, 

and sales to end user data. In 1999, the form was 

modified to collect net generation, consumption, and 

ending stock data. In 2000, the form was modified to 

include useful thermal output data.

In January 2001, Form EIA-906 superseded Forms 

EIA-759 and EIA-900. In January 2004, Form EIA920 superseded Form EIA-906 for those plants 

defined as combined heat and power plants; all other 

plants that generate electricity continue to report on 

Form EIA-906. The Federal Energy Administration 

Act of 1974 (Public Law 93-275) defines the 

legislative authority to collect these data. In January 

2008, the Form EIA-923 superseded this form.

Issues within Historical Data Series

There were a small number of electric commercial 

and industrial- only plants that are included in the 

combined heat and power category. For the purposes 

of this report the data for these plants were included, 

respectively, in the following categories: “Electricity 

Generators, Electric Utilities,” “Combined Heat and 
86 U.S. Energy Information Administration/Electric Power Annual 2009

Power, Industrial,” and “Combined Heat and Power, 

Commercial.” No information on the production of 

Useful Thermal Output (UTO) or fuel consumption 

for UTO was collected or estimated for the electric 

utility combined heat and power plants.

Sensitive Data (Formerly Identified as Data 

Confidentiality). The only business sensitive data 

element collected on the Form EIA-906 is fuel stocks 

at the end of the reporting period.

/	;4&!#		<%

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The Form EIA-920, “Combined Heat and Power Plant 

Report” was used to collect plant-level data on 

generation, fuel consumption, stocks, and fuel heat 

content of combined heat and power (CHP) plants. 

Data were collected monthly from a sample of plants. 

The form was also used to collect the statistics from 

combined heat and power plants on an annual basis. 

Instrument and Design History. In January 2004, 

Form EIA-920 superseded Form EIA-906 for those 

plants defined as combined heat and power plants; all 

other plants that generate electricity continue to report 

on Form EIA-906. Starting with the collection of 2007 

calendar year data, the Form EIA-920 information is 

now collected on a replacement form (the Form EIA923). The monthly data for Form EIA-920 began 

collection on the replacement form in January of 

2008. (For further information on predecessor forms, 

see the discussion of the EIA-906 survey, above.) The 

Federal Energy Administration Act of 1974 (Public 

Law 93-275) defines the legislative authority to 

collect these data. 

Issues within Historical Data Series

There are a small number of electric commercial and 

industrial only plants that are included in the 

combined heat and power category. For the purposes 

of this report the data for these plants are included,

respectively, in the following categories: “Electricity 

Generators, Electric Utilities,” “Combined Heat and 

Power, Industrial,” and “Combined Heat and Power, 

Commercial.” No information on the production of 

UTO or fuel consumption for UTO was collected or

estimated for the electric utility combined heat and 

power plants.

Sensitive Data (Formerly Identified as Data 

Confidentiality). The only business sensitive data 

element collected on the Form EIA-920 were fuel 

stocks at the end of the reporting period. 

/


Form EIA-923, “Power Plant Operations Report,” is 

used to collect information on receipts and cost of 

fossil fuels, fuel stocks, generation, consumption of 

fuel for generation, and environmental data (e.g., 

emission controls and cooling systems). Data are 

collected from a monthly sample of approximately 

1,600 plants, which includes a census of nuclear and 

pumped storage hydroelectric plants. The plants in 

the monthly sample report their receipts, cost and 

stocks of fossil fuels, electric power generation, and 

the total consumption of fuels for both electric power 

generation and, if a combined heat and power plant, 

useful thermal output. At the end of the year, the 

monthly respondents report their annual source and 

disposition of electric power (nonutilities only), and if 

applicable, the environmental data on the Form EIA923 Supplemental Form (Schedules 6, 7, and 8A to 

8F). Approximately 3,300 plants, representing all 

generators not included in the monthly sample and 

with a nameplate capacity of 1 MW or more, report 

data on the entire form (Schedules 1 to 8F, as 

applicable) annually. In addition to electric power 

generating plants, respondents include fuel storage 

terminals without generating capacity that receives 

shipments of fossil fuels for eventual use in electric 

power generation. The monthly data are due by the 

last day of the month following the reporting period.

Receipts of fossil fuels, fuel cost and quality 

information, and fuel stocks at the end of the reporting 

period are all reported at the plant level. Fuel receipts 

and costs are collected from plants with a nameplate 

capacity of 50 MW or more and burn fossil fuels. 

Plants that burn organic fuels and have a steam turbine 

capacity of at least 10 megawatts report consumption 

at the boiler level and generation at the generator level 

for each month, regardless of whether the plant reports 

in the monthly sample or reports once a year 

(annually). For all other plants, consumption is 

reported at the prime-mover level. For these plants, 

generation is reported either at the prime-mover level 

or, for noncombustible sources (e.g., wind, nuclear), at 

the prime-move and energy source level (including 

generating unit for nuclear only). The source and 

disposition of electricity is reported annually for 

nonutilities at the plant level, as is revenue from sales 

for resale. Additional operational data, including 

environmental data, are collected annually from 

facilities that have a steam turbine capacity of at least 

10 megawatts.

Instrument and Design History: 

Receipts and Cost and Quality of Fossil Fuels

On July 7, 1972, the Federal Power Commission 

(FPC) issued Order Number 453 enacting the New 

Code of Federal Regulations, Section 141.61, legally 

creating the FPC Form 423. Originally, the form was 

used to collect data only on fossil-steam plants, but 

was amended in 1974 to include data on internalcombustion and combustion-turbine units. The FERC 

Form 423 replaced the FPC Form 423 in January 

1983. The FERC Form 423 eliminated peaking units,

for which data were previously collected on the FPC 
U.S. Energy Information Administration/Electric Power Annual 2009 87

Form 423. In addition, the generator nameplate 

capacity threshold was changed from 25 megawatts to 

50 megawatts. This reduction in coverage eliminated 

approximately 50 utilities and 250 plants. All 

historical FPC Form 423 data in this publication were 

revised to reflect the new generator-nameplatecapacity threshold of 50 or more megawatts reported 

on the FERC Form 423. In January 1991, the 

collection of data on the FERC Form 423 was 

extended to include combined-cycle units. Historical 

data have not been revised to include these units. 

Starting with the January 1993 data, the FERC began 

to collect the data directly from the respondents.

The Form EIA-423 was originally implemented in 

January 2002 to collect monthly cost and quality data 

for fossil fuel receipts from owners or operators of 

nonutility electricity generating plants. Due to the 

restructuring of the electric power industry, many 

plants which had historically submitted this 

information for utility plants on the FERC Form 423 

(see above) were being transferred to the nonutility 

sector. As a result, a large percentage of fossil fuel 

receipts were no longer being reported. The Form 

EIA-423 was implemented to fill this void and to 

capture the data associated with existing non-regulated 

power producers. Its design closely followed that of 

the FERC Form 423. 

Both the Form EIA-423 and FERC-423 were 

superseded by Form EIA-923 (Schedule 2) in January 

of 2008. The EIA-923 maintains the same 50 

megawatt threshold for these data. However, not all 

data are collected monthly on the new form. 

Beginning with 2008 data, a sample of the 

respondents will report monthly, with the remainder 

reporting annually (monthly values will be imputed 

via regression). For 2007, Schedule 2 annual data will 

not be collected or imputed. Most of the plants 

required to report on Schedule 2 already submitted 

their 2007 receipts data on a monthly basis.

Generation and Consumption

The Bureau of Census and the U.S. Geological Survey 

collected, compiled, and published data on the electric 

power industry prior to 1936. After 1936, the Federal 

Power Commission (FPC) assumed all data collection 

and publication responsibilities for the electric power 

industry and implemented the Form FPC-4. The 

Federal Power Act, Section 311 and 312, and FPC 

Order 141 defined the legislative authority to collect 

power production data. The Form EIA-759 replaced 

the Form FPC-4 in January 1982.

In 1996, the Form EIA-900 was initiated to collect 

sales for resale data from unregulated entities. In 

1998, the form was modified to collect sales for 

resale, gross generation, and sales to end user data. In 

1999, the form was modified to collect net generation, 

consumption, and ending stock data. In 2000, the form

was modified to include useful thermal output data. 

In January 2001, Form EIA-906 superseded Forms 

EIA-759 and EIA-900. In January 2004, Form EIA920 superseded Form EIA-906 for those plants 

defined as combined heat and power plants; all other 

plants that generate electricity continue to report on 

Form EIA-906. The Federal Energy Administration 

Act of 1974 (Public Law 93-275) defines the 

legislative authority to collect these data. 

Forms EIA-906 and EIA-920 were superseded by 

survey form EIA-923 beginning in January 2008 with 

the collection of annual 2007 data and monthly 2008 

data. 

Steam Electric Plant Operational Data

The Federal Energy Administration Act of 1974 

(Public Law 93-275) defines the legislative authority 

to collect these data. The predecessor form, FPC-67, 

“Steam-Electric Plant Air and Water Quality Control 

Data,” was used to collect data from 1969 to 1980, 

when the form number was changed to Form EIA767. In 1982, the form was completely redesigned and 

retitled Form EIA-767, “Steam-Electric Plant 

Operation and Design Report.” In 1986, the 

respondent universe of 700 was increased to 900 to 

include plants with nameplate capacity from 10 

megawatts to 100 megawatts. In 2002, the 

respondent universe increased to above 1,370 plants 

plus the addition of non-utility plants. Collection of 

data via the Form EIA-767 was suspended for the 

2006 data year, but was resumed on the Form EIA923 for data year 2007. For respondents selected to 

be in the monthly sample for Form EIA-906 or EIA920 in 2007, and were thus were not annual filers for 

Form EIA-923, this data was collected for 2007 via a 

one-time supplemental filing in 2008.

Data Processing and Data System Editing.

Respondents are encouraged to enter data directly into 

a computerized database via the e-filing system. A 

variety of automated quality control mechanisms are 

run during this process, such as range checks and 

comparisons with historical data. These edit checks 

were performed as the data were provided, and many 

problems that are encountered are resolved during the 

reporting process. Those plants that are unable to use 

the electronic reporting medium provide the data in 

hard copy, typically via fax. These data were 

manually entered into the computerized database. The 

data were subjected to the same edits as those that 

were electronically submitted. 

If the reported data appeared to be in error and the 

data issue could not be resolved by follow up contact 

with the respondent, or if a facility was a 

nonrespondent, a regression methodology was used to 

impute for the facility.
88 U.S. Energy Information Administration/Electric Power Annual 2009

Imputation. For data collected monthly, regression 

prediction, or imputation, is done for all missing data 

including non-sampled units and any nonrespondents. 

For data collected annually, imputation is done for 

nonrespondents.

For gross generation and total fuel consumption, 

multiple regression is used for imputation. For gross 

generation, the regressors are prior year average 

generation for the same fuel, prior year average 

generation from other fuels, and nameplate capacity. 

Regressors for total fuel consumption are prior year 

average fuel consumption from the same fuel, prior 

year average consumption from other fuels, and 

nameplate capacity. For stocks, a linear combination 

of the prior month’s ending stocks value and the 

current month’s consumption and receipts values is 

used.

Only approximately 0.01% of the national total gross 

generation for 2009 reported here is imputed, although 

this will vary by State and energy source.

Net generation, where not reported, is estimated by 

using a fixed ratio to gross generation by prime-mover 

type.

Receipts of Fossil Fuels. Receipts data, including 

cost and quality of fuels, are collected at the plant 

level from selected electric generating plants and 

fossil-fuel storage terminals in the United States. 

These plants include independent power producers, 

electric utilities, and commercial and industrial 

combined heat and power producers whose total 

fossil-fueled nameplate capacity is 50 megawatts or 

more (excluding storage terminals, which do not 

produce electricity). The data on cost and quality of 

fuel shipments are then used in the following formulas 

to produce aggregates and averages for each fuel type 

at the State, Census division, and U.S. levels. For 

these formulas, receipts and average heat content are 

at the plant level. For each geographic region, the 

summation sign, represents the sum of all facilities 

in that geographic region. 

For coal, units for receipts are in tons and units for 

average heat contents (A) are in million Btu per ton. 

For petroleum, units for receipts are in barrels and 

units for average heat contents (A) are in million Btu 

per barrel. 

For gas, units for receipts are in thousand cubic feet 

(Mcf) and units for average heat contents (A) are in 

million Btu per thousand cubic foot. 

For each of the above fossil fuels:

Total Btu = 

where i denotes a facility; Ri = receipts for facility i;

Ai = average heat content for receipts at facility i; 

Weighted Average Btu = 

where i denotes a facility; Ri = receipts for facility i; 

and, Ai = average heat content for receipts at facility i.

The weighted average cost in cents per million Btu is 

calculated using the following formula:

Weighted Average Cost = 

where i denotes a facility; Ri = receipts for facility i; 

Ai average heat content for receipts at facility i;

and Ci = cost in cents per million Btu for facility i. 

The weighted average cost in dollars per unit (i.e., 

tons, barrels, or Mcf) is calculated using the following 

formula:

Weighted Average Cost = 

where i denotes a facility; Ri = receipts for facility i; 

Ai = average heat content for receipts at facility i;

and, Ci = cost in cents per million Btu for facility i. 

Power Production, Fuel Stocks, and Fuel 

Consumption Data. The Bureau of Census and the 

U.S. Geological Survey collected, compiled, and 

published data on the electric power industry prior to 

1936. After 1936, the Federal Power Commission 

(FPC) assumed all data collection and publication 

responsibilities for the electric power industry and 

implemented the Form FPC-4. The Federal Power 

Act, Section 311 and 312, and FPC Order 141 defined 

the legislative authority to collect power production 

data. The Form EIA-759 replaced the Form FPC-4 in 

January 1982. 

In 1996, the Form EIA-900 was initiated to collect 

sales for resale data from unregulated entities. In 

1998, the form was modified to collect sales for 

resale, gross generation, and sales to end user data. In 

1999, the form was modified to collect net generation, 

consumption, and ending stock data. In 2000, the form 

was modified to include useful thermal output data. 

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i

i i i

i







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i

i i

i







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U.S. Energy Information Administration/Electric Power Annual 2009 89

In January 2001, Form EIA-906 superseded Forms 

EIA-759 and EIA-900. In January 2004, Form EIA920 superseded Form EIA-906 for those plants 

defined as combined heat and power plants; all other 

plants that generate electricity continue to report on 

Form EIA-906. The Federal Energy Administration 

Act of 1974 (Public Law 93-275) defines the 

legislative authority to collect these data. 

In January 2004, Form EIA-920 superseded Form 

EIA-906 for those plants defined as combined heat 

and power plants; all other plants that generate 

electricity continue to report on Form EIA-906. In 

January 2008, Form EIA-923 superseded both the 

EIA-906 and EIA-920 forms for the collection of 

these data. 

Methodology to Estimate Biogenic and Nonbiogenic Municipal Solid Waste9

. Municipal Solid 

Waste (MSW) consumption for generation of electric 

power is split into its biogenic and non-biogenic 

components beginning with 2001 data by the 

following methodology: 

The reported tonnage of MSW is reported on the 

Form EIA-923. The composition of MSW and 

categorization of the components were obtained 

from the Environmental Protection Agency 

publication, Municipal Solid Waste in the United 

States: 2005 Facts and Figures. The Btu contents 

of the components of MSW were obtained from 

various sources.

The potential quantities of combustible MSW 

discards (which include all MSW material 

available for combustion with energy recovery, 

discards to landfill, and other disposal) were 

multiplied by their respective Btu contents. The 

EPA-based categories of MSW were then 

classified into renewable and non-renewable 

groupings. From this, EIA calculated how much of 

the energy potentially consumed from MSW was 

attributed to biogenic components and how much 

to non-biogenic components (see Table 1 and 2, 

below).10

9 See the following sources: 

 Bahillo, A. et al. Journal of Energy Resources Technology, “NOx and 

N2O Emissions During Fluidized Bed Combustion of Leather Wastes.” 

Volume 128, Issue 2, June 2006. pp. 99-103. 

 U.S. Energy Information Administration. Renewable Energy Annual 

2004. “Average Heat Content of Selected Biomass Fuels.” 

Washington, DC, 2005

 Penn State Agricultural College Agricultural and Biological 

Engineering and Council for Solid Waste Solutions. Garth, J. and 

Kowal, P. Resource Recovery, Turning Waste into Energy, University 

Park, PA, 1993

 Utah State University Recycling Center Frequently Asked Questions. 

Published at http://www.usu.edu/recycle/faq.htm. Accessed December 

2006 

10 Biogenic components include newsprint, paper, containers and packaging,

leather, textiles, yard trimmings, food wastes, and wood. Non-biogenic

components include plastics, rubber and other miscellaneous non-biogenic

waste.

These values are used to allocate the net and gross 

generation published in the Electric Power Monthly

and Electric Power Annual generation tables. The tons 

of biogenic and non-biogenic components were 

estimated with the assumption that glass and metals 

were removed prior to combustion. The average 

Btu/ton for the biogenic and non-biogenic components 

is estimated by dividing the total Btu consumption by 

the total tons. Published net generation attributed to 

biogenic MSW and non-biogenic MSW is classified 

under Other Renewables and Other, respectively.

Table 1. Btu Consumption for Biogenic and Nonbiogenic Municipal Solid Waste (percent)

2001 2002 2003 2004 2005 2006

Biogenic 57 56 55 55 56 56

Nonbiogenic 43 44 45 45 44 44

Table 2. Tonnage Consumption for Biogenic and 

Non-biogenic Municipal Solid Waste (percent)

2001 2002 2003 2004 2005 2006

Biogenic 77 77 76 76 75 75

Nonbiogenic 23 23 24 24 25 25

Useful Thermal Output. With the implementation of 

the Form EIA-923, “Power Plant Operations Report,” 

in 2008, combined heat and power (CHP) plants are 

required to report total fuel consumed and electric 

power generation4. Beginning with preliminary 

January 2008 data, EIA estimated the allocation of 

the total fuel consumed at CHP plants between electric 

power generation and useful thermal output.

The estimated allocation methodology is summarized 

in the following paragraphs. The methodology was 

retroactively applied to 2004-2007 data. Prior to 

2004, useful thermal output was collect on the Form 

EIA-906 and an estimated allocation of fuel for 

electricity was not necessary.

First, an efficiency factor is determined for each plant 

and prime mover type. Based on data for electric 

power generation and useful thermal output (UTO) 

collected in 2003 (on Form EIA-906, “Power Plant 

Report”) efficiency was calculated for each prime 

mover type at a plant. The efficiency factor is the 

total output in Btu, including electric power and useful 

thermal output (UTO), divided by the total input in 

Btu. Electric power is converted to Btu at 3,412 Btu 

per kilowatthour. 

Second, to calculate the amount of fuel for electric 

power, the gross generation in Btu is divided by the 

efficiency factor. The fuel for UTO is the difference 

between the total fuel reported and the fuel for electric 

power generation. UTO is calculated by multiplying

the fuel for UTO by the efficiency factor. 
90 U.S. Energy Information Administration/Electric Power Annual 2009

In addition, if the total fuel reported is less than the 

estimated fuel for electric power generation, then the 

fuel for electric power generation is equal to the total 

fuel consumed, and the UTO will be zero. 

Issues within Historical Data Series

Receipts and Cost and Quality of Fossil Fuels

Values for receipts of natural gas for 2001 forward do 

not include blast furnace gas or other gas.

Historical data collected on FERC Form 423 and 

published by EIA have been reviewed for consistency 

between volumes and prices and for their consistency 

over time. However, these data were collected by 

FERC for regulatory rather than statistical and 

publication purposes. EIA did not attempt to resolve 

any late filing issues in the FERC Form 423 data. In 

2003, EIA introduced a procedure to estimate for late 

or non-responding entities who were required to report 

on the FERC Form 423. Due to the introduction of 

this procedure, 2003 and later data cannot be directly 

compared to previous years’ data.

Prior to 2008, regulated plants reported receipts data 

on the FERC Form 423. These plants, along with 

unregulated plants, now report receipts data on 

Schedule 2 of Form EIA-923. Because FERC issued 

waivers to Form 423 filing requirements to some 

plants who met certain criteria, and because not all 

types of generators were required to report (only 

steam turbines and combined cycle units reported), a 

significant number of plants either did not submit 

fossil fuel receipts data or submitted only a portion of 

their fossil fuel receipts. Since Form EIA-923 does 

not have exemptions based on generator type, or 

reporting waivers, receipts data from 2008 and later 

cannot be directly compared to previous years’ data 

for the regulated sector. Furthermore, there may be a 

notable increase in fuel receipts beginning with 

January 2008 data. 

Also beginning with January 2008 data, tables for 

total receipts will include imputed quantities for plants 

with capacity one megawatt or more, to be consistent 

with other electric power data. Previous published 

receipts data were from plants over a 50 megawatt 

threshold, which was a legacy of their original 

collection as information for a regulatory agency, not 

as a survey to provide more meaningful estimates of 

totals for statistical purposes. Totals appeared to 

become smaller as more electric production came 

from unregulated plants, until the EIA-423 was 

created to help fill that gap. As a further 

improvement, estimation of all receipts for the 

universe normally depicted in the EPA (i.e., one 

megawatt and above), with associated relative 

standard errors, provides a more complete assessment 

of the market. 

Generation and Consumption

Beginning in 2008, a new method of allocating fuel 

consumption between electric power generation and 

useful thermal output (UTO) was implemented (see 

above). This new methodology evenly distributes a 

combined heat and power (CHP) plant’s losses 

between the two output products (electric power and 

UTO). In the historical data, UTO was consistently 

assumed to be 80 percent efficient and all other losses 

at the plant were allocated to electric power. This 

change causes the fuel for electric power to be lower 

while the fuel for UTO is higher as both are given the 

same efficiency. This results in the appearance of an

increase in efficiency of production of electric power 

between periods. 

Steam Electric Plant Operational Data

Due to suspension of Form EIA-767 in 2007, there is 

a one year break in this data series as data year 2006 

could not be collected.

Sensitive Data (Formerly identified as Data 

Confidentiality). Most of the data collected on the 

Form EIA-923 are not considered business sensitive. 

However, the total delivered cost of fuel delivered to 

nonutilities, commodity cost of fossil fuels, and 

reported fuel stocks at the end of the reporting period 

are considered business sensitive. The release of these 

data must adhere to EIA's “Policy on the Disclosure of 

Individually Identifiable Energy Information in the 

Possession of the EIA” (45Federal Register 59812 

(1980)).

!!!#

This section describes the methodology for calculating 

estimated emissions of carbon dioxide (CO2) from 

electric generating plants for 1989 through 2009, as 

well as the estimated emissions of sulfur dioxide 

(SO2) and nitrogen oxides (NOx) from electric 

generating plants for 2001 through 2009. For a 

description of the methodology used for other years, 

see the technical notes to the Electric Power Annual 

2003. 

Methodology Overview

Initial estimates of uncontrolled SO2 and NOx

emissions for all plants are made by applying an 

emissions factor to fuel consumption data collected by 

EIA on the Form EIA-923. An emission factor is the 

average quantity of a pollutant released from a power 

plant when a unit of fuel is burned, assuming no use of 

pollution control equipment. The basic relationship is:
U.S. Energy Information Administration/Electric Power Annual 2009 91

Emissions = Quantity of Fuel Consumed x 

Emission Factor 

Quantity is defined in physical units (e.g., tons of solid 

fuels, million cubic feet of gaseous fuels, and 

thousands of barrels of liquid fuels) for determining 

NOx and SO2 emissions. As discussed below, 

physical quantities are converted to millions of Btus 

for calculating CO2 emissions.

For some fuels, the calculation of SO2 emissions 

requires including in the formula the sulfur content of 

the fuel measured in percentage of weight. Examples 

include coal and fuel oil. In these cases the formula 

is:

Emissions = Quantity of Fuel Consumed x 

Emission Factor x Sulfur Content 

The fuels that require the percent sulfur as part of the 

emissions calculation are indicated in Table A1, which 

lists the SO2 emission factors used for this report.

In the case of SO2 and NOx emissions, the factor 

applied to a fuel can also vary with the combustion 

system: either a steam-producing boiler, a combustion 

turbine, or an internal combustion engine. In the case 

of boilers, NOx emissions can also vary with the firing 

configuration of a boiler and whether or not the boiler 

is a wet-bottom or dry-bottom design.11

For SO2 and NOx, the initial estimate of uncontrolled 

emissions is reduced to account for the plant’s 

operational pollution control equipment, when data on 

control equipment are available from the historical 

Form EIA-767 survey (i.e., data for the years 2005 

and earlier) and the EIA-860 survey for the years 2007 

and 2008. A special case for removal of SO2 is the 

fluidized bed boiler, in which the sulfur removal 

process is integral with the operation of the boiler. 

The SO2 emission factors shown in Table A1 for 

fluidized bed boilers already account for 90 percent 

removal of SO2 since, in effect, the plant has no 

uncontrolled emissions of this pollutant.

These 

distinctions are shown in Tables A1 and A2.

Although SO2 and NOx emission estimates are made 

for all plants, in many cases the estimated emissions 

can be replaced with actual emissions data collected

by the U.S. Environmental Protection Agency’s 

Continuous Emissions Monitoring System (CEMS) 

program. (CEMS data for CO2 are incomplete and are 

not used in this report.) The CEMS data account for 

the bulk of SO2 and NOx emissions from the electric 

power industry. For those plants for which CEMS 

data are available, the EIA estimates of SO2 and NOx

11 A boiler’s firing configuration relates to the arrangement of the fuel burners 

in the boiler, and whether the boiler is of conventional or cyclone design. 

Wet and dry-bottom boilers use different methods to collect a portion of the 

ash that results from burning coal. For information on wet and dry bottom 

boilers, see the EIA Glossary at

http://www.eia.gov/glossary/index.html. Additional information on wet and 

dry-bottom-boilers and on other aspects of boiler design and operation, 

including the differences between conventional and cyclone designs, can 

be found in Babcock and Wilcox, Steam: Its Generation and Use, 41st

Edition, 2005.

emissions are employed for the limited purpose of 

allocating emissions by fuel, since the CEMS data 

itself do not provide a detailed breakdown of plant 

emissions by fuel. For plants for which CEMS data 

are unavailable, the EIA-computed values are used as 

the final emissions estimates.

There are a number of reasons why the historical data 

are periodically revised. These include data revisions, 

revisions in emission and technology factors, and 

changes in methodology. For instance, the 2008 EPA 

report features a revision in historic CO2 values. This 

revision occurred due to a change in the accepted 

methodology regarding adjustments made for the 

percentage combustion of fuels.

The emissions estimation methodologies are described 

in more detail below.

CO2 Emissions. CO2 emissions are estimated using 

the information on fuel consumption in physical units 

and the heat content of fuel collected on the Forms 

EIA-923 (data for combined heat and power plants) 

and EIA-906 (all other power plants) for the years 

1989 through 2006. In 2007, a new form was 

introduced, the Power Plant Operations Survey (Form 

EIA-923), which includes information on fuel 

consumption previously part of the Form EIA906/EIA-920 Surveys. Fuel consumption data from 

the Form EIA-923 was used to estimate CO2. The heat 

content information is used to convert physical units 

to millions of Btu (MMBtu) consumed. To estimate 

CO2 emissions, the fuel-specific emission factor from 

Table A3 is multiplied by the fuel consumption in 

MMBtu.

The estimation procedure calculates uncontrolled CO2

emissions. CO2 control technologies are currently in 

the early stages of research and there are no 

operational systems installed. Therefore, no estimates 

of controlled CO2 emissions are made. 

SO2 and NOx Emissions. To comply with 

environmental regulations controlling SO2 emissions, 

many coal-fired generating plants have installed flue 

gas desulfurization (FGD) units. Similarly, NOx

control regulations require many plants to install lowNOx burners, selective catalytic reduction systems, or 

other technologies to reduce emissions. It is common 

for power plants to employ two or even three NOx

control technologies; accordingly, the NOx emissions 

estimation approach accounts for the combined effect 

of the equipment (Table A4). However, control 

equipment information is available only for plants that 

reported on the Form EIA-923 and for historical data 

from the Form EIA-767. Both the EIA-923 and the 

historical EIA-767 surveys are limited to plants with 

boilers fired by combustible fuels12 with a minimum 

generating capacity of 10 megawatts (nameplate). 

Pollution control equipment data are unavailable from 

12 Boilers that rely entirely on waste heat to create steam, including the heat 

recovery portion of most combined cycle plants, did not report on the

historical Form EIA-767 or EIA-923. 
92 U.S. Energy Information Administration/Electric Power Annual 2009

EIA sources for plants that did not report on the 

historical EIA-767 survey, or the EIA-923.

The following method is used to estimate SO2 and 

NOx emissions:

For steam electric plants, uncontrolled emissions 

are estimated using the emission factors shown in 

Tables A1 and A2 as well as reported data on fuel 

consumption, sulfur content, and boiler firing 

configuration. Controlled emissions are then 

determined when pollution control equipment is 

present. Although information on control 

equipment was unreported for the years 2006 and 

2007, updates for new installations during this 

period were made based upon Environmental 

Protection Agency data. For 2008, this data was

collected on the Form EIA-923. For SO2, the 

reported efficiency of the plant’s FGD units is 

used to convert uncontrolled to controlled 

emission estimates. For NOx, the reduction 

percentages shown in Table A4 are applied to the 

uncontrolled estimates.

For plants and prime movers not reported on the 

historical Form EIA-767 survey or EIA-923,

uncontrolled emissions are estimated using the 

Table A1 and Table A2 emission factors and the 

following data and assumptions:

o Fuel consumption is taken from the 

Form EIA-923 (for historical data, from the 

Form EIA-920 - for combined heat and 

power plants) or the Form EIA-906 - all other

power plants).

o The sulfur content of the fuel is 

estimated from fuel receipts for the plant 

reported the Form EIA-923 (for historical 

data, from either the Form EIA-423 or the 

FERC Form 423). When plant-specific 

sulfur content data are unavailable, the 

national average sulfur content for the fuel, 

computed from the Form EIA-923 (for 

historical data, from the Form EIA-423 and 

the FERC Form 423), is applied to the plant. 

o As noted earlier, the emission factor for 

plants with boilers depends in part on the 

type of combustion system, including 

whether a boiler is wet-bottom or dry-bottom, 

and the boiler firing configuration. However, 

this boiler information is unavailable for 

steam electric plants that did not report on the 

historical Form EIA-767 or EIA-860. For 

these cases, the plant is assumed to have a 

dry-bottom, non-cyclone boiler using a firing 

method that falls into the “All Other” 

category shown on Table A1.13

13 The “All Other” firing configuration category includes, for example, arch 

firing and concentric firing. For a full list of firing method options for 

reporting on the historical Form EIA-767, see the form instructions, page xi, 

at http://www.eia.gov/cneaf/electricity/forms/eia767/eia767instr.pdf. 

o For the plants that did not report on the 

historical Form EIA-767 or EIA-860,

pollution control equipment data are 

unavailable and the uncontrolled estimates 

are not reduced.

If actual emissions of SO2 or NOx are reported in 

EPA’s CEMS data, the EIA estimates are 

replaced with the CEMS values, using the EIA 

estimates to allocate the CEMS plant-level data 

by fuel. If CEMS data are unavailable, the EIA 

estimates are used as the final values.

3#!#8('$3>

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The quantity conversion is 5 barrels (of 42 U.S. 

gallons each) per short ton (2,000 pounds). Coke from 

petroleum has a heating value of 6.024 million Btu per 

barrel.

'!0'#

The relative standard error (RSE) statistic, usually 

given as a percent, describes the magnitude of 

sampling error that might reasonably be incurred. The 

RSE is the square root of the estimated variance, 

divided by the variable of interest. The variable of 

interest may be the ratio of two variables, or a single 

variable.

The sampling error may be less than the nonsampling 

error. In fact, large RSE estimates found in 

preliminary work with these data have often indicated 

nonsampling errors, which were then identified and 

corrected. Nonsampling errors may be attributed to 

many sources, including the response errors, 

definitional difficulties, differences in the 

interpretation of questions, mistakes in recording or 

coding data obtained, and other errors of collection, 

response, or coverage. These nonsampling errors also 

occur in complete censuses. In a complete census, this 

problem may become unmanageable. 

Using the Central Limit Theorem, which applies to 

sums and means such as are applicable here, there is 

approximately a 68-percent chance that the true total 

or mean is within one RSE of the estimated total. Note 

that reported RSEs are always estimates, themselves, 

and are usually, as here, reported as percents. As an 

example, suppose that a net generation from coal 

value is estimated to be 1,507 total million 

kilowatthours with an estimated RSE of 4.9 percent. 

This means that, ignoring any nonsampling error, 

there is approximately a 68-percent chance that the 

true million kilowatthour value is within 

approximately 4.9 percent of 1,507 million 

kilowatthours (that is, between 1,433 and 1,581 

million kilowatthours). Also under the Central Limit 
U.S. Energy Information Administration/Electric Power Annual 2009 93

Theorem, there is approximately a 95-percent chance 

that the true mean or total is within 2 RSEs of the 

estimated mean or total. 

Note that there are times when a model may not apply, 

such as in the case of a substantial reclassification of 

sales, when the relationship between the variable of 

interest and the regressor data does not hold. In such a 

case, the new information represents only itself, and 

such numbers are added to model results when 

estimating totals. Further, there are times when sample 

data may be known to be in error, or are not reported. 

Such cases are treated as if they were never part of the 

model-based sample, and values are imputed.

5$!#3!8!&'!#

Nonutility power producers consist of entities that 

own or operate electric generating units but are not 

subject to direct economic regulation of rates, such as 

by state utility commissions.. Nonutility power 

producers do not have a designated franchised service 

area. In addition to entities whose primary business is 

the production and sale of electric power, entities with 

other primary business classifications can and do sell 

electric power. These can consist of, for example, 

manufacturing facilities and paper mills.

The Energy Information Administration, in the 

Electric Power Annual and other data products, 

classifies nonutility power producers into the 

following categories:

Independent Power Producers (IPPs) whose 

primary business is selling electricity in the 

public markets. (The combination of the 

utility and IPP businesses are referred to by 

EIA as the Electric Power Sector.)

Power producers whose primary business 

falls under NAICS14

Power producers whose primary business 

falls under NAICS classifications 

Transportation and Public (non-electric) 

Utilities, Wholesale Trade, Retail Trade, 

Finance, Insurance, and Real Estate are 

classified as “commercial” producers.

classifications 

Agriculture, Forestry, Fishing, Mining, 

Construction, or Manufacturing are classified 

as “industrial” producers.

Each of these non-utility sectors are further divided 

into facilities which do or do not operate as combined 

heat and power plants (CHP; often also referred to as 

co-generators). CHP plants produce heat, such as 

steam for use in a manufacturing process, along with 

electricity.

14 Business classifications are based on the North American Industry 

Classification System (NAICS).

The following is a list of the main NAICS 

classifications and the category of primary business 

activity within each classification.

Agriculture, Forestry, and Fishing 

111 Agriculture production-crops

112 Agriculture production, livestock and animal 

specialties

113 Forestry

114 Fishing, hunting, and trapping

115 Agricultural services

Mining

211 Oil and gas extraction 

2121 Coal mining

2122 Metal mining

2123 Mining and quarrying of nonmetallic 

minerals except fuels

Construction

23

Manufacturing

311 Food and kindred products

3122 Tobacco products

314 Textile and mill products

315 Apparel and other finished products made 

from fabrics and similar materials

316 Leather and leather products

321 Lumber and wood products, except furniture

322 Paper and allied products (other than 322122

or 32213)

322122 Paper mills, except building paper

32213 Paperboard mills

323 Printing and publishing

325 Chemicals and allied products (other than 

325188, 325211, 32512, or 325311)

32512 Industrial organic chemicals

325188 Industrial Inorganic Chemicals

325211 Plastics materials and resins

325311 Nitrogenous fertilizers

324 Petroleum refining and related industries 

(other than 32411)

32411 Petroleum refining

326 Rubber and miscellaneous plastic products

327 Stone, clay, glass, and concrete products 

(other than 32731)

32731 Cement, hydraulic

331 Primary metal industries (other than 331111 

or 331312)

331111 Blast furnaces and steel mills

331312 Primary aluminum

332 Fabricated metal products, except machinery 

and transportation equipment

333 Industrial and commercial equipment and 

components except computer equipment
94 U.S. Energy Information Administration/Electric Power Annual 2009

3345 Measuring, analyzing, and controlling 

instruments, photographic, medical, and 

optical goods, watches and clocks

335 Electronic and other electrical equipment and 

components except computer equipment

336 Transportation equipment

337 Furniture and fixtures

339 Miscellaneous manufacturing industries

Transportation and Public Utilities

22 Electric, gas, and sanitary services

2212 Natural gas transmission

2213 Water supply

22131 Irrigation systems

22132 Sewerage systems

481 Transportation by air

482 Railroad transportation

483 Water transportation

484 Motor freight transportation and warehousing

485 Local and suburban transit and interurban 

highway passenger transport

486 Pipelines, except natural gas

487 Transportation services

491 United States Postal Service

513 Communications

562212 Refuse systems

Wholesale Trade

421 to 422

Retail Trade

441 to 454

Finance, Insurance, and Real Estate

521 to 533

Services

512 Motion pictures

514 Business services

514199 Miscellaneous services

541 Legal services

561 Engineering, accounting, research, 

management, and 611 Education services

622 Health services

624 Social services

712 Museums, art galleries, and botanical and 

zoological gardens

713 Amusement and recreation services

721 Hotels

811 Miscellaneous repair services

8111 Automotive repair, services, and parking

812 Personal services

813 Membership organizations related services

814 Private households

Public Administration

92
U.S. Energy Information Administration/Electric Power Annual 2009 95

Table A1. Sulfur Dioxide Uncontrolled Emission Factors

(Units and Factors) 

Fuel, Code, Source and Emission units Combustion System Type/Firing Configuration

Fuel And EIA Fuel Code Source and Tables (As 

appropriate)

Emissions Units

(Lbs = pounds, 

MMCF = million cubic 

feet, 

MG = thousand gallons)

Cyclone

Boiler

Fluidized 

Bed Boiler

Opposed 

Firing

Boiler

Spreader 

Stoker 

Boiler

Tangential

Boiler

All Other

Boiler 

Types

Combustion 

Turbine

Internal 

Combustion 

Engine 

Agricultural Byproducts (AB) Source: 1 Lbs per ton 0.08 0.01 0.08 0.08 0.08 0.08 NA NA

Blast Furnace Gas (BFG) Sources: 1 (including 

footnote 7 within source); 2, 

Table 1.4-2 (including 

footnote d within source)

Lbs per MMCF 0.6 0.06 0.6 0.6 0.6 0.6 0.6 0.6

Bituminous Coal (BIT)* Source: 2, Table 1.1-3 Lbs per ton 38.00 3.8 38.00 38.00 38.00 38.00 NA NA

Black Liquor (BLQ) Source: 1 Lbs per ton ** 7.00 0.70 7.00 7.00 7.00 7.00 NA NA

Distillate Fuel Oil (DFO)* Source: 2, Table 3.1-2a, 3.4-

1 & 1.3-1 

Lbs per MG 157.0 15.70 157.0 157.0 157.0 157.0 140.0 140.0

Jet Fuel (JF)* Assumed to have emissions 

similar to DFO.

Lbs per MG 157.0 15.70 157.0 157.0 157.0 157.0 140.0 140.0

Kerosene (KER)* Assumed to have emissions 

similar to DFO.

Lbs per MG 157.0 15.70 157.0 157.0 157.0 157.0 140.0 140.0 

Landfill Gas (LFG) Sources: 1 (including 

footnote 7 within source); 2, 

Table 1.4-2 (including 

footnote d within source)

Lbs per MMCF 0.6 0.06 0.6 0.6 0.6 0.6 0.6 0.6

Lignite Coal (LIG)* Source: 2, Table 1.7-1 Lbs per ton 30.00 3.00 30.00 30.00 30.00 30.00 NA NA

Municipal Solid Waste 

(MSW)

Source: 1 Lbs per ton 1.70 0.17 1.70 1.70 1.70 1.70 NA NA

Natural Gas (NG) Sources: 1 (including 

footnote 7 within source); 2, 

Table 1.4-2 (including 

footnote d within source)

Lbs per MMCF 0.60 0.06 0.60 0.60 0.60 0.60 0.60 0.60 

Other Biomass Gas (OBG) Sources: 1 (including 

footnote 7 within source); 2, 

Table 1.4-2 (including 

footnote d within source)

Lbs per MMCF 0.60 0.06 0.60 0.60 0.60 0.60 0.60 0.60

Other Biomass Liquids 

(OBL)*

Source: 1 (including 

footnotes 3 and 16 within 

source)

Lbs per MG 157.0 15.70 157.0 157.0 157.0 157.0 140.0 140.0

Other Biomass Solids (OBS) Source: 1 (including 

footnote 11 within source)

Lbs per ton 0.23 0.02 0.23 0.23 0.23 0.23 NA NA

Other Gases (OG) Source: 1 (including 

footnote 7 within source)

Lbs per MMCF 0.60 0.06 0.60 0.60 0.60 0.60 0.60 0.60

Other (OTH) Assumed to have emissions 

similar to NG.

Lbs per MMCF 0.60 0.06 0.60 0.60 0.60 0.60 0.60 0.60

Petroleum Coke (PC)* Source: 1 Lbs per ton 39.00 3.90 39.00 39.00 39.00 39.00 NA NA

Propane Gas (PG) Sources: 1 (including 

footnote 7 within source); 2, 

Table 1.4-2 (including 

footnote d within source)

Lbs per MMCF 0.60 0.06 0.60 0.60 0.60 0.60 0.60 0.60

Residual Fuel Oil (RFO)* Source: 2, Table 1.3-1 Lbs per MG 157.00 15.70 157.00 157.00 157.00 157.00 NA NA

Synthetic Coal (SC)* Assumed to have the 

emissions similar to 

Bituminous Coal.

Lbs per ton 38.00 3.8 38.00 38.00 38.00 38.00 NA NA

Sludge Waste (SLW) Source: 1 (including 

footnote 11 within source)

Lbs per ton ** 2.80 0.28 2.80 2.80 2.80 2.80 NA NA

Subbituminous Coal (SUB)* Source: 2, Table 1.1-3 Lbs per ton 35.00 3.5 35.00 38.00 35.00 35.00 NA NA

Tire-Derived Fuel (TDF)* Source: 1 (including 

footnote 13 within source)

Lbs per ton 38.00 3.80 38.00 38.00 38.00 38.00 NA NA

Waste Coal (WC)* Source: 1 (including 

footnote 20 within source)

Lbs per ton 30.00 3.00 30.00 30.00 30.00 30.00 NA NA

Wood Waste Liquids 

(WDL)*

Source: 1 (including 

footnotes 3 and 16 within 

source)

Lbs per MG 157.0 15.70 157.0 157.0 157.0 157.0 140.0 140.0

Wood Waste Solids (WDS) Source: 1 Lbs per ton 0.29 0.08 0.29 0.08 0.29 0.29 NA NA

Waste Oil (WO)* Source: 2, Table 1.11-2 Lbs per MG 147.00 14.70 147.00 147.00 147.00 147.00 NA NA

Note: * For these fuels, emissions are estimated by multiplying the emissions factor by the physical volume of fuel and the sulfur percentage of the fuel (other fuels do not require the 

sulfur percentage in the calculation). Note that EIA data do not provide the sulfur content of TDF. The value used (1.56 percent) is from U.S. EPA, Control of Mercury Emissions from 

Coal-Fired Electric Utility Boilers, April 2002, EPA-600/R-01-109, Table A-11 (available at:http://www.epa.gov/appcdwww/aptb/EPA-600-R-01-109A.pdf). 

** Although Sludge Waste and Black Liquor consist substantially of liquids, these fuels are measured and reported to EIA in tons.

Sources:

1. Eastern Research Group, Inc. and E.H. Pechan & Associates, Inc., Documentation for the 2002 Electric Generating Unit National Emissions Inventory, Table 6, September 

2004. Prepared for the U.S. Environmental Protection Agency, Emission Factor and Inventory Group (D205-01), Emissions, Monitoring and Analysis Division, Research 

Triangle Park; and 

2. U.S. Environmental Protection Agency, AP 42, Fifth Edition (Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources); available at: 

http://www.epa.gov/ttn/chief/ap42/
96 U.S. Energy Information Administration/Electric Power Annual 2009

Table A2. Nitrogen Oxides Uncontrolled Emission Factors 

(Units and Factors) 

Fuel, Code, Source, and Emission Units Combustion System Type/Firing Configuration

Factors for Wet-Bottom Boilers are in Brackets; All Other Boiler Factors are for Dry-Bottom

Fuel And EIA Fuel Code Source and Tables 

(As appropriate)

Emissions Units

(Lbs = pounds, 

MMCF = million cubic 

feet, 

MG = thousand gallons)

Cyclone

Boiler

Fluidized 

Bed Boiler

Opposed 

Firing

Boiler

Spreader 

Stoker 

Boiler

Tangential

Boiler

All 

Other

Boiler 

Types

Combustion 

Turbine

Internal 

Combustion 

Engine 

Agricultural Byproducts (AB) Source: 1 Lbs per ton 1.20 1.20 1.20 1.20 1.20 1.20 NA NA

Blast Furnace Gas (BFG) Sources: 1 (including 

footnote 7 within source); 

EIA estimates

Lbs per MMCF 15.40 15.40 15.40 15.40 15.40 15.40 30.40 256.55

Bituminous Coal (BIT) Source: 2, Table 1.1-3 Lbs per ton 33.00 5.00 12 [31] 11.00 10.0 [14.0] 12.0

[31.0] 

NA NA

Black Liquor (BLQ) Source: 1 Lbs per ton ** 1.50 1.50 1.50 1.50 1.50 1.50 NA NA

Distillate Fuel Oil (DFO) Source: 2, Tables 3.4-1 & 

1.3-1 

Lbs per MG 24.00 24.00 24.00 24.00 24.00 24.00 122.0 443.8

Jet Fuel (JF) Source: 2, Tables 3.1-2a, 

3.4-1 & 1.3-1

Lbs per MG 24.00 24.00 24.00 24.00 24.00 24.00 118.0 432.0

Kerosene (KER) Source: 2, Tables 3.1-2a, 

3.4-1 & 1.3-1

Lbs per MG 24.00 24.00 24.00 24.00 24.00 24.00 118.0 432.0 

Landfill Gas (LFG) Sources: 1 (including 

footnote 7 within source); 

EIA estimates

Lbs per MMCF 72.44 72.44 72.44 72.44 72.44 72.44 144.0 1215.22 

Lignite Coal (LIG) Source: 2, Table 1.7-1 Lbs per ton 15.00 3.60 6.3 5.80 7.10 6.3 NA NA

Municipal Solid Waste (MSW) Source: 1 Lbs per ton 5.0 5.0 5.0 5.0 5.0 5.0 NA NA

Natural Gas (NG) Source: 2, Tables 1.4-1, 

3.1-1, and 3.4-1 

Lbs per MMCF 280.00 280.00 280.00 280.00 170.00 280.00 328.00 2768.00

Other Biomass Gas (OBG) Sources: 1 (including 

footnote 7 within source); 

EIA estimates

Lbs per MMCF 112.83 112.83 112.83 112.83 112.83 112.83 313.60 2646.48

Other Biomass Liquids (OBL) Source: 1 (including 

footnote 3 within source)

Lbs per MG 19.0 19.0 19.0 19.0 19.0 19.0 NA NA

Other Biomass Solids (OBS) Source: 1 (including 

footnote 11 within source)

Lbs per ton 2.0 2.0 2.0 2.0 2.0 2.0 NA NA

Other Gases (OG) Sources: 1 (including 

footnote 7 within source); 

EIA estimates

Lbs per MMCF 152.82 152.82 152.82 152.82 152.82 152.82 263.82 2226.41 

Other (OTH) Assumed to have emissions 

similar to natural gas.

Lbs per MMCF 280.00 280.00 280.00 280.00 170.00 280.00 328.00 2768.00 

Petroleum Coke (PC) Source: 1 (including 

footnote 8 within source)

Lbs per ton 21.00 5.00 21.00 21.00 21.00 21.00 NA NA

Propane Gas (PG) Sources: 3; EIA estimates Lbs per MMCF 215.00 215.00 215.00 215.00 215.00 215.00 330.75 2791.22

Residual Fuel Oil (RFO) Source: 2, Table 1.3-1 Lbs per MG 47.00 47.00 47.00 47.00 32.00 47.00 NA NA

Synthetic Coal (SC) Assumed to have emissions 

similar to Bituminous Coal.

Lbs per ton 33.00 5.00 12 [31] 11.00 10.0 [14.0] 12.0

[31.0]

NA NA

Sludge Waste (SLW) Source: 1 (including 

footnote 11 within source)

Lbs per ton ** 5.00 5.00 5.00 5.00 5.00 5.00 NA NA

Subbituminous Coal (SUB) Source: 2, Table 1.1-3 Lbs per ton 17.00 5.00 7.4 [24] 8.80 7.2 7.4 

[24.0] 

NA NA

Tire-Derived Fuel (TDF) Source: 1 (including 

footnote 13 within source)

Lbs per ton 33.00 5.00 12 [31] 11.00 10.0 [14.0] 12.0

[31.0]

NA NA

Waste Coal (WC) Source: 1 (including 

footnote 20 within source)

Lbs per ton 15.00 3.60 6.30 5.80 7.10 6.30 NA NA

Wood Waste Liquids (WDL) Source: 1 (including 

footnote 16 within source)

Lbs per MG 5.43 5.43 5.43 5.43 5.43 5.43 NA NA

Wood Waste Solids (WDS) Source: 1 Lbs per ton 2.51 2.00 2.51 1.50 2.51 2.51 NA NA

Waste Oil (WO) Source: 2, Table 1.11-2 Lbs per MG 19.00 19.00 19.00 19.00 19.00 19.00 NA NA

Note: ** Although Sludge Waste and Black Liquor consist substantially of liquids, these fuels are measured and reported to EIA in tons.

Sources:

1. Eastern Research Group, Inc. and E.H. Pechan & Associates, Inc., Documentation for the 2002 Electric Generating Unit National Emissions Inventory, Table 6, September 

2004. Prepared for the U.S. Environmental Protection Agency, Emission Factor and Inventory Group (D205-01); Emissions, Monitoring and Analysis Division, Research 

Triangle Park; 

2. U.S. Environmental Protection Agency, AP 42, Fifth Edition (Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources); available at: 

http://www.epa.gov/ttn/chief/ap42/; and 

3. U.S. Environmental Protection Agency, Factor Information Retrieval (FIRE) Database, Version 6.25; available at: http://www.epa.gov/ttn/chief/software/fire/index.html
U.S. Energy Information Administration/Electric Power Annual 2009 97

Table A3. Carbon Dioxide Uncontrolled Emission Factors 

(Pounds of CO2 per Million Btu) 

 Fuel, Code, Source, and Emission Factor

Fuel And EIA Fuel Code Source and Tables 

(As appropriate)

Factor 

(Pounds of CO2 Per 

Million Btu)***

Bituminous Coal (BIT) Source: 3 205.573R

Distillate Fuel Oil (DFO) Source: 1 161.386

Geothermal (GEO) Estimate from EIA, Office 

of Integrated Analysis and 

Forecasting

16.59983 

Jet Fuel (JF) Source: 1 156.258

Kerosene (KER) Source: 1 159.535 

Lignite Coal (LIG) Source: 3 215.070

Municipal Solid Waste (MSW) Source: 1 (including 

footnote 2 within source)

91.900

Natural Gas (NG) Source: 1 117.080

Petroleum Coke (PC) Source: 1 225.130

Propane Gas (PG) Source: 1 139.178 

Residual Fuel Oil (RFO) Source: 1 173.906

Synthetic Coal (SC) Assumed to have emissions 

similar to Bituminous Coal.

205.573R

Subbituminous Coal (SUB) Source: 3 214.212R

Tire-Derived Fuel (TDF) Source: 1 189.538

Waste Coal (WC) Assumed to have emissions 

similar to Bituminous Coal.

205.573R

Waste Oil (WO) Source: 2, Table 1.11-3

(assumes typical heat 

content of 4.4 MMBtus per 

barrel)

210.000

Note: *** CO2 factors do not vary by combustion system type or boiler firing configuration.

R = Revised.

Sources: 1. U.S. Energy Information Administration, Office of Integrated Analysis and Forecasting, Voluntary Reporting of Greenhouse Gases Program, Table of Fuel and Energy Source: 

Codes and Emission Coefficients; 2. U.S. Environmental Protection Agency, AP 42, Fifth Edition (Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area 

Sources); available at: http://www.epa.gov/ttn/chief/ap42/, and, 3. Environmental Protection Agency, Inventory of Greenhouse Gas Emissions and Sinks, 1990-2008, Annex 2, (April 2010, 

Washington, DC), Table A-36, and, Energy Information Administration, Form EIA-923, "Power Plant Operations Report." Emission factor data has been converted to pounds per million 

Btu. Emission factor data is also an average of annual emission factors for the years 1990-2008 appearing in the Inventory of Greenhouse gas Emissions and Sinks, 1990-2008 weighted by 

annual coal receipts at electric power plant data appearing in the EIA-923 data base over the same time period.
98 U.S. Energy Information Administration/Electric Power Annual 2009

Table A4. Nitrogen Oxides Control Technology Emissions Reduction Factors 

Nitrogen Oxides

Control Technology EIA-Code(s) Reduction Factor(Percent)

Advanced Overfire Air ......................................................... AA 301

Alternate Burners.................................................................. BF 20

Flue Gas Recirculation.......................................................... FR 40

Fluidized Bed Combustor ..................................................... CF 20

Fuel Reburning ..................................................................... FU 30

Low Excess Air .................................................................... LA 20

Low NOx Burners ................................................................. LN 301

Other (or Unspecified) .......................................................... OT 20

Overfire Air .......................................................................... OV 201

Selective Catalytic Reduction ............................................... SR 70

Selective Catalytic Reduction ...............................................

With Low Nitrogen Oxide Burners ..................................... SR and LN 90

Selective Noncatalytic Reduction ......................................... SN 30

Selective Noncatalytic Reduction .........................................

With Low NOx Burners....................................................... SN and LN 50

Slagging................................................................................ SC 20

1. Starting with 1995 data, reduction factors for advanced overfire air, low NOx burners, and overfire air were reduced by 10 percent.

 Sources: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report;" Babcock and Wilcox, Steam 41st Edition, 2005.

Table A5. Unit-of-Measure Equivalents

Unit Equivalent Unit

Kilowatt (kW)............................................................................................................................ 1,000 (One Thousand) Watts

Megawatt (MW) ........................................................................................................................ 1,000,000 (One Million) Watts

Gigawatt (GW) .......................................................................................................................... 1,000,000,000 (One Billion) Watts

Terawatt (TW) ........................................................................................................................... 1,000,000,000,000 (One Trillion) Watts

Gigawatt .................................................................................................................................... 1,000,000 (One Million) Kilowatts

Thousand Gigawatts .................................................................................................................. 1,000,000,000 (One Billion) Kilowatts

Kilowatthours (kWh) ................................................................................................................. 1,000 (One Thousand) Watthours

Megawatthours (MWh).............................................................................................................. 1,000,000 (One Million) Watthours

Gigawatthours (GWh)................................................................................................................ 1,000,000,000 (One Billion) Watthours

Terawatthours (TWh)................................................................................................................. 1,000,000,000,000 (One Trillion) Watthours

Gigawatthours............................................................................................................................ 1,000,000 (One Million) Kilowatthours

Thousand Gigawatthours ........................................................................................................... 1,000,000,000(One Billion) Kilowatthours

U.S. Dollar................................................................................................................................. 1,000 (One Thousand) Mills

U.S. Cent ................................................................................................................................... 10 (Ten) Mills

Source: U.S. Energy Information Administration, Office of Electricity, Renewables, and Uranium Statistics.
U.S. Energy Information Administration/Electric Power Annual 2009 99
100 U.S. Energy Information Administration/Electric Power Annual 2009

.%

The Office of Electricity, Renewables, and Uranium Statistics' 

Master Glossary contains all references used in this publication.

Please use this URL: 

http://www.eia.gov/cneaf/electricity/page/glossary.html