Electric Power Annual 2010

November 2011

Independent Statistics & Analysis 

www.eia.gov

U.S. Department of Energy

Washington, DC 20585
U.S. Energy Information Administration|Electric Power Annual 2010

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

Questions regarding this report should be directed to Infoelectric@eia.gov
Table of Contents

Summary Statistics

ES1. Summary Statistics for the United States

ES2. Supply and Disposition of Electricity

Chapter 1. Capacity

Existing

1.1.A. Net Summer Capacity by Energy Source and Producer Type

1.1.B. Net Summer Capacity of Other Renewables by Producer Type

1.2. Capacity by Energy Source

1.3. Capacity by Producer Type

Planned

1.4. Generating Capacity Additions from New Generators, by Energy Source

1.5. Capacity Additions, Retirements and Changes by Energy Source

Capacity of

1.6.A. Dispersed Generators by Technology Type

1.6.B. Distributed Generators by Technology Type

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

FuelͲSwitching Capacity of

1.7. Generators Reporting Natural Gas as the Primary Fuel, by Producer Type

1.8. Generators Reporting Petroleum Liquids as the Primary Fuel, by Producer Type

1.9. FuelͲSwitching Capacity: From Natural Gas to Petroleum Liquids, by Type of Prime Mover

1.10. FuelͲSwitching Capacity: From Natural Gas to Petroleum Liquids, by Year of Initial Commercial

Operation

Interconnection Cost and Capacity for New Generators,

1.11. by Producer Type

1.12. Interconnection Cost and Capacity for New Generators, by Grid Voltage Class

Chapter 2. Generation and Useful Thermal Output

Net Generation by

2.1.A. Energy Source by Type of Producer

2.1.B. Selected Renewables by Type of Producer

2.2. Useful Thermal Output by Energy Source by Combined Heat and Power Producers

Chapter 3. Fuel and Emissions

Consumption of Fossil Fuels for

3.1. Electricity Generation by Type of Power Producer

3.2. Useful Thermal Output by Type of Combined Heat and Power Producers
3.3. Electricity Generation and for Useful Thermal Output

3.4. EndͲofͲYear Stocks of Coal and Petroleum by Type of Producer

3.5. Receipts, Average Cost, and Quality of Fossil Fuels for the Electric Power Industry

3.6. Receipts and Quality of Coal Delivered for the Electric Power Industry

3.7. Average Quality of Fossil Fuel Receipts for the Electric Power Industry

3.8. Weighted Average Cost of Fossil Fuels for the Electric Power Industry

3.9. Emissions from Energy Consumption at Conventional Power Plants and CombinedͲHeatͲandͲPower

Plants

3.10. Number and Capacity of FossilͲFuel SteamͲElectric Generators with Environmental Equipment

3.11. Average Flue Gas Desulfurization Costs

Chapter 4. Demand, Capacity Resources, and Capacity Margins

4.1.A. Noncoincident Peak Load by North American Electric Reliability Corporation Assessment Area,

1999Ͳ2010 Actual

4.1.B. Noncoincident Peak Load by North American Electric Reliability Corporation Assessment Area,

2010 Actual, 2011Ͳ2015 Projected

Net Internal Demand

4.2.A. Net Energy for Load by North American Electric Reliability Corporation Assessment Area, 1999Ͳ

2010 Actual

4.2.B. Net Energy for Load by North American Electric Reliability CorporationAssessment Area, 2010

Actual, 2011Ͳ2015 Projected

4.3.A. Summer Net Internal Demand, Capacity Resources, and Capacity Margins by North American

Electric Reliability Assessment Area, 1999Ͳ2010 Actual

4.3.B. Summer Net Internal Demand, Capacity Resources, and Capacity Margins by North American

Electric Reliability Corporation Assessment Area, 2010 Actual, 2011Ͳ2015 Projected

4.4.A. Winter Net Internal Demand, Capacity Resources, and Capacity Margins by North American

Electric Reliability Assessment Areas, 2001Ͳ2010 Actual

4.4.B. Winter Net Internal Demand, Capacity Resources, and Capacity Margins by North American

Electric Reliability Corporation Assessment Area, 2010 Actual, 2011Ͳ2015 Projected

4.5.A. Existing Transmission Capacity by HighͲVoltage Size, 2010

4.5.B. Proposed Transmission Capacity Additions by HighͲVoltage Size, 2011Ͳ2017

Chapter 5. Characteristics of the Electric Power Industry

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

Plant

Average

5.2. Capacity Factors by Energy SourceͲforthcoming

5.3. Operating Heat Rate for Selected Energy Sources

5.4. Heat Rates by Prime Mover and Energy Source

Chapter 6. Trade

Electric Power Industry
6.1. Electricity Purchases

6.2. Electricity Sales for Resale

6.3. U.S. Electricity Imports from and Electricity Exports to Canada and Mexico

Chapter 7. Retail Customers, Sales, and Revenue

7.1. Number of Ultimate Customers Served by Sector, by Provider

7.2. Retail Sales and Direct Use of Electricity to Ultimate Customers by Sector, by Provider

7.3. Revenue from Retail Sales of Electricity to Ultimate Customers by Sector, by Provider

7.4. Average Retail Price of Electricity to Ultimate Customers by EndͲUse Sector

7.5. Net Metering and Green Pricing Customers by End Use Sector

Chapter 8. Revenue and Expense Statistics

8.1. Revenue and Expense Statistics for Major U.S. InvestorͲOwned Electric Utilities

8.2. Average Power Plant Operating Expenses for Major U.S. InvestorͲOwned Electric Utilities

8.3. Major U.S. Publicly Owned Electric Utilities (With Generation Facilities)

8.4. Major U.S. Publicly Owned Electric Utilities (Without Generation Facilities)

8.5. U.S. Federally Owned Electric Utilities

8.6. U.S. Cooperative Borrower Owned Electric UtilitiesͲforthcoming

Chapter 9. DemandͲSide Management

9.1. DemandͲSide Management Actual Peak Load Reductions by Program Category

DemandͲSide Management Program

9.2. Annual Effects by Program Category

9.3. Incremental Effects by Program Category

9.4. Annual Effects by Sector

9.5. Incremental Effects by Sector

9.6. Energy Savings

9.7. Direct and Indirect Costs

Appendices

Technical Notes

A1. Sulfur Dioxide Uncontrolled Emission Factors

A2. Nitrogen Oxide Uncontrolled Emission Factors

A3. Carbon Dioxide Uncontrolled Emission Factors

A4. Nitrogen Oxide Control Technology Emissions Reduction Factors

A5. UnitͲofͲMeasure Equivalents

EIA Electric Industry Data Collection
Electric Power Annual 2010

Released: November 2011

Revised: November 2012

Next Update: November 2012

Table ES1. Summary Statistics for the United States, 1999 through 2010

Description 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Net Generation (thousand 

megawatthours)

Coal[1] 1,847,290 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

Petroleum[2] 37,061 38,937 46,243 65,739 64,166 122,225 121,145 119,406 94,567 124,880 111,221 118,061

Natural Gas[3] 987,697 920,979 882,981 896,590 816,441 760,960 710,100 649,908 691,006 639,129 601,038 556,396

Other Gases[4] 11,313 10,632 11,707 13,453 14,177 13,464 15,252 15,600 11,463 9,039 13,955 14,126

Nuclear 806,968 798,855 806,208 806,425 787,219 781,986 788,528 763,733 780,064 768,826 753,893 728,254

Hydroelectric 

Conventional[5] 260,203 273,445 254,831 247,510 289,246 270,321 268,417 275,806 264,329 216,961 275,573 319,536

Other Renewables[6] 167,173 144,279 126,101[R] 105,238 96,525 87,329 83,067 79,487 79,109 70,769 80,906 79,423

Wind 94,652 73,886 55,363 34,450 26,589 17,811 14,144 11,187 10,354 6,737 5,593 4,488

Solar Thermal and 

Photovoltaic 1,212 891 864 612 508 550 575 534 555 543 493 495

Wood and Wood Derived 

Fuels[7] 37,172 36,050 37,300 39,014 38,762 38,856 38,117 37,529 38,665 35,200 37,595 37,041

Geothermal 15,219 15,009 14,840[R] 14,637 14,568 14,692 14,811 14,424 14,491 13,741 14,093 14,827

Other Biomass[8] 18,917 18,443 17,734 16,525 16,099 15,420 15,421 15,812 15,044 14,548 23,131 22,572

Pumped Storage[9] -5,501 -4,627 -6,288 -6,896 -6,558 -6,558 -8,488 -8,535 -8,743 -8,823 -5,539 -6,097

Other[10] 12,855 11,928 11,804[R] 12,231 12,974 12,821 14,232 14,045 13,527 11,906 4,794 4,024

All Energy Sources 4,125,060 3,950,331 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

Net Summer Generating 

Capacity (megawatts)

Coal[1] 316,800 314,294 313,322 312,738 312,956 313,380 313,020 313,019 315,350 314,230 315,114 315,496

Petroleum[2] 55,647 56,781 57,445 56,068 58,097 58,548 59,119 60,730 59,651 66,162 61,837 60,069

Natural Gas[3] 407,028 401,272 397,460[R] 392,876 388,294 383,061 371,011 355,442 312,512 252,832 219,590 195,119

Other Gases[4] 2,700 1,932 1,995 2,313 2,256 2,063 2,296 1,994 2,008 1,670 2,342 1,909

Nuclear 101,167 101,004 100,755 100,266 100,334 99,988 99,628 99,209 98,657 98,159 97,860 97,411

Hydroelectric 

Conventional[5] 78,825 78,518 77,930 77,885 77,821 77,541 77,641 78,694 79,356 78,916 79,359 79,393

Other Renewables[6] 53,886 48,552 38,466[R] 30,069 24,113 21,205 18,717 18,153 16,710 16,101 15,572 15,942

Wind 39,135 34,296 24,651 16,515 11,329 8,706 6,456 5,995 4,417 3,864 2,377 2,252

Solar Thermal and 

Photovoltaic 941 619 536 502 411 411 398 397 397 392 386 389

Wood and Wood Derived 

Fuels[7] 7,037 6,939 6,864 6,704 6,372 6,193 6,182 5,871 5,844 5,882 6,147 6,795

Geothermal 2,405 2,382 2,229[R] 2,214 2,274 2,285 2,152 2,133 2,252 2,216 2,793 2,846

Other Biomass[11] 4,369 4,317 4,186 4,134 3,727 3,609 3,529 3,758 3,800 3,748 3,869 3,660

Pumped Storage[9] 22,199 22,160 21,858 21,886 21,461 21,347 20,764 20,522 20,371 19,664 19,522 19,565

Other[12] 884 888 942 788 882 887 746 684 686 519 523 1,023

All Energy Sources 1,039,137 1,025,400 1,010,171 994,888 986,215 978,020 962,942 948,446 905,301 848,254 811,719 785,927

Demand, Capacity 

Resources, and Capacity 

Margins – Summer

Net Internal Demand 

(megawatts) 747,836 713,106 744,151[R] 766,786[R] 776,479 746,470 692,908 696,752 696,376 674,833 680,941 653,857

Capacity Resources 

(megawatts) 924,922 916,449 909,504[R] 914,397[R] 891,226 882,125 875,870 856,131 833,380 788,990 808,054 765,744

Capacity Margins (percent) 19.2 22.2 18.2 16.1 12.9 15.4 20.9 18.6 16.4 14.5 15.7 14.6

Fuel

Consumption of Fossil 

Fuels for Electricity 

Generation

Coal (thousand tons)[1] 979,684 934,683 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

Petroleum (thousand 

barrels)[2] 65,071 67,668 80,932 112,615 110,634 206,785 203,494 206,653 168,597 216,672 195,228 207,871

Natural Gas (millions of 

cubic feet)[3] 7,680,185 7,121,069 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

Other Gases (millions of 

Btu)[4] 90,058 83,593 96,757 114,904 114,665 109,916 135,144 156,306 131,230 97,308 125,971 126,387

Consumption of Fossil 

Fuels for Thermal Output 

in Combined Heat and 

Power Facilities

Coal (thousand tons)[1] 21,727 20,507 22,168 22,810 23,227 23,833 24,275 17,720 17,561 18,944 20,466 20,373

Petroleum (thousand 

barrels)[2] 10,161 13,161 12,016 19,775 20,371 24,408 25,870 17,939 14,811 18,268 22,266 26,822

Natural Gas (millions of 

cubic feet)[3] 821,775 816,787 793,537 872,579 942,817 984,340 1,052,100 721,267 860,019 898,286 985,263 982,958

Other Gases (millions of 

Btu)[4] 172,081 175,671 203,236 214,321 226,464 238,396 218,295 137,837 146,882 166,161 230,082 223,713

Consumption of Fossil 

Fuels for Electricity 

Generation and Useful 

Thermal Output

Coal (thousand tons)[1] 1,001,411 955,190 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

Petroleum (thousand 

barrels)[2] 75,231 80,830 92,948 132,389 131,005 231,193 229,364 224,593 183,408 234,940 217,494 234,694

Natural Gas (millions of 

cubic feet)[3] 8,501,960 7,937,856 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

Other Gases (millions of 

Btu)[4] 262,138 259,265 299,993 329,225 341,129 348,312 353,438 294,143 278,111 263,469 356,053 350,100
Electric Power Annual 2010

Released: November 2011

Revised: November 2012

Next Update: November 2012

Table ES1. Summary Statistics for the United States, 1999 through 2010

Description 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Stocks at Electric Power 

Sector Facilities (year 

end)

Coal (thousand tons)[13] 174,917 189,467 161,589 151,221 140,964 101,137 106,669 121,567 141,714 138,496 102,296 141,604

Petroleum (thousand 

barrels)[14] 40,800 46,181 44,498 47,203 51,583 50,062 51,434 53,170 52,490 57,031 40,932 54,109

Receipts of Fuel at 

Electricity Generators[15]

Coal (thousand tons)[1] 979,918 981,477 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

Petroleum (thousand 

barrels)[2] 75,285 88,951 96,341 88,347 100,965 194,733 186,655 185,567 120,851 124,618 108,272 145,939

Natural Gas (millions of 

cubic feet)[16] 8,673,070 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

Cost of Fuel at Electricity 

Generators (cents per 

million Btu)[15]

Coal[1] 227 221 207 177 169 154 136 128 125 123 120 122

Petroleum[2] 954 702 1,087 717 623 644 429 433 334 369 418 236

Natural Gas[16] 509 474 902 711 694 821 596 539 356 449 430 257

Emissions (thousand 

metric tons)

Carbon Dioxide (CO2) 2,388,662 2,269,508 2,484,012[R] 2,547,032[R] 2,488,918[R] 2,543,838[R] 2,486,982[R] 2,445,094[R] 2,423,963[R] 2,418,607[R] 2,470,834[R] 2,366,302[R]

Sulfur Dioxide (SO2) 5,401 5,970 7,830 9,042 9,524 10,340 10,309 10,646 10,881 11,174 11,963 12,843

Nitrogen Oxides (NOX) 2,491 2,395 3,330 3,650 3,799 3,961 4,143 4,532 5,194 5,290 5,638 5,955

Trade (million 

megawatthours)

Purchases 5,750 5,029 5,613 5,411 5,503 6,092 6,999 6,980 8,755 7,555 2,346 2,040

Sales for Resale 5,929 5,065 5,681 5,479 5,493 6,072 6,759 6,921 8,569 7,345 2,355 1,998

Electricity Imports and 

Exports (thousand 

megawatthours)

Imports 45,083 52,191 57,019[R] 51,396 42,691 43,929[R] 34,210 30,395 36,779 38,500 48,592 43,215

Exports 19,106 18,138 24,198[R] 20,144 24,271 19,151[R] 22,898 23,975 15,796 16,473 14,829 14,222

Retail Sales and Revenue 

Data – Bundled and 

Unbundled

Number of Ultimate 

Customers (thousands)

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

Commercial 17,674 17,562 17,563 17,377 17,172 16,872 16,607 16,550 15,334 14,867 14,349 14,074

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

Transportation 0 1 1 1 1 1 1 1 NA NA NA NA

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

All Sectors 144,140 143,497 143,276 142,122 140,404 138,367 136,119 134,544 133,624 131,359 127,568 125,945

Sales to Ultimate 

Customers (thousand 

megawatthours)

Residential 1,445,708 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

Commercial 1,330,199 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

Industrial 970,873 917,442 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

Transportation 7,712 7,781 7,700 8,173 7,358 7,506 7,224 6,810 NA NA NA NA

Other NA NA NA NA NA NA NA NA 105,552 113,174 109,496 106,952

All Sectors 3,754,493 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

Direct Use 131,910 126,938 132,197[R] 125,670[R] 146,927 150,016 168,470 168,295 166,184 162,649 170,943 171,629

Total Disposition 3,886,403 3,723,803 3,865,159[R] 3,890,231[R] 3,816,845 3,810,984 3,715,949 3,662,029 3,631,650 3,557,107 3,592,357 3,483,716

Revenue From Ultimate 

Customers (million 

dollars) 

Residential 166,782 157,008 155,433 148,295 140,582 128,393 115,577 111,249 106,834 103,158 98,209 93,483

Commercial 135,559 132,940 138,469 128,903 122,914 110,522 100,546 96,263 87,117 85,741 78,405 72,771

Industrial 65,750 62,504 68,920 65,712 62,308 58,445 53,477 51,741 48,336 50,293 49,369 46,846

Transportation 815 828 827 792 702 643 519 514 NA NA NA NA

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

All Sectors 368,906 353,280 363,650 343,703 326,506 298,003 270,119 259,767 249,411 247,343 233,163 219,896

Average Retail Price 

(cents per kilowatthour)

Residential 11.54 11.51 11.26 10.65 10.4 9.45 8.95 8.72 8.44 8.58 8.24 8.16

Commercial 10.19 10.17 10.36 9.65 9.46 8.67 8.17 8.03 7.89 7.92 7.43 7.26

Industrial 6.77 6.81 6.83 6.39 6.16 5.73 5.25 5.11 4.88 5.05 4.64 4.43

Transportation 10.57 10.65 10.74 9.7 9.54 8.57 7.18 7.54 NA NA NA NA

Other NA NA NA NA NA NA NA NA 6.75 7.2 6.56 6.35

All Sectors 9.83 9.82 9.74 9.13 8.9 8.14 7.61 7.44 7.2 7.29 6.81 6.64

Revenue and Expense 

Statistics (million dollars)

Major Investor Owned

Utility Operating Revenues 284,373 276,124 298,962 270,964 275,501 265,652 238,759 230,151 219,609 267,276 233,915 213,090

Utility Operating Expenses 250,122 244,243 267,263 241,198 245,589 236,786 206,960 201,057 189,062 234,910 210,250 180,467

Net Utility Operating 

Income 34,251 31,881 31,699 29,766 29,912 28,866 31,799 29,094 30,548 32,366 23,665 32,623
Electric Power Annual 2010

Released: November 2011

Revised: November 2012

Next Update: November 2012

Table ES1. Summary Statistics for the United States, 1999 through 2010

Description 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Major Publicly Owned 

(with Generation 

Facilities)

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

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

Net Electric Operating 

Income NA NA NA NA NA NA NA 4,268 4,138 5,238 5,598 5,493

Major Publicly Owned 

(without Generation 

Facilities)

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

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

Net Electric Operating 

Income NA NA NA NA NA NA NA 974 843 597 549 617

Major Federally Owned

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

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

Net Electric Operating 

Income NA NA NA NA NA NA NA 3,035 2,805 2,445 2,546 2,411

Major Cooperative 

Borrower Owned

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

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

Net Electric Operating 

Income NA 3,852 3,576 3,365 3,173 2,879 2,822 2,867 2,897 2,696 2,647 2,541

Demand-Side Management 

(DSM) Data[17]

Actual Peak Load 

Reductions (megawatts)

Total Actual Peak Load 

Reduction 33,283 31,682 31,735 30,253 27,240 25,710 23,532 22,904 22,936 24,955 22,901 26,455

DSM Energy Savings 

(thousand 

megawatthours)

Energy Efficiency 86,926 76,891 74,861 67,134 62,951 58,891 52,662 48,245 52,285 52,946 52,827 49,691

Load Management 913 1,015 1,813 1,857 865 1,006 2,047 2,020 1,790 990 875 872

DSM Cost (million 

dollars)

Total Cost 4,220 3,594 3,175 2,523 2,051 1,921 1,557 1,297 1,626 1,630 1,565 1,424

[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.

[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.

 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 EIA767, "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 EIA-920 "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.

[17] Data presented are reflective of large utilities.

 NA = Not available. 

[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.

 R = Revised. 

[13] Anthracite, bituminous, subbituminous, lignite, and synthetic coal; excludes waste coal.

 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 independent rounding.

[16] Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately.

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

[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 commerical and industrial power-producing facilities. Reciepts, 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 reciepts beginning with 2008 data. Receipts of coal include imported coal.

[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).
Electric Power Annual 2010

Released: November 2011

Revised: March 2012Next Update: November 2012Table ES2. Supply and Disposition of Electricity, 1999 through 2010(Million Megawatthours)

Category 2010 2009 2008 2007 2006 2005 2004 2003 2002 

SupplyGeneration Electric Utilities 2,472 2,373 2,475 2,504 2,484 2,475 2,505 2,462 2,549  Independent Power Producers 1,339 1,278 1,332 1,324 1,259 1,247 1,119 1,063 955  Combined Heat and Power, Electric 162 159 167 177 165 180 184 196 194  Electric Power Sector Generation Subtotal 3,972 3,810 3,974 4,005 3,908 3,902 3,808 3,721 3,698  Combined Heat and Power, Commercial 9 8 8 8 8 8 8 7 7  Combined Heat and Power, Industrial 144 132 137 143 148 145 154 155 153  Industrial and Commercial Generation Subtotal 153 140 145 151 157 153 162 162 160 Total Net Generation 4,125 3,950 4,119 4,157 4,065 4,055 3,971 3,883 3,858 Total Imports 45 52 57 51 43 44 34 30 37 Total Supply 4,170 4,003 4,176 4,208 4,107 4,099 4,005 3,914 3,895 Disposition Retail Sales Full-Service Providers 3,365 3,289 3,434 3,468 3,438 3,413 3,318 3,285 3,324  Energy-Only Providers 379 295 286 283 219 237 222 189 141  Facility Direct Retail Sales 10 13 14 14 12 11 8 20 NA Total Electric Industry Retail Sales 3,754 3,597 3,733 3,765 3,670 3,661 3,547 3,494 3,465 Direct Use 132 127 132 126 147 150 168 168 166 Total Exports 19 18 24 20 24 19 23 24 16 Losses and Unaccounted For 265 261 287 298 266 269 266 228 248 Total Disposition 4,170 4,003 4,176 4,208 4,107 4,099 4,005 3,914 3,895  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 

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 transmissunaccounted 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 P

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

Electrical Export/Import Data:" Canada data - National Energy Board of Canada (metered energy firm and interruptible).
Electric Power Annual 2010

Released: November 2011

Revised: December 2011

Next Update: November 2012

Table 1.1.A. Existing Net Summer Capacity by Energy Source and Producer Type, 2000 through 2010

(Megawatts)

Period Coal[1] Petroleum [2] Natural Gas[3] Other Gases[4] Nuclear Hydroelectric 

Conventional[5]

Other Renewables[6]

Hydroelectric 

Pumped 

Storage[7]

Other[8] Total

Total (All Sectors)

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 57,445 397,460 1,995 100,755 77,930 38,466 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

2010 316,800 55,647 407,028 2,700 101,167 78,825 53,811[R] 22,199 884 1,039,062[R]

Electricity Generators, Electric Utilities

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

2010 235,707 28,972 184,231 539 54,369 72,974 6,316[R] 18,969 -- 602,076[R]

Electricity Generators, Independent Power Producers

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 24,823 179,169 -- 46,379 5,433 28,139 3,193 46 359,044

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

2010 71,214 24,867 178,190 8 46,798 5,489 41,014 3,230 77 370,887

Combined Heat and Power, Electric Power

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

2010 5,451 766 29,006 182 -- -- 846 -- -- 36,250

Combined Heat and Power, Commercial[9]

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

2010 418 368 1,155 5 -- 22 520 -- 3 2,490

Combined Heat and Power, Industrial[9]

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

2010 4,010 674 14,447 1,967 -- 341 5,116 -- 804 27,359

[R] Revised.

[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.

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.

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

[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.

5
Electric Power Annual 2010

Released: November 2011

Revised: December 2011

Next Update: November 2012

Table 1.1.B. Existing Net Summer Capacity of Other Renewables by Producer Type, 2000 through 2010

(Megawatts)

Period Wind Solar Thermal and 

Photovoltaic

Wood and Wood-Derived 

Fuels[1] Geothermal Other Biomass[2] Total (Other Renewables)

Total (All Sectors)

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 2,229 4,186 38,466

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

2010 39,135 866[R] 7,037 2,405 4,369 53,811[R]

Electricity Generators, Electric Utilities

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

2010 5,338 79[R] 414 159 325 6,316[R]

Electricity Generators, Independent Power Producers

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 2,070 2,891 28,139

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

2010 33,784 780 1,275 2,246 2,930 41,014

Combined Heat and Power, Electric Power

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

2010 -- -- 393 -- 453 846

Combined Heat and Power, Commercial[3]

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

2010 11 6 8 -- 496 520

Combined Heat and Power, Industrial[3]

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

2010 2 1 4,948 -- 165 5,116

[R] Revised.

[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 woodbased 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.

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."

6
Electric Power Annual 2010

Released: November 2011

Revised: January 2012

Next Update: November 2012

Table 1.2. Existing Capacity by Energy Source, 2010

(Megawatts)

Energy Source Number of 

Generators

Generator

Nameplate Capacity 

Net Summer 

Capacity

Net Winter 

Capacity

Coal[1] 1,396 342,296 316,800 319,186

Petroleum[2] 3,779 62,504 55,647 59,577

Natural Gas[3] 5,529 467,214 407,028 438,727

Other Gases[4] 106 3,130 2,700 2,691

Nuclear 104 106,731 101,167 102,984

Hydroelectric Conventional[5] 4,020 78,204 78,825 78,468

Wind 689 39,516 39,135 39,185

Solar Thermal and Photovoltaic[R] 180 912 866 771

Wood and Wood Derived Fuels[6] 346 7,949 7,037 7,094

Geothermal 225 3,498 2,405 2,590

Other Biomass[7] 1,574 5,043 4,369 4,440

Pumped Storage 151 20,538 22,199 22,064

Other[8] 51 1,027 884 896

Total[R] 18,150 1,138,563 1,039,062 1,078,673

[R] Revised.

[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."

[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
Electric Power Annual 2010

Released: November 2011

Revised: January 2012

Next Update: November 2012

Table 1.3. Existing Capacity by Producer Type, 2010

(Megawatts)

Producer Type Number of Generators Generator Nameplate 

Capacity Net Summer Capacity Net Winter Capacity

Electric Power Sector

Electric Utilities[R] 9,519 654,884 602,076 622,251

Independent Power Producers 5,708 407,978 370,887 385,804

Total [R] 15,227 1,062,862 972,963 1,008,055

Combined Heat and Power Sector

Electric Power[1] 628 41,613 36,250 39,129

Commercial[2] 683 2,796 2,490 2,596

Industrial[2] 1,612 31,294 27,359 28,893

Total 2,923 75,702 66,099 70,618

Total All Sectors[R] 18,150 1,138,563 1,039,062 1,078,673

[R] Revised.

[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."

8
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 1.4. Planned Generating Capacity Additions from New Generators, by Energy Source, 2011-2015

(Count, Megawatts)

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

U.S. Total 521 25,602 23,733 24,565

Coal[1] 8 4,873 4,563 4,595

Petroleum[2] 26 548 516 519

Natural Gas 89 11,256 9,988 10,792

Other Gases[3] -- -- -- --

Nuclear -- -- -- --

Hydroelectric Conventional[4] 26 33 33 33

Wind 92 7,972 7,763 7,763

Solar Thermal and Photovoltaic 171 586 577 569

Wood and Wood Derived Fuels[5] 9 155 129 127

Geothermal 7 31 21 22

Other Biomass[6] 92 128 123 124

Pumped Storage -- -- -- --

Other[7] 1 20 20 20

U.S. Total 295 23,506 22,042 22,670

Coal[1] 7 4,304 4,105 4,181

Petroleum[2] 14 70 60 68

Natural Gas 65 8,756 7,967 8,401

Other Gases[3] 4 808 597 638

Nuclear 1 1,270 1,122 1,164

Hydroelectric Conventional[4] 6 155 146 146

Wind 49 4,711 4,711 4,711

Solar Thermal and Photovoltaic 107 2,717 2,711 2,700

Wood and Wood Derived Fuels[5] 15 485 443 454

Geothermal 7 144 104 130

Other Biomass[6] 20 86 77 77

Pumped Storage -- -- -- --

Other[7] -- -- -- --

U.S. Total 143 12,001 11,375 11,652

Coal[1] 1 290 290 290

Petroleum[2] -- -- -- --

Natural Gas 40 6,028 5,529 5,803

Other Gases[3] 1433

Nuclear -- -- -- --

Hydroelectric Conventional[4] 6 224 222 222

Wind 20 2,221 2,221 2,221

Solar Thermal and Photovoltaic 59 2,673 2,606 2,606

Wood and Wood Derived Fuels[5] 3 206 185 185

Geothermal 5 185 160 162

Other Biomass[6] 8 171 161 162

Pumped Storage -- -- -- --

Other[7] -- -- -- --

U.S. Total 63 8,199 7,351 7,707

Coal[1] 2 515 482 489

Petroleum[2] -- -- -- --

Natural Gas 30 4,291 3,888 4,214

Other Gases[3] 3 840 593 596

Nuclear -- -- -- --

Hydroelectric Conventional[4] 10 263 262 262

Wind 4 349 349 349

Solar Thermal and Photovoltaic 12 1,848 1,692 1,712

Wood and Wood Derived Fuels[5] -- -- -- --

Geothermal -- -- -- --

Other Biomass[6] 2 93 85 85

Pumped Storage -- -- -- --

Other[7] -- -- -- --

2011

2012

2013

2014

Table Continued on Next Page

9
Table 1.4. Planned Generating Capacity Additions from New Generators, by Energy Source, 2011-2015 (Cont'd)

(Count, Megawatts)

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

U.S. Total 49 8,446 7,772 8,157

Coal[1] 1 41 41 41

Petroleum[2] -- -- -- --

Natural Gas 34 7,387 6,780 7,140

Other Gases[3] -- -- -- --

Nuclear -- -- -- --

Hydroelectric Conventional[4] 1 22 22 22

Wind -- -- -- --

Solar Thermal and Photovoltaic 3 471 471 471

Wood and Wood Derived Fuels[5] -- -- -- --

Geothermal 7 460 400 425

Other Biomass[6] 3 65 58 58

Pumped Storage -- -- -- --

Other[7] -- -- -- --

[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, 2010. • 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."

[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).

2015

10
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 1.5. Capacity Additions, Retirements and Changes by Energy Source, 2010

(Count, Megawatts)

Number of 

Gene-rators

Generator 

Nameplate 

Capacity 

Net 

Summer 

Capacity 

Net Winter 

Capacity

Number of 

Gene-rators

Generator 

Nameplate 

Capacity

Net 

Summer 

Capacity

Net Winter 

Capacity

Generator 

Nameplate 

Capacity

Net 

Summer 

Capacity

Net Winter 

Capacity

Coal[2] 9 5,836 5,246 5,268 35 1,678 1,528 1,529 -585 -1,213 -916

Petroleum[3] 53 1,001 804 806 59 1,114 1,043 1,046 -636 -895 -1,061

Natural Gas[4] 106 7,544 6,543 7,206 67 2,333 2,168 2,236 2,201 1,382 1,447

Other Gases[5] 2 101 101 101 2 8 6 6 820 673 696

Nuclear -- -- -- -- -- -- -- -- 113 164 495

Hydroelectric 

Conventional 7 22 21 19 2 1 1 1274 287 324

Wind 69 4,565 4,545 4,546 2 2 2 2271 296 291

Solar Thermal and 

Photovoltaic 61 337 313 300 -- -- -- -- 11 10 10

Wood and Wood Derived 

Fuels[6] 3 94 74 78 9 96 97 97 122 121 121

Geothermal 2 24 13 19 -- -- -- -- 54 10 10

Other Biomass[7] 105 139 129 133 32 38 32 34 -64 -45 -40

Pumped Storage -- -- -- -- -- -- -- -- -- 39 1

Other[8] 1 1 1 1 250 39 39 34 34 34

Total 418 19,661 17,789 18,477 210 5,321 4,916 4,989 2,612 863 1,412

[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.

Energy Source

Generator Additions Generator Retirements Changes to Existing Capacity[1]

[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."

11
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 1.6.A. Capacity of Dispersed Generators by Technology Type, 2005 through 2010(Count, Megawatts)

Internal 

Combustion

Combustion 

Turbine

Steam 

Turbine Hydroelectric Wind and Other Wind Photovoltaic Storage O

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (M

2005* 4290 335 126 2 13 

2006* 6524 346 157 3 8 

2007* 7866 268 102 31 30 

2008* 9335 86 248 34 70 

2009* 9751 329 204 81 108 

2010 2771 64 14 8 6 95 7 

Period

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 

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."

 * During these years, generators above 1 MW were also counted. This changed in 2010 when only generators smaller than 1 MW were counted.

12
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 1.6.B. Capacity of Distributed Generators by Technology Type, 2005 through 2010(Count, Megawatts)

Internal 

Combustion

Combustion 

Turbine

Steam 

Turbine Hydroelectric Wind and Other Wind Photovoltaic Storage Oth

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW

2005[1]* 4025 1917 1830 999 995 

2006* 3646 1298 2582 806 1081 

2007* 4624 1990 3596 1051 1441 

2008* 5112 1949 3060 1154 1588 

2009* 4339 4147 4621 1166 1729 

2010 887 186 110 97 99 236 0 

 * During these years, generators above 1 MW were also counted. This changed in 2010 when only generators smaller than 1 MW were counted.

Period

[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 loca

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."

13
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 1.6.C. Total Capacity of Dispersed and Distributed Generators by Technology Type, 2005 through 2010(Count, Megawatts)

Internal 

Combustion

Combustion 

Turbine

Steam 

Turbine Hydroelectric Wind and Other Wind Photovoltaic Storage Ot

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (M

2005[1]* 8315 2252 1956 1001 1008 

2006* 10169 1644 2739 809 1088 

2007* 12490 2258 3698 1082 1471 

2008* 14447 2035 3308 1188 1658 

2009* 14090 4476 4825 1248 1838 

2010 3658 250 124 106 105 332 7 

 * During these years, generators above 1 MW were also counted. This changed in 2010 when only generators smaller than 1 MW were counted.

Period

[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 ar

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 distributio

includes generators for which technology is not specified.

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

14
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 1.7. Fuel Switching Capacity of Operable Generators Reporting Natural Gas as the Primary Fuel, by Producer Type, 2010

(Megawatts, Percent)

Net Summer Capacity of 

Natural Gas-Fired 

Generators Reporting the 

Ability to Switch to 

Petroleum Liquids[1]

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 184,231 76,469 41.5 74,390 25,957

Independent Power Producers 178,190 39,897 22.4 38,967 11,057

Combined Heat and Power, Electric Power[2] 29,006 6,282 21.7 6,013 572

Electric Power Sector Subtotal 391,427 122,648 31.3 119,370 37,586

Combined Heat and Power, Commercial[3] 1,155 524 45.3 512 134

Combined Heat and Power, Industrial[3] 14,447 1,241 8.6 1,190 262

All Sectors 407,028 124,412 30.6 121,072 37,982

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

Producer Type

Total Net Summer 

Capacity of All 

Generators Reporting 

Natural Gas as the 

Primary Fuel

Fuel-Switchable Part of Total

[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 Combined Heat and Power plants are included in Electric Utilities.

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

15
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 1.8. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum Liquids by Type of Prime Mover, 2010

(Megawatts, Percent)

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 28,972 9,606 33.2 9,206

Independent Power Producers 24,867 12,240 49.2 10,469

Combined Heat and Power Electric Power[2] 766 450 58.7 450

Electric Power Sector Subtotal 54,605 22,296 40.8 20,124

Combined Heat and Power Commercial[3] 368 19 5.3 19

Combined Heat and Power Industrial[3] 674 44 6.5 35

All Sectors 55,647 22,359 40.2 20,178

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

Producer Type

Total Net Summer Capacity 

of All Generators Reporting 

Petroleum as the Primary 

Fuel[1]

Fuel-Switchable Part of Total

[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 Combined Heat and Power plants are included in Electric Utilities.

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

16
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 1.9. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum Liquids by Type of Prime Mover, 2010

(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 

Liquids[1]

Steam Generator 196 27,441 17,135

Combined Cycle 401 41,684 7,288

Internal Combustion 331 1,054 335

Gas Turbine 927 54,234 13,224

All Fuel Switchable Prime Movers 1,855 124,412 37,982

[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."

Notes: • A small number of generators for which waste heat is the primary energy source may be included.

17
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 1.10. Fuel-Switching Capacity of Operable Generators: From Natural Gas to Petroleum Liquids, by Year of Initial Commercial Operation, 2010

(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 

Liquids[1]

pre-1970 363 14,248 9,585

1970-1974 387 17,937 9,599

1975-1979 105 10,353 5,971

1980-1984 48 969 131

1985-1989 110 3,346 461

1990-1994 210 12,873 2,141

1995-1999 133 9,933 2,191

2000-2004 373 39,072 5,819

2005-2009 105 14,424 2,064

2010 21 1,257 20

Total 1,855 124,412 37,982

[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."

Notes: • A small number of generators for which waste heat is the primary energy source may be included.

18
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 1.11. Interconnection Cost and Capacity for New Generators, by Producer Type, 2009 and 2010

Sector Units[1]

Nameplate Capacity 

(megawatts)[1]

Cost

(thousand dollars)[1]

2009

Total 382 23,144 819,680

Electric Utilities[2] 106 10,939 237,751

Independent Power Producers[3] 244 11,590 561,057

Commercial[4] 20 58 10,587

Industrial[4] 12 557 10,285

2010

Total 418 19,661 493,909

Electric Utilities[2] 155 9,199 129,232

Independent Power Producers[3] 213 9,335 323,909

Commercial[4] 37 205 26,926

Industrial[4] 13 922 13,842

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."

[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.

19
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 1.12. Interconnection Cost and Capacity for New Generators, by Grid Voltage Class, 2009 and 2010

Voltage Group Units[1] Nameplate Capacity[1]

(megawatts)

Cost[1]

(thousand dollars)

2009

Total 382 23,144 819,680

Less than 100 kV 207 1,831 96,452

Between 100 kV and 199 kV 78 6,086 268,834

Greater than 200 kV 97 15,227 454,394

2010

Total 418 19,661 493,909

Less than 100 kV 287 2,223 66,801

Between 100 kV and 199 kV 69 4,305 145,940

Greater than 200 kV 62 13,133 281,168

[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.

Notes: • 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. • In 2010, EIA changed the voltage groupings to ones that are more commonly used by stakeholders.

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

20
Electric Power Annual 2011

Released: November 2011

Revised: December 2011

Next Update: November 2012

Table 2.1.A Net Generation by Energy Source by Type of Producer, 1999 through 2010

(Thousand Megawatthours)

Period Coal 1 Petroleum 2 Natural Gas Other Gases 3 Nuclear Hydroelectric 

Conventional 4

Other 

Renewables 5

Hydroelectric 

Pumped Storage 6 Other 7 Total

Total (All Sectors)

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 11,707 806,208 254,831 126,101 -6,288 11,804 4,119,388

2009 1,755,904 38,937 920,979 10,632 798,855 273,445 144,279 -4,627 11,928 3,950,331

2010 1,847,290 37,061 987,697 11,313 806,968 260,203 167,173 -5,501 12,855 4,125,060

Electricity Generators, Electric Utilities

1999 1,767,679 86,929 296,381 -- 725,036 299,914 3,716 -5,982 -- 3173674

2000 1,696,619 72,180 290,715 -- 705,433 253,155 2,241 -4,960 -- 3015383

2001 1,560,146 78,908 264,434 -- 534,207 197,804 1,666 -7,704 486 2629946

2002 1,514,670 59,125 229,639 206 507,380 242,302 3,089 -7,434 480 2549457

2003 1,500,281 69,930 186,967 243 458,829 249,622 3,421 -7,532 519 2462281

2004 1,513,641 73,694 199,662 374 475,682 245,546 3,692 -7,526 467 2505231

2005 1,484,855 69,722 238,204 10 436,296 245,553 4,945 -5,383 643 2474846

2006 1,471,421 40,903 282,088 30 425,341 261,864 6,588 -5,281 700 2483656

2007 1,490,985 40,719 313,785 141 427,555 226,734 8,953 -5,328 586 2504131

2008 1,466,395 28,124 320,190 46 424,256 229,645 11,308 -5,143 545 2475367

2009 1,322,092 25,217 349,166 96 417,275 247,198 14,617 -3,369 483 2372776

2010 1,378,028 26,065 392,616 52 424,843 236,104 17,927 -4,466 462 2,471,632

Electricity Generators, Independent Power Producers

1999 64,387 17,906 60,264 36 3,218 14,749 40,460 -115 -- 200905

2000 213,956 25,795 108,712 181 48,460 18,183 42,831 -579 -- 457540

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 82,358 -1,145 5,616 1,332,068

2009 389,783 6,684 373,554 1 381,579 24,304 97,928 -1,259 5,341 1,277,916

2010 419,459 6,312 386,755 15 382,126 22,351 117,201 -1,035 5,529 1,338,712

Combined Heat and Power, Electric Power 8

1999 26,551 6,704 116,351 1,571 -- -- 4,088 -- 139 155404

2000 32,536 7,217 118,551 1,847 -- -- 4,330 -- 125 164606

2001 31,003 5,984 127,966 576 -- -- 3,393 -- 595 169515

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 184259

2005 36,541 5,275 130,655 3,765 -- 10 3,415 -- 716 180375

2006 36,014 4,465 116,430 4,220 -- 8 3,456 -- 766 165359

2007 36,428 4,398 128,444 3,898 -- 6 3,450 -- 733 177356

2008 36,884 3,612 119,043 3,153 -- 6 3,417 -- 798 166915

2009 29,248 3,910 118,286 2,961 -- 4 3,932 -- 805 159146

2010 30,250 2,302 122,019 2,901 -- -- 3,754 -- 816 162,042

Combined Heat and Power, Commercial 9

1999 995 434 4,607 * -- 115 2,412 -- * 8563

2000 1,097 432 4,262 * -- 100 2,012 -- * 7903

2001 995 438 4,434 * -- 66 1,025 -- 457 7416

2002 992 431 4,310 * -- 13 1,065 -- 603 7415

2003 1,206 423 3,899 -- -- 72 1,302 -- 594 7496

2004 1,340 499 3,969 -- -- 105 1,575 -- 781 8270

2005 1,353 375 4,249 -- -- 86 1,673 -- 756 8492

2006 1,310 235 4,355 * -- 93 1,619 -- 758 8371

2007 1,371 189 4,257 -- -- 77 1,614 -- 764 8273

2008 1,261 142 4,188 -- -- 60 1,555 -- 720 7926

2009 1,096 163 4,225 -- -- 71 1,769 -- 842 8165

21
2010 1,111 124 4,725 3 -- 80 1,714 -- 834 8,592

Combined Heat and Power, Industrial 9

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 2,963 75,748 7,574 -- 1,868 26,033 -- 4,457 132,329

2010 18,441 2,258 81,583 8,343 -- 1,668 26,576 -- 5,214 144,082

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.

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.

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.

 Note: Totals may not equal sum of components because of independent rounding

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. 

22
Electric Power Annual 2011

Released: November 2011

Revised: December 2011

Next Update: November 2012

Table 2.1.B. Net Generation by Selected Renewables by Type of Producer, 1999 through 2010

(Thousand Megawatthours)

Period Wind Solar Thermal and 

Photovoltaic

Wood and WoodDerived Fuels 1 Geothermal Other Biomass 2 Total (Other 

Renewables)

Total (All Sectors)

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 14,840 17,734 126,101

2009 73,886 891 36,050 15,009 18,443 144,279

2010 94,652 1,212 37,172 15,219 18,917 167,173

Electricity Generators, Electric Utilities

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

2010 13,089 101 2,328 1,118 1,291 17,927

Electricity Generators, Independent Power Producers

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 13,643 12,659 82,358

2009 63,538 863 6,733 13,826 12,968 97,928

2010 81,547 1,105 7,007 14,101 13,441 117,201

Combined Heat and Power, Electric Power 3

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

23
2008 -- -- 2,004 -- 1,413 3,417

2009 -- -- 2,258 -- 1,674 3,932

2010 -- -- 2,111 -- 1,644 3,754

Combined Heat and Power, Commercial 4

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

2010 16 5 21 -- 1,672 1,714

Combined Heat and Power, Industrial 4

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 -- -- 25,292 -- 740 26,033

2010 -- 2 25,706 -- 869 26,576

 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.

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. 

24
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 2.2. Useful Thermal Output by Energy Source by Combined Heat and Power Producers, 1999 through 2010

(Billion Btus)

Period Coal 1 Petroleum 2 Natural Gas Other Gases 3 Other Renewables 4 Other 5 Total

Total Combined Heat and Power

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 52,899 513,002 99,556 546,974 33,287 1,527,276

2010 300,303 41,361 524,494 91,439 581,310 28,755 1,567,662

Combined Heat and Power, Electric Power

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

2010 38,325 5,810 186,772 19,707 17,589 5,040 273,244

Combined Heat and Power, Commercial

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 -- 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

2010 19,216 1,061 29,791 13 7,917 5,333 63,330

Combined Heat and Power, Industrial

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 44,863 296,225 79,726 520,898 22,471 1,187,669

2010 242,762 34,490 307,931 71,719 555,803 18,382 1,231,088

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.

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.

25
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 3.1. Consumption of Fossil Fuels for Electricity Generation by Type of Power Producer, 1999 through 2010

Coal Petroleum Natural Gas Other Gases

(Thousand Tons)[1] (Thousand Barrels)[2] (Thousand Mcf) (Billion Btu)[3]

Total (All Sectors)

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 67,668 7,121,069 83,593

2010 979,684 65,071 7,680,185 90,058

Electricity Generators, Electric Utilities

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

2010 721,431 47,431 3,290,993 771

Electricity Generators, Independent Power 

Producers

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 2,839,310 16

2010 233,082 12,471 2,948,473 241

Combined Heat and Power, Electric Power[4]

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

2010 16,731 2,575 845,950 18,579

Combined Heat and Power, Commercial[5]

Type of Power Producer and Period

26
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 --

2010 314 172 39,462 12

Combined Heat and Power, Industrial[5]

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 3,328 519,799 62,269

2010 8,125 2,422 555,307 70,454

[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.

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.

[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.

27
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 3.2. Consumption of Fossil Fuels for Useful Thermal Output by Type of Combined Heat and Power Producers, 1999 through 2010

Coal Petroleum Natural Gas Other Gases

(Thousand Tons)[1] (Thousand Barrels)[2] (Thousand Mcf) (Billion Btu)[3]

Total Combined Heat and Power

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 13,161 816,787 175,671

2010 21,727 10,161 821,775 172,081

Electric Power[4]

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

2010 3,808 1,578 301,769 32,609

Commercial

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 --

2010 1,406 265 46,324 16

Industrial

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 10,900 469,970 141,859

2010 16,513 8,318 473,683 139,456

[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.

Type of Power Producer and Year

[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.

28
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 3.3. Consumption of Fossil Fuels for Electricity Generation and for Useful Thermal Output, 1999 through 2010

Coal Petroleum Natural Gas Other Gases

(Thousand Tons)[1] (Thousand 

Barrels)[2] (Thousand Mcf) (Billion Btu)[3]

Total (All Sectors)

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 7,937,856 259,265

2010 1,001,411 75,231 8,501,960 262,138

Electricity Generators, Electric Utilities

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

2010 721,431 47,431 3,290,993 771

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 2,839,310 16

2010 233,082 12,471 2,948,473 241

Combined Heat and Power, Electric Power[4]

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

2010 20,539 4,153 1,147,719 51,188

Period

29
Combined Heat and Power, Commercial[5]

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 --

2010 1,720 437 85,786 28

Combined Heat and Power, Industrial[5]

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

2010 24,638 10,740 1,028,990 209,910

[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.

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.

[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.

30
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 3.4. End-of-Year Stocks of Coal and Petroleum by Type of Producer, 1999 through 2010

Coal Petroleum Coal Petroleum Coal 

(Thousand Tons)[1] (Thousand Barrels)[2] (Thousand Tons)[1] (Thousand Barrels)[2] (Thousand Ton

1999 141,604 54,109 129,041 46,169 

2000 102,296 40,932 90,115 30,502 

2001 138,496 57,031 117,147 37,308 2002 141,714 52,490 116,952 31,243 2003 121,567 53,170 97,831 29,953 2004 106,669 51,434 84,917 32,281 

2005 101,137 50,062 77,457 31,400 

2006 140,964 51,583 110,277 32,082 

2007 151,221 47,203 120,504 29,297 

2008 161,589 44,498 127,463 28,450 

2009 189,467 46,181 154,815 31,778 2010 174,917 40,800 143,744 29,050 

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

"Power Plant Report;" and Form EIA-920, "Combined Heat and Power Plant Report;" Form EIA-860, "Annual Electric Generator Report.[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, petroleu NA = Not available. 

Note: Totals may not equal sum of components because of independent rounding.

Period

Electric Power Sector Electric Utilities Independ

31
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 3.5. Receipts, Average Cost, and Quality of Fossil Fuels for the Electric Power Industry, 1999 through 2010

Average

Cost

1999 908,232 1.01 122 24.72 145,939 1.51 236 14.81 2,809,455 257 2000 790,274 0.93 120 24.28 108,272 1.33 418 26.30 2,629,986 430 2001 762,815 0.89 123 24.68 124,618 1.42 369 23.20 2,148,924 449 2002 5 884,287 0.94 125 25.52 120,851 1.64 334 20.77 5,607,737 356 

2003 986,026 0.97 128 26.00 185,567 1.53 433 26.78 5,500,704 539 2004 1,002,032 0.97 136 27.42 186,655 1.66 429 26.56 5,734,054 596 2005 1,021,437 0.98 154 31.20 194,733 1.61 644 39.65 6,181,717 821 2006 1,079,943 0.97 169 34.09 100,965 2.31 623 37.66 6,675,246 694 2007 1,054,664 0.96 177 35.48 88,347 2.10 717 43.50 7,200,316 711 2008 1,069,709 0.97 207 41.14 96,341 2.21 1,087 64.89 7,879,046 902 2009 981,477 1.01 221 43.74 88,951 2.14 702 41.64 8,118,550 474 

2010 979,918 1.04 227 44.64 75,285 2.20 954 56.35 8,673,070 509 

Receipts 

(thousand 

barrels)

Avg. Sulfur 

Percent by 

Weight 4

Average Cost Average Cost

(dollars/ton) (cents per MMBtu) (dollars/ barrel) (cents per MMBtu)

Period

Coal 1 Petroleum 2 Natural Gas 3

Receipts 

(thousand tons)

Avg. Sulfur 

Percent by 

Weight

 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, fuel receipts

quality data are imputed for plants between 1 and 50 MW and are included in the data collected from plants at or above the 50 MW threshold. Therefore, there may be a notafuel receipts beginning with 2008 data.

Sources: U.S. Energy Information Administration (EIA), Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including Form EIA-423, "Monthly Co

of Fuels for Electric Plants Report" and Federal Energy Regulatory Commission (FERC), FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants1 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 (convpetroleum, 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.

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 b

higher beginning in 2006 as a result of the greater influence by petroleum coke receipts, which have a 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 20

were not collected; the data for 2001 and previous years include only data collected from electric utilities via the historical FERC Form 423.

Receipts 

(thousand Mcf) (cents per 

MMBtu)

32
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 3.6. Receipts and Quality of Coal Delivered for the Electric Power Industry, 1999 through 2010

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

Recei

(thous

ton

1999 137 0.64 37.8 444,399 1.57 10.2 386,271 0.38 6.6 

2000 11 0.64 37.2 375,673 1.45 10.1 341,242 0.35 6.3 2001 1 -- -- -- 348,703 1.42 10.4 349,340 0.35 6.1 

2002 2 -- -- -- 412,589 1.47 10.1 391,785 0.36 6.2 

2003 -- -- -- 436,809 1.49 9.9 432,513 0.38 6.4 

2004 -- -- -- 441,186 1.50 10.3 445,603 0.36 6.0 

2005 -- -- -- 451,680 1.55 10.5 456,856 0.36 6.2 

2006 -- -- -- 462,992 1.57 10.5 504,947 0.35 6.1 

2007 -- -- -- 439,154 1.61 10.3 505,155 0.34 6.0 

2008 -- -- -- 463,943 1.68 10.6 522,228 0.34 5.8 

2009 -- -- -- 418,688 1.77 10.5 484,007 0.34 5.8 

2010 -- -- -- 403,619 1.90 10.5 491,425 0.33 5.8 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 tablecollected; 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, fuel receipts, cost, and quality 

between 1 and 50 MW and are included in the data collected from plants at or above the 50 MW threshold. Therefore, there may be a notable increase in fuel rec

Sources: U.S. Energy Information Administration (EIA), Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including Form EIA-423, "

for Electric Plants Report" and Federal Energy Regulatory Commission (FERC), FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Pla

Period

Anthracite Bituminous Subbituminous 

1 Beginning in 2001, anthracite coal receipts were no longer reported separately. From 2001 forward, all anthracite coal receipts have been combined with bitum

33
Electric Power Annual 2010

Released: November 2011Next Update: November 2012

Table 3.7. Average Quality of Fossil Fuel Receipts for the Electric Power Industry, 1999 through 20101999 10,163 1.01 9.0 149,407 12000 10,115 0.93 8.8 149,857 12001 10,200 0.89 8.8 147,857 1

2002 4 10,168 0.94 8.7 147,902 1

2003 10,137 0.97 9.0 147,086 1

2004 10,074 0.97 9.0 147,286 12005 10,107 0.98 9.0 146,481 12006 10,063 0.97 9.0 143,883 22007 10,028 0.96 8.8 144,545 22008 9,947 0.97 9.0 142,205 22009 9,902 1.01 8.9 141,321 2

2010 9,842 1.04 8.9 140,598 2

Average Btu per Pound Average Sulfur Percent by Weight Average Ash Percent by Weight Average Btu per Gallon Average Sulfur Percen

by Weight

 Sources: U.S. Energy Information Administration (EIA), Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including Form EIA-Quality of Fuels for Electric Plants Report" and Federal Energy Regulatory Commission (FERC), FERC Form 423, "Monthly Report of Cost and Quality o

 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, pet

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 inclu

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 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. Beginning in 2008 with the Form EIA-923, fuel receipts, cost, and qua

between 1 and 50 MW and are included in the data collected from plants at or above the 50 MW theshold. Therefore, there may be a notable increase in fu

data.

Year

Coal 1 Petroleum 2

34
Electric Power Annual 2010

Released: November 2011Next Update: November 2012

Table 3.8. Weighted Average Cost of Fossil Fuels for the Electric Power Industry, 1999 through 2010

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)

A

Co

M

1999 10,722 131 6,740 110 996 93 18,461 122 916 236 2,862 

2000 9,050 130 5,991 108 947 94 15,988 120 681 418 2,682 

2001 8,312 139 6,134 104 839 109 15,286 123 783 369 2,209 

2002 9,932 142 6,878 105 851 104 17,982 125 751 334 5,750 

2003 10,543 144 7,598 110 1,026 103 19,990 128 1,146 433 5,663 

2004 10,538 156 7,817 112 1,012 106 20,189 136 1,155 429 5,891 

2005 10,833 184 8,004 119 1,008 107 20,647 154 1,198 644 6,357 

2006 11,129 204 8,842 131 982 115 21,735 169 610 623 6,856 

2007 10,580 208 8,826 145 925 128 21,152 177 536 717 7,396 

2008 11,110 250 9,087 162 896 141 21,280 207 575 1,087 8,089 

2009 10,010 275 8,421 164 835 158 19,438 221 528 702 8,319 

2010 9,652 281 8,545 173 925 162 19,290 227 445 954 8,867 

All Coal Ranks

 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 

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 (EIA), Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including Form EIA-423, "Monthly Cost 

Plants Report" and Federal Energy Regulatory Commission (FERC), FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."

Year

Coal

Petroleum Natural G

Bituminous Subbituminous Lignite

35
Electric Power Annual 2010

Released: November 2011Revised: March 2012Next Update: November 2012

Table 3.9. Emissions from Energy Consumption at Conventional Power Plants and Combined-Heat-and-Power Plants, 1999 through 2010

(Thousand Metric Tons)Emission 2010 2009 2008 2007 2006 2005 2004 2003 2002 Carbon Dioxide (CO2) 2,388,596 2,269,508 2,484,012 2,547,032 2,488,918 2,543,838 2,486,982 2,445,094 2,423,963 2Sulfur Dioxide (SO2) 5,401 5,970 7,830 9,042 9,524 10,340 10,309 10,646 10,881 

Nitrogen Oxides (NOx) 2,491 2,395 3,330 3,650 3,799 3,961 4,143 4,532 5,194 

Source: Calculations made by the Office of Electricity, Renewables, and Uranium Statistics, U.S. Energy Information Administration.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 develop the emissions estimates. • CO2 emissions for the historical years 1998-2008 have been revised due to changes in emission factors. Total year 2000 sulfur dioxide emissions were revismetric tons to 11,904 thousand metric tons in March 2012.
Electric Power Annual 2010

Released: November 2011

Revised: December 2011

Next Update: November 2012

Table 3.10. Number and Capacity of Existing Fossil-Fuel Steam-Electric Generators with Environmental Equipment, 1991 through 2010

Number of 

Generators

Capacity[2]

(megawatts)

Number of 

Generators

Capacity[2]

(megawatts)

Number of 

Generators

Capacity[2]

(megawatts)

Number of 

Generators

Capacity

(megawatts)

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

2007 278 119,024 1,188 354,407 771 228,704 1,547 421,120

2008 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

2010[R] 432 188,327 1,183 363,116 825 242,998 1,579 435,915

[2] Nameplate capacity.

[R] Revised.

NA = Not available. Form EIA-767 data collection was suspended in the data year 2006.

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."

Year

Flue Gas Desulfurization 

(Scrubbers) Particulate Collectors Cooling Towers Total[1]

[1] Components are not additive since some generators are included in more than one category.

37
Electric Power Annual 2010

Released: November 2011

Revised: December 2011

Next Update: November 2012

Table 3.11. Average Costs of Existing Flue Gas Desulfurization Units, 1999 through 2010

Year Average Operation & Maintenance Costs

(mills per kilowatthour)[1]

Average Installed Capital Costs

(dollar per kilowatt)

1999 1.13 125

2000 0.96 124

2001 1.27 130.8

2002 1.11 124.18

2003 1.23 123.75

2004 1.38 144.64

2005 1.23 141.34

2006 NA NA

2007 1.51 135.29

2008 1.55 150.74

2009 1.61 186.73

2010[R] 1.61 206.27

[1] A mill is one tenth of one cent.

[R] Revised.

NA = Not available. Form EIA-767 data collection was suspended in the data year 2006.

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 EIA923, "Power Plant Operations Report" for Average Operation & Maintenance Costs.

38
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.1.A. Noncoincident Peak Load by North American Electric Reliability Corporation Assessment Area, 1999-2010 Actual

(Megawatts)

Interconnection NERC Regional Assesment 

Area

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

FRCC 37,493 37,194 39,062 40,696 40,475 42,383 46,396 45,751 46,676 44,836 46,550 45,722

NPCC 52,855 50,057 55,949 56,012 55,018 52,549 58,960 63,241 58,314 58,543 55,944 60,554

Balance of Eastern Region 422,616 418,954 428,481 442,535 431,349 427,860 462,550 476,048 475,660 452,087 431,701 466,543

ECAR 99,239 92,033 100,235 102,996 98,487 95,300 NA NA NA NA NA NA

MAAC 51,645 49,477 54,015 55,569 53,566 52,049 NA NA NA NA NA NA

MAIN 51,535 52,552 56,344 56,396 56,988 53,439 NA NA NA NA NA NA

MAPP NA NA NA NA NA NA NA NA NA NA NA 4,598

MISO NA NA NA NA NA NA NA NA NA NA NA 108,346

MRO 31,903 28,605 28,321 29,119 28,831 29,351 39,918 42,194 41,684 39,677 37,963 NA

PJM NA NA NA NA NA NA NA NA NA NA NA 136,465

RFC NA NA NA NA NA NA 190,200 191,920 181,700 169,155 161,241 NA

SERC 149,685 156,088 149,293 158,767 153,110 157,615 190,705 199,052 209,109 199,779 191,032 164,058

SPP 38,609 40,199 40,273 39,688 40,367 40,106 41,727 42,882 43,167 43,476 41,465 53,077

ERCOT TRE 55,529 57,606 55,201 56,248 59,996 58,531 60,210 62,339 62,188 62,174 63,518 65,776

Western Interconnection WECC 113,629 114,602 109,119 119,074 122,537 123,136 130,760 142,096 139,389 134,829 128,245 129,352

All Interconnections Contiguous U.S. 682,122 678,413 687,812 714,565 709,375 704,459 758,876 789,475 782,227 752,470 725,958 767,948

Interconnection NERC Regional Assesment 

Area

1999/2000 2000/2001 2001/2002 2002/2003 2003/2004 2004/2005 2005/2006 2006/2007 2007/2008 2008/2009 2009/2010 2010/2011

FRCC 40,178 38,606 40,922 45,635 36,841 44,839 42,657 42,526 41,701 45,275 53,022 46,135

NPCC 45,227 43,852 42,670 46,009 48,079 48,176 46,828 46,697 46,795 46,043 44,864 45,712

Balance of Eastern Region 347,266 364,003 352,083 371,977 364,232 378,987 381,246 390,263 386,301 390,829 405,176 400,589

ECAR 86,239 84,546 85,485 87,300 86,332 91,800 NA NA NA NA NA NA

MAAC 40,220 43,256 39,458 46,551 45,625 45,905 NA NA NA NA NA NA

MAIN 39,081 41,943 40,529 42,412 41,719 42,929 NA NA NA NA NA NA

MAPP NA NA NA NA NA NA NA NA NA NA NA 5,069

MISO NA NA NA NA NA NA NA NA NA NA NA 86,728

MRO 25,200 24,536 21,815 23,645 24,134 24,526 33,748 34,677 33,191 36,029 35,351 NA

PJM NA NA NA NA NA NA NA NA NA NA NA 115,535

RFC NA NA NA NA NA NA 151,600 149,631 141,900 142,395 143,827 NA

SERC 128,563 139,146 135,182 141,882 137,972 144,337 164,638 175,163 179,888 179,596 193,135 152,030

SPP 27,963 30,576 29,614 30,187 28,450 29,490 31,260 30,792 31,322 32,809 32,863 41,226

ERCOT TRE 39,164 44,641 44,015 45,414 42,702 44,010 48,141 50,402 50,408 47,806 56,191 57,315

Western Interconnection WECC 99,080 97,324 96,622 95,951 102,020 102,689 107,493 111,093 112,700 113,605 109,565 101,668

All Grids Contiguous U.S. 570,915 588,426 576,312 604,986 593,874 618,701 626,365 640,981 637,905 643,557 668,818 651,418

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Peak load represents an hour of a day during the associated peak period. 

• The Summer peak period begins on June1 and extends through September 30. 

• The Winter peak period begins October 1 and extends through May 31.

• Historically the MRO, RFC, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical data

series for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to provide a consistent

trend of the Eastern interconnection.

 • ECAR, MAAC, and MAIN dissolved at the end-of-2005. Many of the former utility members joined RFC. ReliabilityFirst Corporation (RFC)

came into existence on January 1, 2006. RFC submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN.

• NA - Not Available

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply and Demand Program Report."

Summer

Winter

Eastern Interconnection

Eastern Interconnection

39
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.1.B. Noncoincident Peak Load by North American Electric Reliability Corporation Assessment Area, 2010 Actual, 2011-2015 Projected

(Megawatts)

Interconnection NERC Regional Assesment Area

Actual

2010 2011E 2012E 2013E 2014E 2015E

FRCC 45,722 46,091 46,658 47,446 48,228 49,278

NPCC 60,554 60,262 61,277 61,958 62,579 63,058

Balance of Eastern Region 466,543 469,412 477,274 487,587 493,523 498,194

MAPP 4,598 4,810 5,036 5,331 5,401 5,497

MISO 108,346 98,068 92,976 94,834 95,227 95,947

PJM 136,465 148,941 158,603 162,489 164,772 166,506

SERC 164,058 164,510 167,027 169,783 172,637 174,688

SPP 53,077 53,084 53,632 55,149 55,485 55,556

ERCOT TRE 65,776 63,770 65,406 67,362 70,004 71,910

Western Interconnection WECC 129,352 130,962 132,422 134,252 136,138 138,497

All Grids Contiguous U.S. 767,948 770,497 783,037 798,605 810,472 820,937

Interconnection NERC Regional Assesment Area

Actual

2010/2011 2011/2012E 2012/2013E 2013/2014E 2014/2015E 2015/2016E

FRCC 46,135 47,613 48,276 48,889 49,534 50,148

NPCC 45,712 46,788 47,058 47,271 47,440 47,578

Balance of Eastern Region 400,589 410,168 411,679 418,406 420,899 425,399

MAPP 5,069 5,118 5,066 5,316 5,368 5,459

MISO 86,728 79,052 75,208 77,410 77,725 78,574

PJM 115,535 130,711 133,594 135,529 136,948 137,985

SERC 152,030 154,150 156,118 157,978 158,766 160,721

SPP 41,226 41,138 41,693 42,173 42,092 42,660

ERCOT TRE 57,315 51,642 51,343 53,472 55,126 56,398

Western Interconnection WECC 101,668 106,717 108,157 110,259 112,231 113,971

All Interconnections Contiguous U.S. 651,418 662,928 666,513 678,297 685,230 693,494

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Projected data are updated annually.

• Peak load represents an hour of a day during the associated peak period. 

• The Summer peak period begins on June1 and extends through September 30. 

• The Winter peak period begins October 1 and extends through May 31.

• Historically the MRO, RFC, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical data

series for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to provide a consistent

trend of the Eastern interconnection.

 • ECAR, MAAC, and MAIN dissolved at the end-of-2005. Many of the former utility members joined RFC. ReliabilityFirst Corporation (RFC)

came into existence on January 1, 2006. RFC submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN.

• E - Estimate; NA - Not Available

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply and Demand Program Report."

Eastern Interconnection

Projected

Winter

Summer

Projected

Eastern Interconnection

40
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 4.2.A. Net Energy for Load by North American Electric Reliability Corporation Assessment Area, 1999-2010 Actual(Thousands of Megawatthours)

Interconnection NERC Regional Assesment Area

1999 2000 2001 2002 2003 2004 2005 2006 2007 

FRCC 188,598 196,561 200,134 211,116 219,021 220,335 226,544 230,115 232,405 

NPCC 277,902 281,518 282,670 286,199 288,791 292,725 303,607 294,319 301,766 

Balance of Eastern

Region 2,147,860 2,210,739 2,203,509 2,301,321 2,255,233 2,313,180 2,385,461 2,361,721 2,432,475 

ECAR 547,846 545,958 546,167 567,897 545,109 553,236 NA NA NA 

MAAC 255,741 262,320 263,841 273,907 276,600 283,646 NA NA NA 

MAIN 243,278 259,608 271,053 279,264 267,068 274,760 NA NA NA 

MAPP NA NA NA NA NA NA NA NA NA 

MISO NA NA NA NA NA NA NA NA NA 

MRO 152,350 145,981 144,893 150,058 153,918 152,975 216,633 222,748 217,602 

PJM NA NA NA NA NA NA NA NA NA 

RFC NA NA NA NA NA NA 1,005,226 926,279 954,700 

SERC 768,408 803,211 787,139 835,319 826,964 856,734 962,054 1,011,173 1,049,298 

SPP 180,237 193,661 190,416 194,876 185,574 191,829 201,548 201,521 210,875 

ERCOT TRE 268,622 286,313 278,226 280,269 283,868 289,146 299,225 305,672 307,064 

Western Interconnection WECC 635,503 663,913 638,746 666,696 664,754 682,053 685,624 720,087 739,018 

All Interconnections Contiguous U.S. 3,518,485 3,639,044 3,603,285 3,745,601 3,711,667 3,797,439 3,900,461 3,911,914 4,012,728 

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Peak load represents an hour of a day during the associated peak period. • Net Energy for Load represents net Balancing Authority Area generation, plus energy received from other Balancing Authority Areas, less energy delivered to other Balancing Authority Areas through interchange.• Historically the MRO, RFC, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical dataseries for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to provide a consistenttrend of the Eastern interconnection. • ECAR, MAAC, and MAIN dissolved at the end-of-2005. Many of the former utility members joined RFC. ReliabilityFirst Corporation (RFC)came into existence on January 1, 2006. RFC submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN.• NA - Not AvailableSource: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply and Demand Program Report."

Eastern Interconnection

41
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.2.B. Net Energy for Load by North American Electric Reliability CorporationAssessment Area, 2010 Actual, 2011-2015 Projected

(Thousands of Megawatthours)

Actual

2010 2011E 2012E 2013E 2014E 2015E

FRCC 233,034 225,325 229,230 234,208 238,618 242,420

NPCC 294,276 297,702 302,476 303,826 305,678 307,140

Balance of Eastern Region 2,456,553 2,377,560 2,451,847 2,514,769 2,548,867 2,571,918

MAPP 30,691 33,507 34,448 35,679 36,226 36,652

MISO 585,274 497,080 466,383 476,183 480,432 486,274

PJM 712,731 762,050 842,634 860,521 874,144 883,516

SERC 870,367 825,261 842,397 872,236 885,180 892,373

SPP 257,491 259,661 265,985 270,150 272,885 273,103

ERCOT TRE 319,097 319,403 330,034 339,616 352,294 362,841

Western Interconnection WECC 713,177 732,710 742,148 752,650 763,397 773,510

All Interconnections Contiguous U.S. 4,016,137 3,952,699 4,055,735 4,145,069 4,208,854 4,257,828

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Projected data are updated annually.

• Peak load represents an hour of a day during the associated peak period. 

• Net Energy for Load represents net Balancing Authority Area generation, plus energy received from other Balancing Authority Areas, 

less energy delivered to other Balancing Authority Areas through interchange.

• Historically the MRO, RFC, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical data

series for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to provide a consistent

trend of the Eastern interconnection.

• E - Estimate; NA - Not Available

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply and Demand Program Report."

Projected

Eastern Interconnection

Interconnection NERC Regional Assesment 

Area

42
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.3.A. Summer Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Assessment Area, 1999-2010 Actual

(Megawatts and Percent)

Interconnection NERC Regional Assesment 

Area

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

FRCC 34,832 35,666 38,932 37,951 40,387 42,243 45,950 45,345 46,434 44,660 46,263 45,522

NPCC 53,450 54,270 55,888 55,164 53,936 51,580 57,402 60,879 58,221 59,896 55,730 56,232

Balance of Eastern Region 401,701 420,443 417,613 430,396 422,253 419,349 455,594 469,639 465,229 447,629 424,714 454,759

ECAR 94,072 98,651 100,235 101,251 98,487 95,300 NA NA NA NA NA NA

MAAC 49,325 51,358 54,015 54,296 53,566 52,049 NA NA NA NA NA NA

MAIN 47,165 51,845 53,032 53,267 53,617 50,499 NA NA NA NA NA NA

MAPP NA NA NA NA NA NA NA NA NA NA NA 4,493

MISO NA NA NA NA NA NA NA NA NA NA NA 100,963

MRO 30,606 28,006 27,125 28,825 28,775 29,094 38,266 40,661 40,249 38,857 35,849 NA

PJM NA NA NA NA NA NA NA NA NA NA NA 136,465

RFC NA NA NA NA NA NA 190,200 190,800 177,200 169,155 161,241 NA

SERC 142,726 151,527 144,399 154,459 148,380 153,024 186,049 196,196 205,321 196,711 186,507 160,896

SPP 37,807 39,056 38,807 38,298 39,428 39,383 41,079 41,982 42,459 42,906 41,117 51,942

ERCOT TRE 51,697 53,649 55,106 55,833 59,282 58,531 59,060 61,214 61,063 61,049 63,518 64,378

Western Interconnection WECC 112,177 116,913 107,294 117,032 120,894 121,205 128,464 139,402 135,839 130,916 122,881 126,944

All Interconnections Contiguous U.S. 653,857 680,941 674,833 696,376 696,752 692,908 746,470 776,479 766,786 744,151 713,106 747,836 

Interconnection NERC Regional Assesment 

Area

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

FRCC 40,645 43,083 42,290 43,342 46,806 48,579 50,200 50,909 53,027 51,541 49,239 53,370

NPCC 63,077 63,376 63,760 66,208 70,902 71,532 72,258 73,095 73,771 75,894 78,639 67,569

Balance of Eastern Region 460,325 490,333 487,950 504,357 513,382 526,454 532,917 534,270 543,608 539,936 559,823 571,719

ECAR 107,451 115,379 113,136 119,736 123,755 127,919 NA NA NA NA NA NA

MAAC 57,831 60,679 59,533 63,619 65,897 66,167 NA NA NA NA NA NA

MAIN 55,984 64,170 65,950 67,025 67,410 65,677 NA NA NA NA NA NA

MAPP NA NA NA NA NA NA NA NA NA NA NA 7,210

MISO NA NA NA NA NA NA NA NA NA NA NA 131,691

MRO 35,373 34,236 32,271 34,259 33,287 35,830 46,792 50,116 47,259 48,180 47,529 NA

PJM NA NA NA NA NA NA NA NA NA NA NA 168,970

RFC NA NA NA NA NA NA 220,000 214,693 213,544 215,477 215,700 NA

SERC 160,575 169,760 171,530 172,485 177,231 182,861 219,749 223,630 234,232 228,169 247,400 200,511

SPP 43,111 46,109 45,530 47,233 45,802 48,000 46,376 45,831 48,573 48,110 49,194 63,337

ERCOT TRE 65,423 69,622 70,797 76,849 74,764 73,850 66,724 70,664 75,912 74,274 76,280 73,857

Western Interconnection WECC 136,274 141,640 124,193 142,624 150,277 155,455 160,026 162,288 168,080 167,860 152,467 158,407

All Interconnections Contiguous U.S. 765,744 808,054 788,990 833,380 856,131 875,870 882,125 891,226 914,397 909,504 916,449 924,922 

Interconnection NERC Regional Assesment 

Area

1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

FRCC 14.3 17.2 7.9 12.4 13.7 13.0 8.5 10.9 12.4 13.4 6.0 14.7 

NPCC 15.3 14.4 12.3 16.7 23.9 27.9 20.6 16.7 21.1 21.1 29.1 16.8

Balance of Eastern Region 12.7 14.3 14.4 14.7 17.8 20.3 14.5 12.1 14.4 17.1 24.1 20.5 

ECAR 12.5 14.5 11.4 15.4 20.4 25.5 NA NA NA NA NA NA 

MAAC 14.7 15.4 9.3 14.7 18.7 21.3 NA NA NA NA NA NA 

MAIN 15.8 19.2 19.6 20.5 20.5 23.1 NA NA NA NA NA NA 

MAPP NA NA NA NA NA NA NA NA NA NA NA 37.7 

MISO NA NA NA NA NA NA NA NA NA NA NA 23.3 

MRO 13.5 18.2 15.9 15.9 13.6 18.8 18.2 18.9 14.8 19.3 24.6 NA 

PJM NA NA NA NA NA NA NA NA NA NA NA 19.2 

RFC NA NA NA NA NA NA 13.5 11.1 17.0 21.5 25.2 NA 

SERC 11.1 10.7 15.8 10.5 16.3 16.3 15.3 12.3 12.3 13.8 24.6 19.8

SPP 12.3 15.3 14.8 18.9 13.9 18.0 11.4 8.4 12.6 10.8 16.4 18.0

ERCOT TRE 21.0 22.9 22.2 27.3 20.7 20.7 11.5 13.4 19.6 17.8 16.7 12.8 

Western Interconnection WECC 17.7 17.5 13.6 17.9 19.6 22.0 19.7 14.1 19.2 22.0 19.4 19.9 

All Interconnections Contiguous U.S. 14.6 15.7 14.5 16.4 18.6 20.9 15.4 12.9 16.1 18.2 22.2 19.1 

[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 nonutility-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.

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Peak load represents an hour of a day during the associated peak period. 

• The Summer peak period begins on June1 and extends through September 30. 

• Historically the MRO, RFC, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical data

series for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to provide a consistent

trend of the Eastern interconnection.

 • ECAR, MAAC, and MAIN dissolved at the end-of-2005. Many of the former utility members joined RFC. ReliabilityFirst Corporation (RFC)

came into existence on January 1, 2006. RFC submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN.

• NA - Not Available

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply and Demand Program Report."

Eastern Interconnection

Net Internal Demand (MW)[1] -- Summer

Capacity Resources (MW)[2] -- Summer

Capacity Margin (percent)[3] -- Summer

Eastern Interconnection

Eastern Interconnection

43
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.3.B. Summer Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Corporation Assessment Area, 2010 Actual, 2011-2015 Projected

(Megawatts)

Interconnection NERC Regional Assesment Area

Actual

2010 2011E 2012E 2013E 2014E 2015E

FRCC 45,522 42,945 43,389 44,056 44,787 45,770

NPCC 56,232 56,174 56,618 56,902 57,127 57,606

Balance of Eastern Region 454,759 442,400 454,051 461,791 467,431 471,764

MAPP 4,493 4,704 4,926 5,216 5,285 5,379

MISO 100,963 90,249 85,157 87,015 87,408 88,128

PJM 136,465 137,341 151,780 153,510 155,793 157,527

SERC 160,896 158,323 159,852 162,247 164,805 166,467

SPP 51,942 51,783 52,337 53,802 54,140 54,263

ERCOT TRE 64,378 62,286 63,880 65,790 68,381 70,231

Western Interconnection WECC 126,944 126,586 127,446 128,925 130,801 133,139

All Grids Contiguous U.S. 747,836 730,391 745,384 757,464 768,528 778,510 

Interconnection NERC Regional Assesment Area

Actual

2010 2011E 2012E 2013E 2014E 2015E

FRCC 53,370 53,538 54,695 54,815 56,242 57,253

NPCC 67,569 71,943 72,333 74,119 74,761 74,254

Balance of Eastern Region 571,719 569,691 575,220 579,720 581,186 578,986

MAPP 7,210 6,563 6,516 6,326 6,321 6,371

MISO 131,691 111,945 106,631 106,690 106,709 106,732

PJM 168,970 181,740 189,601 191,265 191,425 192,011

SERC 200,511 203,220 205,834 207,560 208,362 205,988

SPP 63,337 66,224 66,638 67,879 68,369 67,884

ERCOT TRE 73,857 73,199 74,902 75,063 77,223 78,003

Western Interconnection WECC 158,407 171,032 180,001 186,410 188,386 191,799

All Grids Contiguous U.S. 924,922 939,403 957,151 970,127 977,798 980,295 

Interconnection NERC Regional Assesment Area

Actual

2010 2011E 2012E 2013E 2014E 2015E

FRCC 14.7 19.8 20.7 19.6 20.4 20.1

NPCC 16.8 21.9 21.7 23.2 23.6 22.4

Balance of Eastern Region 20.5 22.3 21.1 20.3 19.6 18.5

MAPP 37.7 28.3 24.4 17.5 16.4 15.6

MISO 23.3 19.4 20.1 18.4 18.1 17.4

PJM 19.2 24.4 19.9 19.7 18.6 18.0

SERC 19.8 22.1 22.3 21.8 20.9 19.2

SPP 18.0 21.8 21.5 20.7 20.8 20.1

ERCOT TRE 12.8 14.9 14.7 12.4 11.4 10.0

Western Interconnection WECC 19.9 26.0 29.2 30.8 30.6 30.6

All Grids Contiguous U.S. 19.1 22.2 22.1 21.9 21.4 20.6

[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 nonutility-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.

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Projected data are updated annually.

• Peak load represents an hour of a day during the associated peak period. 

• The Winter peak period begins October 1 and extends through May 31.

• Historically the MRO, RFC, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical data

series for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to provide a consistent

trend of the Eastern interconnection.

• E - Estimate

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply and Demand Program Report."

Eastern Interconnection

Capacity Resources (MW)[2] -- Summer

Capacity Margin (percent)[3] -- Summer

Projected

Net Internal Demand (MW)[1] -- Summer

Projected

Projected

Eastern Interconnection

Eastern Interconnection

44
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.4.A. Winter Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Assessment Areas, 2001-2010 Actual

(Megawatts and Percent)

Interconnection NERC Regional Assesment 

Area

2001/2002 2002/2003 2003/2004 2004/2005 2005/2006 2006/2007 2007/2008 2008/2009 2009/2010 2010/ 2011

FRCC 39,699 42,001 36,229 41,449 42,493 45,993 46,093 45,042 51,703 45,954

NPCC 42,551 45,980 47,850 47,859 46,328 48,394 46,185 47,151 44,864 44,172

Balance of Eastern Region 341,158 360,748 357,026 371,011 375,365 385,887 383,779 384,495 399,204 389,351

ECAR 82,831 84,844 86,332 91,800 NA NA NA NA NA NA

MAAC 39,458 46,159 45,625 45,565 NA NA NA NA NA NA

MAIN 38,412 39,974 39,955 40,618 NA NA NA NA NA NA

MAPP MRO MRO MRO NA NA NA NA NA NA 4,877

MISO NA NA NA NA NA NA NA NA NA 80,311

MRO 21,575 23,090 24,042 24,446 32,854 34,582 34,358 34,539 33,983 NA

PJM NA NA NA NA NA NA NA NA NA 115,535

RFC NA NA NA NA 151,600 147,800 141,200 142,395 143,827 NA

SERC 130,311 137,541 133,244 139,486 160,054 173,036 176,766 175,199 188,653 148,062

SPP 28,571 29,140 27,828 29,096 30,857 30,469 31,455 32,362 32,741 40,566

ERCOT TRE 43,908 44,719 41,988 44,010 46,991 46,038 46,068 46,747 56,191 55,917

Western Interconnection WECC 95,395 94,554 100,337 101,002 105,670 107,586 113,504 110,977 106,256 99,515

All Interconnections Contiguous U.S. 562,711 588,002 583,430 605,331 616,847 633,898 635,629 634,412 658,219 634,909

Interconnection NERC Regional Assesment 

Area

2001/2002 2002/2003 2003/2004 2004/2005 2005/2006 2006/2007 2007/2008 2008/2009 2009/2010 2010/ 2011

FRCC 44,336 46,219 50,010 51,196 49,066 56,896 57,510 53,278 52,751 57,358

NPCC 66,314 68,884 73,123 74,277 76,076 76,110 75,772 79,394 78,992 70,557

Balance of Eastern Region 488,418 511,642 524,995 538,041 545,850 547,005 537,094 545,843 567,746 595,627

ECAR 115,926 123,823 129,351 131,187 NA NA NA NA NA NA

MAAC 63,604 66,143 68,134 69,604 NA NA NA NA NA NA

MAIN 63,209 66,694 68,942 66,414 NA NA NA NA NA NA

MAPP NA NA NA NA NA NA NA NA NA 6,941

MISO NA NA NA NA NA NA NA NA NA 129,241

MRO 30,809 33,224 32,769 34,371 44,620 46,959 44,987 47,343 46,422 NA

PJM NA NA NA NA NA NA NA NA NA 190,000

RFC NA NA NA NA 229,000 220,930 212,257 215,477 215,700 NA

SERC 169,580 174,925 179,810 186,784 224,652 231,917 229,627 234,797 255,527 207,558

SPP 45,290 46,833 45,989 49,681 47,578 47,199 50,223 48,226 50,097 61,888

ERCOT TRE 72,644 73,335 77,111 71,902 61,003 71,451 75,504 73,910 69,490 77,660

Western Interconnection WECC 119,254 132,278 152,158 149,360 152,211 166,362 167,770 167,312 151,022 156,413

All Interconnections Contiguous U.S. 790,966 832,358 877,397 884,776 884,206 917,824 913,650 919,736 920,002 957,615

Interconnection NERC Regional Assesment 

Area

2001/2002 2002/2003 2003/2004 2004/2005 2005/2006 2006/2007 2007/2008 2008/2009 2009/2010 2010/ 2011

FRCC 10.5 9.1 27.6 19.0 13.4 19.2 19.9 15.5 2.0 19.9

NPCC 35.8 33.3 34.6 35.6 39.1 36.4 39.0 40.6 43.2 37.4 

Balance of Eastern Region 30.2 29.5 32.0 31.0 31.2 29.5 28.5 29.6 29.7 34.6 

ECAR 28.5 31.5 33.3 30.0 NA NA NA NA NA NA

MAAC 38.0 30.2 33.0 34.5 NA NA NA NA NA NA

MAIN 39.2 40.1 42.0 38.8 NA NA NA NA NA NA

MAPP NA NA NA NA NA NA NA NA NA 29.7 

MISO NA NA NA NA NA NA NA NA NA 37.9 

MRO 30.0 30.5 26.6 28.9 26.4 26.4 23.6 27.0 26.8 NA 

PJM NA NA NA NA NA NA NA NA NA 39.2 

RFC NA NA NA NA 33.8 33.1 33.5 33.9 33.3 NA 

SERC 23.2 21.4 25.9 25.3 28.8 25.4 23.0 25.4 26.2 28.7 

SPP 36.9 37.8 39.5 41.4 35.1 35.4 37.4 32.9 34.6 34.5 

ERCOT TRE 39.6 39.0 45.5 38.8 23.0 35.6 39.0 36.8 19.1 28.0

Western Interconnection WECC 20.0 28.5 34.1 32.4 30.6 35.3 32.3 33.7 29.6 36.4 

All Interconnections Contiguous U.S. 28.9 29.4 33.5 31.6 30.2 30.9 30.4 31.0 28.5 33.7 

[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 nonutility-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.

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Peak load represents an hour of a day during the associated peak period. 

• The Winter peak period begins October 1 and extends through May 31.

• Historically the MRO, RFC, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical data

series for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to provide a consistent

trend of the Eastern interconnection.

 • ECAR, MAAC, and MAIN dissolved at the end-of-2005. Many of the former utility members joined RFC. ReliabilityFirst Corporation (RFC)

came into existence on January 1, 2006. RFC submitted a consolidated filing covering the historical NERC regions of ECAR, MAAC, and MAIN.

• NA - Not Available

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply and Demand Program Report."

Eastern Interconnection

Capacity Margin (percent)[3] -- Winter

Net Internal Demand (MW)[1] -- Winter

Capacity Resources[2] -- Winter

Eastern Interconnection

Eastern Interconnection

45
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.4.B. Winter Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Corporation Assessment Area, 2010 Actual, 2011-2015 Projected

(Megawatts)

Interconnection NERC Regional Assesment Area

Actual

2010/2011 2011/2012E 2012/2013E 2013/2014E 2014/2015E 2015/2016E

FRCC 45,954 44,196 44,750 45,350 45,923 46,503

NPCC 44,172 44,924 44,637 44,422 44,216 44,354

Balance of Eastern Region 389,351 384,993 390,736 394,849 396,861 401,086

MAPP 4,877 4,746 4,686 4,929 4,977 5,062

MISO 80,311 71,233 67,389 69,591 69,906 70,755

PJM 115,535 119,806 127,464 127,243 128,662 129,699

SERC 148,062 148,990 150,504 151,921 152,244 153,879

SPP 40,566 40,218 40,693 41,165 41,073 41,691

ERCOT TRE 55,917 50,158 49,817 51,900 53,503 54,719

Western Interconnection WECC 99,515 104,740 105,879 107,570 109,542 111,261

All Grids Contiguous U.S. 634,909 629,011 635,819 644,091 650,044 657,923 

Interconnection NERC Regional Assesment Area

Actual

2010/2011 2011/2012E 2012/2013E 2013/2014E 2014/2015E 2015/2016E

FRCC 57,358 55,786 57,282 58,030 61,245 60,543

NPCC 70,557 74,946 75,937 77,155 77,850 77,706

Balance of Eastern Region 595,627 570,224 578,991 581,968 582,872 580,949

MAPP 6,941 7,078 7,038 7,118 7,118 7,088

MISO 129,241 107,051 101,737 101,796 101,815 101,838

PJM 190,000 182,643 189,777 191,426 192,016 192,022

SERC 207,558 208,978 214,974 215,492 215,346 213,657

SPP 61,888 64,474 65,466 66,137 66,577 66,345

ERCOT TRE 77,660 77,256 78,440 78,535 80,695 82,095

Western Interconnection WECC 156,413 161,583 168,816 172,598 175,807 176,112

All Grids Contiguous U.S. 957,615 939,795 959,466 968,287 978,469 977,406 

Interconnection NERC Regional Assesment Area

Actual

2010/2011 2011/2012E 2012/2013E 2013/2014E 2014/2015E 2015/2016E

FRCC 19.9 20.8 21.9 21.9 25.0 23.2

NPCC 37.4 40.1 41.2 42.4 43.2 42.9

Balance of Eastern Region 34.6 32.5 32.5 32.2 31.9 31.0

MAPP 29.7 32.9 33.4 30.7 30.1 28.6

MISO 37.9 33.5 33.8 31.6 31.3 30.5

PJM 39.2 34.4 32.8 33.5 33.0 32.5

SERC 28.7 28.7 30.0 29.5 29.3 28.0

SPP 34.5 37.6 37.8 37.8 38.3 37.2

ERCOT TRE 28.0 35.1 36.5 33.9 33.7 33.3

Western Interconnection WECC 36.4 35.2 37.3 37.7 37.7 36.8

All Grids Contiguous U.S. 33.7 33.1 33.7 33.5 33.6 32.7

[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 nonutility-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.

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Projected data are updated annually.

• Peak load represents an hour of a day during the associated peak period. 

• The Winter peak period begins October 1 and extends through May 31.

• Historically the MRO, RFC, SERC, and SPP regional boundaries were altered as utilities changed reliability organizations. The historical data

series for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to provide a consistent

trend of the Eastern interconnection.

• E - Estimate

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply and Demand Program Report."

Eastern Interconnection

Capacity Resources[2] -- Winter

Capacity Margin (percent)[3] -- Winter

Projected

Net Internal Demand[1] -- Winter

Projected

Projected

Eastern Interconnection

Eastern Interconnection

46
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.5.A. Existing Transmission Capacity by High-Voltage Size, 2010

(Circuit Miles of Transmission)

Type Operating 

(kV) FRCC MRO NPCC RFC SERC SPP TRE WECC ContigiousU.S.

AC 100-199 - - - - - - - - -

AC 200-299 5,922 7,241 1,521 6,949 21,100 2,776 - 36,810 82,319

AC 300-399 - 11,468 5,064 13,610 3,538 4,934 9,500 10,301 58,415

AC 400-599 1,201 473 - 2,551 8,617 47 - 12,729 25,618

AC 600+ - - 190 2,226 - - - - 2,416

AC Total 7,123 19,182 6,774 25,336 33,255 7,757 9,500 59,840 168,768 

DC 100-199 - - 48 - - - - - 48

DC 200-299 - 930 - - - - - - 930

DC 300-399 - - - - - - - - -

DC 400-499 - 872 - - - - - - 872

DC 500-599 - - - 66 - - - 2,137 2,203

DC 600+ - - - - - - - - -

DC Total - 1,802 48 66 - - - 2,137 4,053 

Grand Total 7,123 20,984 6,822 25,402 33,255 7,757 9,500 61,977 172,820 

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Circuit miles do not equal physical miles on the ground; the reference terminology for that concept is structural mile. 

• 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.

Voltage

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program Report."

Circuit Miles

47
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 4.5.B. Proposed Transmission Capacity Additions by High-Voltage Size, 2011-2017

(Circuit Miles of Transmission)

Type Operating

(kV) 2011 2012 2013 2014 2015 2016 2017 AllYears

AC 100-199 1,164 1,749 932 738 466 368 214 5,630 

AC 200-299 1,007 1,091 708 822 895 241 157 4,922 

AC 300-399 555 1,336 4,934 1,234 699 476 1,156 10,390

AC 400-599 116 695 633 782 2,802 1,438 440 6,906 

AC 600+ - - - - 275 - - 275 

AC Total 2,841 4,871 7,208 3,577 5,137 2,524 1,967 28,124

DC 100-199 - - - - - - - -

DC 200-299 - - - - - - - -

DC 300-399 - - - - 140 - - 140 

DC 400-599 - - - - 60 640 - 700 

DC 600+ - - - - 142 - - 142 

DC Total - - - - 342 640 - 982 

Grand Total 2,841 4,871 7,208 3,577 5,479 3,164 1,967 29,106

Lines taken out of service 99 180 21 121 33 134 - 587 

Notes: • NERC region and reliability assessment area maps are provided on EIA's Electricity Reliability web page: 

http://www.eia.gov/cneaf/electricity/page/eia411/eia411.html

• Circuit miles do not equal physical miles on the ground; the reference terminology for that concept is structural mile. 

• 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.

Voltage

Source: U.S. Energy Information Administration, Form EIA-411, "Coordinated Bulk Power Supply Program Report."

Circuit Miles

48
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 5.1. Count of Electric Power Industry Power Plants, by Sector, by Predominant Energy Sources within Plant, 2002 through 2010

(Count)

Period Coal Petroleum Natural Gas Other Gases Nuclear Hydroelectric 

Conventional

Other 

Renewables

Hydroelectric 

Pumped Storage Other

2002 633 1,147 1,649 40 66 1,426 682 38 28

2003 629 1,166 1,693 40 66 1,425 741 38 27

2004 625 1,143 1,670 46 66 1,425 749 39 28

2005 619 1,133 1,664 44 66 1,422 781 39 29

2006 616 1,148 1,659 46 66 1,421 843 39 29

2007 606 1,163 1,659 46 66 1,424 929 39 25

2008 598 1,170 1,655 43 66 1,423 1,076 39 29

2009 593 1,168 1,652 43 66 1,427 1,219 39 28

2010 580 1,169 1,657 48 66 1,432 1,356 39 32

2002 363 811 699 1 37 913 57 33 0

2003 359 827 715 1 37 912 64 33 1

2004 357 816 722 2 37 908 65 34 1

2005 353 813 743 1 37 906 71 34 1

2006 353 832 758 1 37 905 84 34 1

2007 351 851 767 1 37 904 93 34 1

2008 348 866 774 0 37 902 107 34 1

2009 346 861 776 0 37 903 132 34 1

2010 339 861 781 3 37 904 159 34 0

2002 106 180 326 1 29 455 430 5 4

2003 99 182 350 0 29 456 468 5 2

2004 100 173 355 1 29 457 478 5 2

2005 101 170 357 2 29 456 502 5 2

2006 101 166 356 2 29 458 552 5 2

2007 101 166 364 1 29 462 625 5 1

2008 99 166 365 0 29 464 751 5 2

2009 97 169 369 1 29 468 866 5 2

2010 99 171 374 1 29 472 964 5 6

2002 44 15 169 2 0 0 28 0 0

2003 49 17 187 3 0 0 34 0 0

2004 48 15 180 3 0 0 30 0 0

2005 48 14 177 3 0 0 33 0 0

2006 50 15 173 4 0 0 32 0 0

2007 48 12 170 4 0 0 32 0 0

2008 47 12 169 3 0 0 36 0 0

2009 49 10 165 3 0 0 39 0 0

2010 45 10 161 2 0 0 41 0 0

2002 22 63 122 0 0 9 41 0 0

2003 22 65 121 0 0 9 44 0 0

2004 21 65 121 1 0 9 46 0 0

2005 20 64 113 1 0 9 48 0 0

2006 22 62 109 1 0 9 47 0 0

2007 20 64 106 1 0 9 47 0 1

2008 20 62 106 1 0 9 49 0 1

2009 18 66 107 1 0 9 48 0 1

2010 17 67 110 1 0 9 57 0 1

2002 98 71 317 36 0 49 125 0 24

2003 100 71 310 36 0 48 130 0 24

2004 99 74 292 39 0 51 130 0 25

2005 97 72 274 37 0 51 127 0 26

2006 90 73 263 38 0 49 128 0 26

2007 86 70 252 39 0 49 132 0 22

2008 84 64 241 39 0 48 133 0 25

2009 83 62 235 38 0 47 134 0 24

2010 80 60 231 41 0 47 135 0 25

[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) above is the sum of the 

counts for each sector by energy source and does not necessarily represent unique site. In addition, changes to predominant energy sources and status codes from year to year may result in changes to 

previously-posted data.

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

Total (All Sectors)

Electricity Generators, Electric Utilities

Electricity Generators, Independent Power Producers

Combined Heat and Power, Electric Power

Combined Heat and Power, Commercial[1]

Combined Heat and Power, Industrial[1]

49
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 5.3. Average Operating Heat Rate for Selected Energy Sources, 2001 through 2010

(Btu per Kilowatthour)

Period Coal 1 Petroleum 2 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 R 10,414 10,923 8,160 10,460

2010 10,415 10,984 8,185 10,452

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: • 2009 natural gas heat rate is revised •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.

 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
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 5.4. Average Heat Rates by Prime Mover and Energy Source, 2010

(Btu per Kilowatthour)

Prime Mover Coal Petroleum Natural Gas[1] Nuclear

Steam Turbine 10,142 10,249 10,416 10,452

Gas Turbine[2] -- 13,386 11,590 --

Internal Combustion -- 10,429 9,917 --

Combined Cycle W 10,474 7,619 --

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

[2] Includes binary turbines.

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. • The average heat rates above are weighted by Net Summer Capacity. • In 2010, EIA changed the way 

it treated blank values in its methodology for calculating average heat rates.

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

51
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 6.1. Electric Power Industry - Electricity Purchases, 1999 through 2010(Thousand Megawatthours)

2010 2009 2008 2007 2006 2005 2004 2003 2002 200

U.S. Total 5,770,134 5,028,647 5,612,781 5,411,422 5,502,584 6,092,285 6,998,549 6,979,669 8,754,807 7,55Electric Utilities 2,353,086 2,364,648 2,483,927 2,504,002 2,605,315 2,760,043 2,725,694 2,610,525 2,620,712 3,04Energy-Only Providers 3,319,211 2,564,407 3,024,730 2,805,833 2,793,288 3,250,298 4,170,331 4,264,102 6,050,159 4,4

IPP 23,976 27,922 25,431 24,942 26,628 12,201 24,258 37,921 15,801 97,

CHP 73,861 71,669 78,693 76,646 77,353 69,744 78,267 67,122 68,135 

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 Ge

predecessor forms; and Form EIA-923, "Power Plant Operations Report" for 2007 and predecessor form(s) for earlier years.

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 equa

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 20caution.[1] For 2001, CHP purchases are combined with IPP data above. NA = Not available.  R = Revised. 

52
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 6.2. Electric Power Industry - Electricity Sales for Resale, 1999 through 2010(Thousand Megawatthours)

2010 2009 2008 2007 2006 2005 2004 2003 2002 200

U.S. Total 5,929,211 5,065,031 5,680,733 5,479,394 5,493,473 6,071,659 6,758,975 6,920,954 8,568,678 7,34Electric Utilities 1,541,554 1,495,636 1,576,976 1,603,179 1,698,389 1,925,710 1,923,440 1,824,030 1,838,901 2,14Energy-Only Providers 2,946,452 2,240,399 2,718,661 2,476,740 2,446,104 2,867,048 3,756,175 3,906,220 5,757,283 4,38

IPP 1,404,137 1,295,857 1,355,017 1,368,310 1,321,342 1,252,796 1,053,364 1,156,796 943,531 811,

CHP 37,068 33,139 30,079 31,165 27,638 26,105 25,996 33,909 28,963 

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 Ge

predecessor forms; and Form EIA-923, "Power Plant Operations Report" for 2007 and predecessor form(s) for earlier years.[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 

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 crounding.

53
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 6.3. Electric Power Industry - U.S. Electricity Imports from and Electricity Exports to Canada and Mexico, 1999-2010

(Megawatthours)

Trading Partner 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Canada

Imports from ............... 43,763,091 51,108,502 55,732,400 50,118,056 41,544,052 42,332,039 33,007,487 29,324,625 36,536,479 38,401,598 48,515,476 42,911,308

Exports to .................. 18,481,678 17,490,264 23,499,445 19,559,417 23,405,387 18,680,237 22,482,109 23,584,513 15,231,079 16,105,612 12,684,706 12,953,488

Mexico

Imports from ............... 1,320,095 1,082,093 1,286,981 1,277,644 1,147,258 1,597,275 1,202,576 1,069,926 242,596 98,649 76,800 303,439

Exports to .................. 624,502 647,720 698,714 584,176 865,948 470,731 415,754 390,190 564,603 367,680 2,144,676 1,268,284

U.S. Total 

Imports 45,083,186 52,190,595 57,019,381 51,395,702 42,691,310 43,929,314 34,210,063 30,394,551 36,779,077 38,500,247 48,592,276 43,214,747

Exports 19,106,180 18,137,984 24,198,159 20,143,592 24,271,335 19,150,968 22,897,863 23,974,703 15,795,681 16,473,292 14,829,382 14,221,772

Sources:

National Energy Board of Canada; DOE, Office of Electricity Delivery and Energy Reliability, Form OE-781R, 

"Annual Report of International Electric Export/Import Data," predecessor forms.

To estimate electricity trade with Mexico, for 2001 forward data from the California Independent System Operator are used 

in combination with the Form OE-781R values.

U.S. Electricity Imports and Exports

54
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 7.1. Number of Ultimate Customers Served by Sector, by Provider, 1999 through 2010

(Count)

Period Residential Commercial Industrial Transportation Other All Sectors

Total Electric Industry

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

2010 125,717,935 17,674,338 747,746 239 NA 144,140,258

Full-Service Providers[1]

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 122,533,214 16,860,320 736,751 666 NA 140,130,951

2010 121,555,089 16,675,341 718,651 198 NA 138,949,279

Energy-Only Providers

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 2,643,961 701,341 20,768 39 NA 3,366,109

2010 4,162,846 998,997 29,095 41 NA 5,190,979

[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."

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."

 NA = Not available. 

55
Electric Power Annual 2010

Released: November 2011

Revised: March 2012

Next Update: November 2012

Table 7.2. Retail Sales and Direct Use of Electricity to Ultimate Customers by Sector, by Provider, 1999 through 2010

(Megawatthours)

Total

Residential Commercial Industrial Transportation Other Total End Use

Total Electric Industry

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 3,764,560,712 125,670,185[R] 3,890,230,897[R]

2008 1,379,981,104 1,335,981,135 1,009,300,309 7,699,632 NA 3,732,962,180 132,196,685[R] 3,865,158,865[R]

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

2010 1,445,708,403 1,330,199,364 970,872,874 7,712,412 NA 3,754,493,053 131,910,249 3,886,403,302

Full-Service Providers[2]

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 1,345,125,375 1,140,767,357 813,292,567 2,453,843 NA 3,301,639,142 NA 3,301,639,142

2010 1,409,355,244 1,123,328,313 840,091,476 2,440,567 NA 3,375,215,600 NA 3,375,215,600

Energy-Only Providers

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 19,349,042 166,400,456 104,149,496 5,326,730 NA 295,225,724 NA 295,225,724

2010 36,353,159 206,871,051 130,781,398 5,271,845 NA 379,277,453 NA 379,277,453

Period

Sales

Direct Use[1]

[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.

Sources: U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report;" Form EIA-923, "Power Plant Operations Report" and predecessor 

[2] These data include Facility Direct Retail Sales.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."

 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 
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 7.3. Revenue from Retail Sales of Electricity to Ultimate Customers by Sector, by Provider, 1999 through 2010

(Million Dollars)

Period Residential Commercial Industrial Transportation Other All Sectors

Total Electric Industry[1]

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 157,008 132,940 62,504 828 NA 353,280

2010 166,782 135,559 65,750 815 NA 368,906

Full-Service Providers[2]

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 153,723 112,111 53,345 226 NA 319,405

2010 161,221 110,298 54,561 233 NA 326,312

Restructured Retail Service 

Providers[3]

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 20,828 9,159 602 NA 33,875

2010 5,560 25,261 11,190 582 NA 42,593

57
Energy-Only Providers[4]

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 14,271 7,205 460 NA 23,813

2010 3,230 16,999 8,664 425 NA 29,318

Delivery-Only Service

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 6,557 1,954 143 NA 10,062

2010 2,330 8,262 2,526 157 13,276

 NA = Not available. 

Notes: • See Technical Notes reference for definitions. • Full-Service Providers sell bundled electricity services (e.g., both energy and 

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

[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.

58
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 7.4. Average Retail Price of Electricity to Ultimate Customers by End-Use Sector, 1999 through 2010

(Cents per kilowatthour)

Period Residential Commercial Industrial Transportation Other All Sectors

Total Electric Industry[1]

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 7.2 7.29

2002 8.44 7.89 4.88 NA 6.75 7.2

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 10.4 9.46 6.16 9.54 NA 8.9

2007 10.65 9.65 6.39 9.7 NA 9.13

2008 11.26 10.36 6.83 10.74 NA 9.74

2009 11.51 10.17 6.81 10.65 NA 9.82

2010 11.54 10.19 6.77 10.57 NA 9.83

Full-Service Providers[2]

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 8.4 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 9.4 8.46 5.61 7.45 NA 8.05

2006 10.36 9.18 6 8.44 NA 8.77

2007 10.59 9.29 6.17 8.82 NA 8.98

2008 11.18 9.98 6.6 9.96 NA 9.54

2009 11.43 9.83 6.56 9.2 NA 9.67

2010 11.44 9.82 6.49 9.55 NA 9.67

Restructured Retail Service 

Providers[3]

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 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 6.5 6.95 NA 8.55

2005 12.26 10.6 7.08 9.47 NA 9.39

2006 14.43 11.99 8.21 10.32 NA 10.87

2007 15.8 12.35 8.37 10.11 NA 11.03

2008 17.49 12.77 9.54 11.12 NA 12.12

2009 16.98 12.52 8.79 11.31 NA 11.47

2010 15.30 12.21 8.56 11.04 NA 11.23

59
Energy-Only Providers[4]

1999 8.17 7.26 4.43 NA 6.45 5.81

2000 5.69 5.84 5.1 NA 4.47 5.5

2001 5.34 6.22 4.69 NA 5.23 5.51

2002 5.43 5.86 4.53 NA 4.3 5.27

2003 5.43 6.02 4.47 6.16 NA 5.3

2004 5.5 6.02 4.6 4.99 NA 5.42

2005 6.54 7.15 5.31 7.4 NA 6.41

2006 8.23 8.36 6.25 8.24 NA 7.66

2007 9.8 8.71 6.87 8.28 NA 8.09

2008 10.91 9.34 7.76 8.79 NA 8.98

2009 9.7 8.58 6.92 8.63 NA 8.07

2010 8.88 8.22 6.62 8.06 NA 7.73

Delivery-Only Service

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 3.5

2003 6.11 3.8 1.8 2.07 -- 3.13

2004 6 3.59 1.9 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 3.63 1.5 1.84 NA 2.95

2008 6.59 3.43 1.78 2.34 NA 3.13

2009 7.28 3.94 1.88 2.68 NA 3.41

2010 6.41 3.99 1.93 2.98 NA 3.50

 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."

[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

[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.

60
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 7.5. Net Metering and Green Pricing Customers by End Use Sector, 2003 - 2010(Count)

Residential Non Residential Total Residential Non Residential 

2003 819,579 57,547 877,126 5,870 943 2004 864,794 63,539 928,333 14,114 1,712 2005 871,774 70,998 942,772 19,244 1,902 

2006[1] 606,919 35,937 642,856 30,689 2,930 

2007 773,391 62,260 835,651 44,886 3,943 2008 918,284 64,711 982,995 64,400 5,609 2009 1,058,185 65,593 1,123,778 88,222 8,284 2010 1,137,047 79,535 1,216,582 141,844 13,997 

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

[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 pr

Notes: • Green Pricing programs allow electricity customers the opportunity to purchase electricity generated from renewable resources, thereby encourag

Period Green Pricing Net Metering

61
Table 8.1. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities, 1999 through 2010

(Million Dollars)

Description 2010 2009 2008 2007 2006 2005 2004 2003 2002 20

Utility Operating Revenues 284,373 276,124 298,962 270,964 275,501 265,652 238,759 230,151 219,609 Electric Utility 260,113 249,303 266,124 240,864 246,736 234,909 213,012 206,268 200,360 Other Utility 24,260 26,822 32,838 30,100 28,765 30,743 25,747 23,883 19,250 Utility Operating Expenses 250,122 244,243 267,263 241,198 245,589 236,786 206,960 201,057 189,062 Electric Utility 226,845 219,544 236,572 213,076 218,445 207,830 183,121 179,044 171,604 Operation 159,585 154,925 175,887 153,885 158,893 150,645 131,560 125,436 116,660 Production 128,808 118,816 140,974 121,700 127,494 120,586 103,871 98,305 90,715 Cost of Fuel 44,115 40,242 47,337 39,548 37,945 36,106 28,544 26,871 24,149 Purchased Power 67,284 67,630 84,724 74,112 79,205 77,902 67,126 63,749 58,810 Other 13,013 10,970 8,937 8,058 10,371 6,599 8,226 7,709 7,776 Transmission 6,948 6,742 6,950 6,051 6,179 5,664 4,531 3,653 3,560 Distribution 4,007 3,947 3,997 3,765 3,640 3,502 3,287 3,214 3,117 Customer Accounts 5,091 5,203 5,286 4,652 4,409 4,229 4,077 4,262 4,168 Customer Service 4,741 3,857 3,567 2,939 2,536 2,291 2,013 1,902 1,820 Sales 185 178 225 239 240 219 237 238 264 Administrative and General 17,115 15,991 14,718 14,346 14,580 14,130 13,537 13,863 13,018 Maintenance 14,962 14,092 14,192 13,181 12,838 12,033 11,743 11,340 10,861 Depreciation 20,930 20,095 19,049 17,936 17,373 17,123 16,322 15,981 16,199 Taxes and Other 27,646 29,081 26,202 27,000 28,149 26,805 22,190 25,027 26,716 Other Utility 23,277 24,698 30,692 28,122 27,143 28,956 23,839 22,013 17,457 Net Utility Operating Income 34,251 31,881 31,699 29,766 29,912 28,866 31,799 29,094 30,548 Notes: • 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 erroneimbalances 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."

62
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 8.2. Average Power Plant Operating Expenses for Major U.S. Investor-Owned Electric Utilities, 1999 through 2010(Mills per Kilowatthour)

Plant Type 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 OperationNuclear 10.50 10 9.89 9.54 9.03 8.26 8.97 9.12 9 8.44 6.Fossil Steam 4.04 4.23 3.72 3.63 3.57 3.21 3.13 2.74 2.59 2.47 2.Hydroelectric[1] 5.33 4.88 5.78 5.44 3.76 3.95 3.83 3.47 3.71 4.27 3.Gas Turbine and Small 2.79 3.05 3.77 3.26 3.51 3.69 4.27 3.5 3.26 3.65 3.MaintenanceNuclear 6.80 6.34 6.2 5.79 5.69 5.27 5.38 5.23 5.04 5.02 4.Fossil Steam 3.99 3.96 3.59 3.37 3.19 2.98 2.96 2.72 2.67 2.61 2.Hydroelectric[1] 3.81 3.5 3.89 3.87 2.7 2.73 2.76 2.32 2.62 2.89 2.Gas Turbine and Small 2.73 2.58 2.72 2.42 2.16 1.89 2.14 2.26 2.38 3.33 3.FuelNuclear 6.68 5.35 5.29 4.99 4.85 4.63 4.58 4.6 4.6 4.67 4Fossil Steam 27.73 32.3 28.43 23.88 23.09 21.69 18.21 17.29 16.09 18.15 17.Hydroelectric[1] -- -- -- -- -- -- -- -- -- -- Gas Turbine and Small 43.21 51.93 64.23 58.75 53.89 55.52 45.18 43.89 31.84 43.55 41.TotalNuclear 23.98 21.69 21.37 20.32 19.57 18.15 18.93 18.95 18.65 18.13 15.Fossil Steam 35.76 40.48 35.75 30.88 29.85 27.88 24.31 22.75 21.36 23.23 22.Hydroelectric[1] 9.15 8.38 9.67 9.32 6.46 6.68 6.6 5.79 6.33 7.16 5.Gas Turbine and Small 48.74 57.55 70.72 64.43 59.56 61.1 51.59 49.66 37.47 50.53 48.[1] Conventional hydro and pumped storage.[2] Gas turbine, internal combustion, photovoltaic, and wind plants.Notes: • 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 (equivaleone 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 Energ

Velocity Suite."

63
Electric Power Annual 2010

Released: November 2011 Next Update: November 2012

Table 8.3. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (With Generation Facilities), 1999 through 2010(Million Dollars)

Description 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Operating Revenue - Electric NA NA NA NA NA NA NA 33,906 32,776 38,028 31,843 26,767

Operating Expenses - Electric NA NA NA NA NA NA NA 29,637 28,638 32,789 26,244 21,274

Operation Including Fuel NA NA NA NA NA NA NA 22,642 21,731 25,922 19,575 15,386

Production NA NA NA NA NA NA NA 17,948 17,176 21,764 15,742 11,923

Transmission NA NA NA NA NA NA NA 872 858 785 781 732Distribution NA NA NA NA NA NA NA 696 680 605 574 516Customer Accounts NA NA NA NA NA NA NA 582 537 600 507 415

Customer Service NA NA NA NA NA NA NA 280 315 263 211 160

Sales NA NA NA NA NA NA NA 84 74 73 66 49

Administrative and General NA NA NA NA NA NA NA 2,180 2,090 1,832 1,695 1,591

Maintenance NA NA NA NA NA NA NA 2,086 1,926 1,904 1,815 1,686

Depreciation and Amortization NA NA NA NA NA NA NA 3,844 3,907 4,009 3,919 3,505

Taxes and Tax Equivalents NA NA NA NA NA NA NA 1,066 1,074 954 936 697

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

 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.

64
Electric Power Annual 2010

Released: November 2011 Next Update: November 2012

Table 8.4. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (Without Generation Facilities), 1999 through 2010(Million Dollars)

Description 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Operating Revenue - Electric NA NA NA NA NA NA NA 12,454 11,546 10,417 9,904 9,354

Operating Expenses - Electric NA NA NA NA NA NA NA 11,481 10,703 9,820 9,355 8,737

Operation Including Fuel NA NA NA NA NA NA NA 10,095 9,439 8,864 8,424 7,874

Production NA NA NA NA NA NA NA 8,865 8,311 7,863 7,486 7,015

Transmission NA NA NA NA NA NA NA 105 93 61 64 48

Distribution NA NA NA NA NA NA NA 348 320 311 280 261

Customer Accounts NA NA NA NA NA NA NA 172 163 164 155 143

Customer Service NA NA NA NA NA NA NA 31 39 26 22 22

Sales NA NA NA NA NA NA NA 11 10 15 16 14

Administrative and General NA NA NA NA NA NA NA 562 504 423 402 371

Maintenance NA NA NA NA NA NA NA 418 389 304 286 272

Depreciation and Amortization NA NA NA NA NA NA NA 711 631 405 394 369

Taxes and Tax Equivalents NA NA NA NA NA NA NA 257 244 247 251 223

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

 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.

65
Electric Power Annual 2010

Released: November 2011 Next Update: November 2012

Table 8.5. Revenue and Expense Statistics for U.S. Federally Owned Electric Utilities, 1999 through 2010(Million Dollars)

Description 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Operating Revenue - Electric NA NA NA NA NA NA NA 11,798 11,470 12,458 10,685 10,186

Operating Expenses - Electric NA NA NA NA NA NA NA 8,763 8,665 10,013 8,139 7,775

Operation Including Fuel NA NA NA NA NA NA NA 6,498 6,419 7,388 5,873 5,412

Production NA NA NA NA NA NA NA 5,175 5,236 6,247 5,497 4,890

Transmission NA NA NA NA NA NA NA 307 244 354 332 349

Distribution NA NA NA NA NA NA NA11122

Customer Accounts NA NA NA NA NA NA NA 4 10 16 6 1

Customer Service NA NA NA NA NA NA NA 63 60 60 48 50

Sales NA NA NA NA NA NA NA 20 6 6 10 28

Administrative and General NA NA NA NA NA NA NA 927 862 705 467 528

Maintenance NA NA NA NA NA NA NA 600 566 521 488 436

Depreciation and Amortization NA NA NA NA NA NA NA 1,335 1,351 1,790 1,471 1,623

Taxes and Tax Equivalents NA NA NA NA NA NA NA 329 328 315 308 304

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

 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.

66
Electric Power Annual 2010

Released: November 2011Revised: January 2012Next Update: November 2012Table 9.1. Demand-Side Management Actual Peak Load Reductions by Program Category, 1999 through 2010(Megawatts)Item 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 20Total Actual Peak Load Reduction

33,283 31,682 31,735 30,253 27,240 25,710 23,532 22,904 22,936 24,955 

Energy Efficiency 20,808 19,766 19,707 17,710 15,959 15,351 14,272 13,581 13,420 13,027 Load Management 12,475 11,916 12,028 12,543 11,281 10,359 9,260 9,323 9,516 11,928 

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

67
Electric Power Annual 2010

Released: November 2011Revised: January 2012Next Update: November 2012Table 9.2. Demand-Side Management Program Annual Effects by Program Category, 1999 through 2010(MW, MWh)Item 2010 2009 2008 2007 2006 2005 2004 2003 2002 20Annual Effects – Energy EfficiencyLarge UtilitiesActual Peak Load Reduction (MW) 20,808 19,766 19,707 17,710 15,959 15,351 14,272 13,581 13,420 Energy Savings (Thousand MWh) 86,926 76,891 74,861 67,134 62,951 58,891 52,662 48,245 52,285 Annual Effects – Load ManagementLarge UtilitiesActual Peak Load Reduction (MW) 12,475 11,916 12,028 12,543 11,281 10,359 9,260 9,323 9,516 Potential Peak Load Reductions (MW) 25,880 26,178 26,246 23,087 21,270 21,282 20,998 25,290 26,888 Energy Savings (Thousand MWh) 913 1,015 1,813 1,857 865 1,006 2,047 2,020 1,790 

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."

68
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 9.3. Demand-Side Management Program Incremental Effects by Program Category, 1999 through 2010(MW, MWh)

Item 2010 2009 2008 2007 2006 2005 2004 2003 2002 2

Incremental Effects – Energy EfficiencyLarge UtilitiesActual Peak Load Reduction (MW) 4,736 2,941 5,764 1,649 1,177 1,403 1,521 945 1,054 Energy Savings (Thousand MWh) 13,560 12,698 10,407 7,426 5,385 5,872 4,522 2,939 3,543 Small UtilitiesActual Peak Load Reduction (MW) 28 777 567 349 91 302 204 90 49 Energy Savings (Thousand MWh) 32 209 21 254 9 7 10 8 192 

Incremental Effects – Load Management

Large UtilitiesActual Peak Load Reduction (MW) 2,601 2,152 2,923 1,356 1,495 1,009 907 1,084 1,160 Potential Peak Load Reductions (MW) 4,987 5,811 6,636 3,342 2,544 2,005 2,622 1,981 2,655 Energy Savings (Thousand MWh) 49 65 167 132 95 133 2 29 65 Small UtilitiesActual Peak Load Reduction (MW) 108 75 371 1,036 195 153 242 81 54 Potential Peak Load Reductions (MW) 246 232 620 1,423 273 218 422 131 76 Energy Savings (Thousand MWh) 111545442

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."

69
Electric Power Annual 2010

Released: November 2011Revised: January 2012Next Update: November 2012Table 9.4. Demand-Side Management Program Annual Effects by Sector, 1999 through 2010(MW, Thousand MWh)

Item 2010 2009 2008 2007 2006 2005 2004 2003 2002 20

Actual Peak Load Reductions (MW) Large UtilitiesResidential 14,094 12,605 12,910 13,192 10,730 9,432 8,870 9,431 9,137 Commercial 10,882 11,399 11,097 8,054 7,779 7,926 7,194 6,774 6,839 Industrial 8,160 7,666 7,602 8,990 8,692 8,343 7,454 6,594 6,500 Transportation 147 12 126 17 39 9 14 105 NA Other NA NA NA NA NA NA NA NA 460 Total 33,283 31,682 31,735 30,253 27,240 25,710 23,532 22,904 22,936 Potential Peak Load Reductions (MW)Large UtilitiesResidential 17,293 15,986 16,831 15,263 13,040 12,097 11,967 12,525 12,072 Commercial 14,060 14,366 13,850 10,201 10,006 10,214 9,624 8,943 9,298 Industrial 15,053 15,502 15,103 15,271 14,119 14,260 13,665 17,298 18,321 Transportation 282 90 169 62 64 62 14 105 NA Other NA NA NA NA NA NA NA NA 617 Total 46,688 45,944 45,953 40,797 37,229 36,633 35,270 38,871 40,308 Energy Savings (Thousand MWh)Large UtilitiesResidential 32,436 27,811 26,534 23,688 21,437 19,255 17,763 13,469 15,438 Commercial 37,659 35,019 34,869 30,725 28,982 28,416 24,624 25,089 24,391 Industrial 17,655 15,002 15,196 14,470 13,348 12,178 12,273 11,156 11,339 Transportation 89 76 76 109 50 48 51 551 NA Other NA NA NA NA NA NA NA NA 2,907 Total 87,839 77,907 76,674 68,992 63,817 59,897 54,710 50,265 54,075  NA = Not available. 

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

70
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table 9.5. Demand-Side Management Program Incremental Effects by Sector, 1999 through 2010

(MW, Thousand MWh)

Item 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Actual Peak Load Reductions (MW)

Large Utilities

Residential 1,986 2,055 5,507 1,344 1,012 966 1,361 640 895 790 572 605

Commercial 3,512 1,598 2,329 983 759 715 560 528 527 742 515 684

Industrial 1,838 1,436 849.0 677 901 731 507 849 680 640 502 929

Transportation 1 4 2 1 0 0 0 12 NA NA NA NA

Other NA NA NA NA NA NA NA NA 112 124 50 45

Total 7,337 5,093 8,687 3,005 2,672 2,412 2,428 2,029 2,214 2,296 1,640 2,263

Small Utilities

Residential 58 586 220 871 131 325 280 88 48 32 37 27

Commercial 38 226 287 342 63 71 126 58 41 15 37 22

Industrial 40 40 431 130 92 59 40 25 12 16 62 7

Transportation 0 0 0 42 0 0 0 0 NA NA NA NA

Other NA NA NA NA NA NA NA NA 0 0 26 19

Total 136 852 938 1,385 286 455 446 171 101 63 162 76

U.S. Total 7,473 5,945 9,625 4,390 2,958 2,867 2,874 2,200 2,317 2,361 1,802 2,339

Potential Peak Load Reductions (MW)

Large Utilities

Residential 3,234 3,118 7,246 2,374 1,406 1,311 1,680 752 1,311 900 699 753

Commercial 3,715 2,762 3,025 1,574 1,114 1,098 894 602 751 1,115 565 718

Industrial 2,774 2,849 2,127 1,042 1,201 999 1,569 1,551 1,506 1,277 1,815 5,612

Transportation 1 23 2 1 0 0 0 21 NA NA NA NA

Other NA NA NA NA NA NA NA NA 141 155 79 68

Total 9,724 8,752 12,400 4,991 3,721 3,408 4,143 2,926 3,709 3,447 3,159 7,151

Small Utilities

Residential 120 653 315 962 164 367 395 116 64 158 55 41

Commercial 58 251 304 513 95 100 154 73 43 19 51 25

Industrial 96 105 568 243 105 53 77 32 15 18 64 9

Transportation 0 0 0 54 0 0 0 0 NA NA NA NA

Other NA NA NA NA NA NA NA NA 3 2 44 31

Total 274 1,009 1,187 1,772 364 520 626 221 125 197 215 106

U.S. Total 9,998 9,761 13,587 6,763 4,085 3,928 4,769 3,147 3,834 3,644 3,374 7,257

Energy Savings (Thousand MWh)

Large Utilities

Residential 6,496 4,867 4,584 3,515 2,141 2,276 1,842 868 1,203 1,365 856 990

Commercial 5,338 4,975 4,440 2,831 2,339 2,638 1,815 1,356 1,583 1,867 1,780 1,502

Industrial 1,770 2,920 1,549 1,199 999 1,090 867 732 706 872 547 475

Transportation 5 1 1 13 0 * 0 12 NA NA NA NA

Other NA NA NA NA NA NA NA NA 116 376 164 127

Total 13,609 12,763 10,574 7,558 5,479 6,004 4,524 2,968 3,608 4,481 3,347 3,094

Small Utilities

Residential 13 197 16 157 9 6 6 7 45 5 9 4

Commercial 6 5 4 98 3 5 7 5 148 3 4 3

Industrial 13 8 2 4 1 * 2 1 2 2 1 1

Transportation * * * 0 0 0 0 0 NA NA NA NA

Other NA NA NA NA NA NA NA NA * 3 3 1

Total 33 210 22 259 13 12 14 13 194 13 17 9

U.S. Total 13,641 12,972 10,596 7,817 5,492 6,016 4,539 2,981 3,802 4,492 3,364 3,103

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

 * = 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.

71
Electric Power Annual 2010

Released: November 2011Next Update: November 2012Table 9.6. Demand-Side Management Program Energy Savings, 1999 through 2010(Thousand Megawatthours)

Item 2010 2009 2008 2007 2006 2005 2004 2003 2002 2

Total Energy Savings 87,839 77,907 76,674 68,992 63,817 59,897 54,710 50,265 54,075 Energy Efficiency 86,926 76,891 74,861 67,134 62,951 58,891 52,662 48,245 52,285 Load Management 913 1,015 1,813 1,857 865 1,006 2,047 2,020 1,790 

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."

72
Electric Power Annual 2011

Released: November 2011

Revised: March 2012

Next Update: November 2012

Table 9.7. Demand-Side Management Program Direct and Indirect Costs, 1999 through 2010

(Thousand Dollars)

Item 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999

Direct Cost[1] 3,946,541 3,199,568 2,994,280 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

Energy Efficiency 2,902,086 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

Load Management 1,044,455 944,117 836,038 700,176 665,733 625,568 515,057 352,137 413,614 358,098 445,566 430,581

Indirect Cost[2] 273,523 394,182 181,131 158,378 127,499 126,543 132,294 137,670 204,600 174,684 180,669 172,955

Total DSM Cost[3] 4,220,064 3,593,750 3,175,410 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] 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.

 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."
U.S. Energy Information Administration/Electric Power Annual 2010 1

100,x (x t )

(x t (x-) t )

1

2 1

 ̧

 ̧

1

·

 ̈

 ̈

©

§

Appendix A.

Technical Notes

This appendix describes how the U.S. Energy 

Information Administration collects, estimates, and 

reports electric power data in the Electric Power 

Annual.

Data Quality and Submission

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 

collection respondent frames, survey forms, and 

reviews the quality of the data received.

Data are entered directly by respondents into the 

ERUS Internet Data Collection (IDC) system. A small 

number of hard copy forms are keyed into the system

by ERUS personnel. All data are subject to review via 

interactive edits built into the IDC system, internal

quality assurance reports, and review by ERUS 

subject matter experts. Questionable data values are 

verified through contacts with respondents, and survey 

non-respondents are identified and contacted. 

IDC 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, must either be corrected by the respondent or 

the respondent must enter an explanation as to why 

the data are correct. If these explanations are 

unsatisfactory the respondent is contacted by EIA for 

clarification or corrected data.

Those respondents unable to use the electronic 

reporting method provide the data in hard copy, 

typically via fax and email. These data are manually 

entered into the computerized database and are 

subjected to the same data edits as those performed 

during e-filing by the respondent.

Reliability of Data 

Annual survey data have non-sampling errors. Nonsampling errors can be attributed to many sources: (1) 

inability to obtain complete information about all 

cases (i.e., non-response); (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 

non-sampling errors can be obtained, precautionary 

steps were taken in all phases of the frame 

development and data collection, processing, and 

tabulation processes to minimize their influence. 

Imputation: If the reported values appear to be in 

error and the data issue cannot be resolved with the 

respondent, or if the facility is a non-respondent, a 

regression methodology is used to impute for the 

facility. The regression methodology relies on other 

data to make estimates for erroneous or missing 

responses. The basis for the current methodology 

involves a 'borrowing of strength' technique for small 

domains.1

Data Revision Procedure

The EPA presents the most current and complete 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.

After data are disseminated as final, revisions will be 

considered if a correction would 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.

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)). 

Rounding and Percent Change

Calculations

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 period t1

and subsequent period t2.

74
2

Data Sources for Electric Power 

Annual

Data published in the EPA are compiled from forms 

filed annually or aggregated to an annual basis from 

monthly forms (see figure on EIA Electric Industry 

Data Collection in Appendix A). The respondents to 

these forms include electric utilities, other generators 

and sellers of electricity, and North American Electric 

Reliability Corporation (NERC) reliability entities. 

The EIA forms used are: 

x Form EIA-411, “Coordinated Bulk Power 

Supply Program Report;” 

x Form EIA-860, “Annual Electric Generator 

Report;”

x Form EIA-861, “Annual Electric Power 

Industry Report;” 

x 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.

Survey data from other Federal sources are also 

utilized for this publication. They include: 

x DOE Form OE-781R, “Annual Report of 

International Electric Export/Import Data” 

(Office of Electricity Delivery and Energy 

Reliability); 

x FERC Form 1, “Annual Report of Major 

Electric Utilities, Licensees, and Others;” 

x U. S. Department of Agriculture (USDA) 

Rural Utility Service Form 7, “Financial and 

Statistical Report;” and 

x USDA 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 inactive forms: 

x Form EIA-412, “Annual Electric Industry 

Financial Report,” FERC Form 423, “Cost 

and Quality of Fuels for Electric Plants,” 

x Form EIA-423, “Monthly Cost and Quality 

of Fuels for Electric Plants Report;” 

x Form EIA-759, “Monthly Power Plant 

Report,” 

x Form EIA-767, “Steam-Electric Plant 

Operation and Design Report;” 

x Form EIA-860A, “Annual Electric Generator 

Report–Utility,” 

x Form EIA-860B, “Annual Electric Generator 

Report–Nonutility,” 

x Form EIA-867, “Annual Nonutility Power 

Producer Report,”

x Form EIA-900, “Monthly Nonutility Power 

Report,” 

x Form EIA-906, “Power Plant Report;” and

x Form EIA-920, “Combined Heat and Power 

Plant Report.” 

Additionally, some data reported in this publication 

were acquired from public reports of the National 

Energy Board of Canada on electricity imports and 

exports.

Meanings of Symbols Appearing in Tables

The following symbols have the meaning described 

below:

* The value reported is less than half of the 

smallest unit of measure, but is greater than 

zero.

P Indicates a preliminary value.

NM Data value is not meaningful, either (1) when 

compared to the same value for the previous 

time period, or (2) when a data value is not 

meaningful due to having a high Relative 

Standard Error (RSE).

(*) Usage of this symbol indicates a number 

rounded to zero.

Form EIA-411

The information reported on the mandatory Form 

EIA-411 includes: (1) actual energy and peak demand 

for the preceding year and five additional years; (2) 

existing and future generating capacity and capacity 

reserve margins; (3) scheduled capacity transfers; (4) 

projections of capacity, demand, purchases, sales, and 

scheduled maintenance; (5) power flow cases; and (6) 

bulk power system maps. The data is collected for 

EIA by NERC from NERC regional reliability 

entities, which in turn aggregate reports from regional 

members. Non-member data is also included. The 

compiled data is reviewed and edited by NERC and 

submitted to EIA annually on July 15. The data 

undergoes additional review by EIA. EIA resolves any 

quality issues with NERC. 

Instrument and Design History: The Form EIA-411

program was initiated under the Federal Power 

Commission (FPC) Docket R-362, Reliability and 

Adequacy of Electric Service, and Orders 383-2, 383-

3, and 383-4. The DOE, established in October 1977, 

assumed the responsibility for this activity. The 

responsibility for collecting these data was delegated 

to the Office of Emergency Planning and Operations 

within the DOE and was transferred to EIA for the 

reporting year 1996. Until 2008, this form was 

voluntary, The data is collected under the authority of 

the Federal Power Act (Public Law 88-280), the 

75
3

Federal Energy Administration Act of 1974 (Public 

Law 93-275), and the DOE Organization Act (Public 

Law 95-91). 

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 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. 

(Alaska and, obviously, Hawaii are electrically 

interconnected with the coterminous 48 States).

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 to 

handle the regional reliability responsibilities of the 

Electric Reliability Council of Texas (ERCOT). The 

revised delegation agreements covering all the regions 

were approved by the FERC 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 current NERC regional entity names are as 

follows: 

x Florida Reliability Coordinating Council 

(FRCC),

x Midwest Reliability Organization (MRO),

x Northeast Power Coordinating Council 

(NPCC),

x ReliabilityFirst Corporation (RFC),

x Southeastern Electric Reliability Council 

(SERC),

x Southwest Power Pool (SPP), 

x Texas Regional Entity (TRE), and

x Western Electricity Coordinating Council 

(WECC). 

Changes Introduced in 2011: Starting in 2011, 

NERC modified the bulk power system reporting

regions (in contrast to regional reliability entity 

organizational boundaries) to align them with electric 

market operations. Consequently, reliability data will 

be reported for the PJM and MISO regional 

transmission organization areas and the MAPP area

rather than for the MRO and RFC regional areas..

This new framework, along with the other NERC 

regions, now forms the bulk power system reliability 

assessment areas.

Historically the MRO, RFC, SERC, and SPP regional 

boundaries were altered as utilities changed reliability 

organizations. In published EIA reports the historical 

data series for these regions have not been adjusted. 

Instead, starting in 2011, EIA has introduced the 

Balance of Eastern Region category to provide a 

consistent trend for the Eastern interconnection.

Concept of Demand within the EIA-411: The EIA411 uses the following categorization of electricity 

demand:

x Net Internal Demand: Internal Demand 

less Direct Control Load Management and 

Interruptible Demand.

x 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.

x 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. 

x 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 

76
4

Operator or by action of the customer at the 

direct request of the System Operator.

For additional information on demand, refer to the 

NERC’s Long-Term Reliability Assessments at

http://www.nerc.com/page.php?cid=4|61.

Sensitive Data: 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 

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. Data was collected 

annually.

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. 

Beginning with the 2003 collection, the transmission 

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. 

Instrument and Design History: The 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 and renamed the 

Federal Energy Regulatory Commission (FERC). 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. 

The criteria used to select the respondents for this 

survey fit approximately 500 publicly owned electric 

utilities. Federal electric utilities were 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: For 2001 -

2003, the California Department of Water Resources 

(CDWR) 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 CDWR, 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: 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 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 (CHP) producers whose total fossil-fueled 

nameplate generating capacity was 50 or more 

megawatts (MW). (CHP plants are sometimes 

referred to as co-generators. They produce heat, such 

as steam for use in a manufacturing process, along 

with electricity).

Instrument and Design History: The Form EIA4232 was 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."

Issues within Historical Data Series: Natural gas 

values do not include blast furnace gas or other gas. 

Sensitive Data: Plant fuel cost data collected on the 

survey are considered business sensitive. State- and 

national-level aggregations are published 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 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 criteria for filing, a plant must have had a 

total steam turbine electric generating capacity and/or 

combined-cycle (gas turbine with associated steam 

turbine) generating capacity of 50 or more megawatts. 

Only fuel delivered for use in steam-turbine and 

combined-cycle units was reported. Fuel received for 

use in gas-turbine or internal-combustion units that 

was not associated with a combined-cycle operation 

77
5

was not reported. The FERC Form 423 was replaced 

after 2007 by the Form EIA-923. 

Instrument and Design History: On July 7, 1972, 

the FPC issued Order Number 453 enacting the New 

Code of Federal Regulations, Section 141.61, 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. When DOE 

was formed in 1977, most of FPC became FERC. The 

FERC Form 423 replaced the FPC Form 423 in 

January 1983. The FERC Form 423 dropped standalone combustion turbines. 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 generatornameplate-capacity 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. On January 1, 2008, EIA assumed 

responsibility for collection of these data and both the 

utility and nonutility plants began to report their cost 

and quality of fuels information on Schedule 2 of 

Form EIA-923, "Power Plant Operations Report."

Issues within Historical Data Series: 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 survey. The data were quality reviewed by 

EIA and when possible quality issues were resolved 

with FERC.

Natural gas values for 2001 forward do not include 

blast furnace gas or other gas. 

Due to the estimation procedure described below in 

the discussion of the Form EIA-923, 2003 and later 

data cannot be directly compared to previous years’ 

data.

Sensitive Data: Data collected on FERC Form 423 

are not 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 re-titled Form EIA-767, 

“Steam-Electric Plant Operation and Design Report.” 

In 1986, the respondent universe of 700 plants was 

increased to 900 plants 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 

nonutility plants. 

Collection of data via the form was suspended for the 

2006 data year. Starting with 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." 

Estimation of EIA-767 Data: No estimation of Form 

EIA-767 data was performed. Normally the survey 

had no non-response.

Issues within Historical Data Series: As noted 

above, no data were collected for calendar year 2006.

Sensitive Data: Latitude and longitude data collected 

on the Form EIA-767 were considered business 

sensitive. 

Form EIA-860

The Form EIA-860 is a mandatory annual 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 10-year 

plans for constructing new plants, as well as 

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. 

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. It

was preceded by several Federal Power Commission

(FPC) forms including the FPC Form 4, Form 12 and 

12E, Form 67, and Form 411. In January 1999, the 

78
6

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 

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 2007, design parameters data formerly 

collected on Form EIA-767 were 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: EIA received forms 

form all 18,151 existing generators in the 2010 EIA860 frame, so no imputation was required.

Issues within Historical Data Series Regarding 

Categorization of Capacity by Business Sector:

There are a small number of electric utility CHP 

plants, as well as a small number of industrial and 

commercial generating facilities that are not CHP. 

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.”

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 EPA 2006, capacity by producer type 

was determined at the power plant level for 2005 and 

all subsequent data collections. This change required 

revisions to the original published 2005 data.

Issues within Historical Data Series Regarding 

Planned Capacity: Delays and cancellations may 

have occurred subsequent to respondent data reporting 

as of December 31 of the data year.

Issues within Historical Data Series Regarding 

Capacity by Energy Source: Prior to the EPA 2005, 

the capacity for generators for which natural gas or 

petroleum was the most predominant energy source 

was presented in the following three categories: 

petroleum only, natural gas only, and dual-fired. The 

dual-fired category, which was EIA’s effort to infer 

which generators could fuel-switch 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 fuelswitching 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.

In the EPA 2005, certain petroleum-fired capacity was 

misclassified as natural gas-fired capacity for 1995 –

2003. This was corrected in the EPA 2006.

Corrections were noted as revised data.

Sensitive Data: 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 annual census of 

electric power industry participants in the United 

States. The survey is used to collect information on 

power sales and revenue data from approximately 

3,300 respondents. About 3,200 are electric utilities, 

and the remainders are nontraditional entities such as 

energy service providers or the unregulated 

subsidiaries of electric utilities and power marketers.

Transportation Sector: Prior to 2003, sales of 

electric power for transportation (e.g., city subway 

systems) 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 data collection 

sales to the Transportation Sector were collected 

separately. The balance of the Other Sector was

reclassified as Commercial Sector sales except that 

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 

electricity (i.e., gasoline, diesel fuel, etc.) are not 

included.

79
7

Benchmark statistics were reviewed from outside 

surveys, most notably the U.S. Department of 

Transportation (DOT) Federal Transit 

Administration’s National Transportation Database, a 

source previously used by EIA to estimate electricity 

transportation consumption. The DOT survey 

indicated the State and City locations of expected 

respondents. The Form 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 2010, 64

respondents reported transportation data in 28 States.

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 Energy Service 

Providers (ESPs). 

The reporting methodology change uses sales volumes 

and a customer count reported by distribution utilities, 

and modifies only an incremental revenue value, 

representing revenue associated with misreported 

sales assumed to be attributable to the ESPs that were 

under-represented in the survey frame.

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. 

Average Retail Price of Electricity: This value 

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. 

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 other taxes paid 

by the utility. 

This computed average retail price of electricity 

reported in this publication by is a weighted average 

of consumer revenue and sales and does not equal 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 of 

the electric power industry participant for providing 

electrical service. 

Issues within Historical Data Series: 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. The number of ultimate customers is an 

average of the number of customers at the close of 

each month. Also see the discussion of the 

Transportation Sector, above.

Demand-Side Management (DSM): The following 

definitions are supplied to assist in interpreting DSM 

data. Utility costs reflect the total cash expenditures 

for the year, in nominal dollars, that used to support 

DSM programs.

x Actual Peak Load Reduction is 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.

x Energy Savings is 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.

x Large Utilities are 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.

x Potential Peak Load Reduction is the potential 

peak load reduction as a result of load 

management, and also the actual peak load 

reduction achieved by energy efficiency 

programs.

Sensitive Data: None.

Forms EIA-906 and EIA-920 (Replaced 

in 2008 by Form EIA-923)

80
8

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 form was ended after the 2007 data 

collection and replaced by the Form EIA-923. 

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 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 EIA-900 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 data on the production of 

useful thermal output (typically process steam) by 

combined heat and power (CHP) plants.

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 CHP plants; all other plants that generated 

electricity continued 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: A relatively 

small number electric commercial- and industrialonly plants are, for the purposes of this report, are 

included in the CHP data categories. The small 

number of electric utility plants that are CHP units are 

reported together with other utility plants. No 

information on the production of useful thermal output 

(UTO) or fuel consumption for UTO was collected or 

estimated for the electric utility CHP plants.

Sensitive Data: The only business sensitive data 

element collected on the Forms EIA-906 and EIA-920

was fuel stocks at the end of the reporting period. 

Form EIA-923

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).3 Data are 

collected from a monthly sample of approximately 

1,900 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 CHP 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 EIA-923 

Supplemental Form (Schedules 6, 7, and 8A to 8F).

Approximately 3,900 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 annually. In addition to 

electric power generating plants, respondents include 

fuel storage terminals without generating capacity that 

receive shipments of fossil fuel 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 annually. For all 

other plants, consumption is reported at the primemover level and generation is reported at the primemover level or, for noncombustible sources (e.g., 

wind, nuclear), at the prime-mover and energy source 

levels (including generating units for nuclear only).

The source and disposition of electricity are 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: See discussion of 

predecessor forms (EIA-906, -920, -767, and -423, 

and FERC Form 423). 

Imputation: For data collected monthly, regression 

prediction, or imputation, is done for all missing data 

including non-sampled units and any non-respondents. 

For data collected annually, imputation is performed

for non-respondents. For gross generation and total 

fuel consumption, multiple regression is used for 

imputation (see discussion, above). Only 

approximately 0.02 percent of the national total 

generation for 2010 is imputed, although this will vary 

by State and energy source.

When gross generation is reported and net generation 

is not available, net generation is estimated by using a 

fixed ratio to gross generation by prime-mover type

81
9

and installed environmental equipment. These ratios 

are:

Prime Movers: 

Combined Cycle Steam - 0.97

Combined Cycle Single Shaft - 0.97

Combined Cycle Combustion Turbine - 0.97

Compressed Air - 0.97

Fuel Cell - 0.99

Gas Turbine - 0.98

Hydroelectric Turbine - 0.99

Hydroelectric Pumped Storage - 0.99

Internal Combustion Engine - 0.98

Other - 0.97

Photovoltaic - 0.99

Steam Turbine - 0.97

Wind Turbine - 0.99

Environmental Equipment:

Flue Gas Desulfurization - 0.97

Flue Gas Particulate 0.99

All Others - 0.97

Net Generation = (Factor) x Gross Generation

For stocks, a linear combination of the prior month’s 

ending stocks value and the current month’s 

consumption and receipts values is used.

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 CHP 

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 to 

produce aggregates and weighted averages for each 

fuel type at the State, Census division, and U.S. levels. 

The units for receipts are: 1) coal and petroleum coke, 

tons and million Btu per ton; 2) petroleum, barrels and 

million Btu per barrel.; and gases in thousand cubic 

feet (Mcf) and million Btu per thousand cubic foot. 

Methodology to Estimate Biogenic and Nonbiogenic Municipal Solid Waste:4 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:

x The 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 (EPA) 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.

x 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).5

x The percentages of biogenic and nonbiogenic components of MSW are applied to 

the net and gross generation from MSW, 

splitting the generation into a renewable 

share (biogenic) and non-renewable share 

(non-biogenic). 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 nonbiogenic 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 (UTO): With the 

implementation of the Form EIA-923, “Power Plant 

Operations Report,” in 2008, CHP plants were 

required to report total fuel consumed and electric 

power generation. Beginning with preliminary January 

2008 data, EIA estimated the allocation of the total 

fuel consumed at CHP plants between electric power 

generation and UTO.

The estimated allocation methodology is summarized 

in the following paragraphs. The methodology was 

82
10

retroactively applied to 2004-2007 data. Prior to 

2004, UTO was collected 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 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 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. 

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 for 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 that 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.

Also beginning with January 2008 data, tables for 

total receipts included 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 at or 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 

Form 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. 

Issues within Historical Data Series for Generation 

and Consumption: Beginning in 2008, a new 

method of allocating fuel consumption between 

electric power generation and UTO was implemented 

(see above). This new methodology evenly distributes 

a 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.

Sensitive Data: The total delivered cost of fuel 

delivered to nonutilities, the commodity cost of fossil 

fuels, and fuel stocks are considered business 

sensitive.

Air Emissions

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 EPA 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 EIA923. 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:

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, 

83
11

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: 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.6 These 

distinctions are shown in Tables A1 and A2.

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 and EIA-923 surveys for 

the years 2007 through 2010. 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.

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 (U.S. 

EPA’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 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 Form 

EIA-923 and predecessors. 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 

commercial 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 fossil-fueled plants 

to install low-NOx 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 EIA767. The Form EIA-860, EIA-923, and the historical 

EIA-767 surveys are limited to plants with boilers 

fired by combustible fuels7 with a minimum 

generating capacity of 10 megawatts (nameplate). 

Pollution control equipment data are unavailable from 

EIA sources for plants that did not report on the 

historical EIA-767 survey, or the Forms EIA-860 and 

EIA-923.

The following method is used to estimate SO2 and 

NOx emissions:

x 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 not collected in 2006, updates for 

new installations during this period were made 

based on EPA data. Beginning in 2007, these data 

were collected on the Forms EIA-860 and EIA923. 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.

84
12

x For plants and prime movers not reported on the

historical Form EIA-767 survey or Forms EIA860 and 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 and predecessors.

o The sulfur content of the fuel is 

estimated from fuel receipts for the plant 

reported on the Form EIA-923. When 

plant-specific sulfur content data are 

unavailable, the national average sulfur 

content for the fuel, computed from the 

Form EIA-923 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 drybottom, and the boiler firing 

configuration. However, this boiler 

information is unavailable for steam 

electric plants that did not report on the 

historical Forms 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 

A1.8

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.

x If actual emissions of SO2 or NOx are reported in 

the 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.

Conversion of Petroleum Coke 

to Liquid Petroleum 

The quantity conversion is 5 barrels (of 42 U.S. 

gallons each) per short ton (2,000 pounds). 

Relative Standard Error

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 non-sampling 

error. In fact, large RSE estimates found in 

preliminary work with these data have often indicated 

non-sampling errors, which were then identified and 

corrected. Non-sampling errors may be attributed to 

many sources, including 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 non-sampling errors also occur in 

complete censuses. 

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 non-sampling 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 

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.

Business Classification

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 EIA, in the EPA and other data products, 

classifies nonutility power producers into the 

following categories:

x The Electric Power Sector consists of the 

combination of utilities and independent 

power producers (IPPs) whose primary 

85
13

business is selling electricity in the public 

markets. 

x The Industrial Sector are power producers 

whose primary business falls under NAICS9

classifications of Agriculture, Forestry, 

Fishing, Mining, Construction, or 

Manufacturing.

x The Commercial Sector are those facilities

where the primary business falls under 

NAICS classifications of Transportation and 

Public (non-electric) Utilities, Wholesale 

Trade, Retail Trade, Finance, Insurance, 

Services, Public Administration, and Real 

Estate.

Each of these nonutility sectors is further divided into 

facilities which do or do not operate as CHP plants.

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

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, and 

management

611 Education services

86
14

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

_______________________________________

1 The basic technique employed is described in the paper “Model-Based 

Sampling and Inference,” on the EIA website. Additional references can be 

found on the InterStat website (http://interstat.statjournals.net/). See the 

following sources: Knaub, J.R., Jr. (1999a), “Using Prediction-Oriented 

Software for Survey Estimation,” InterStat, August 1999, 

http://interstat.statjournals.net/; Knaub, J.R. Jr. (1999b), “Model-Based 

Sampling, Inference and Imputation,” EIA web site:

http://www.eia.gov/cneaf/electricity/forms/eiawebme.pdf; Knaub, J.R., Jr. 

(2005), “Classical Ratio Estimator,” InterStat, October 2005, 

http://interstat.statjournals.net/; Knaub, J.R., Jr. (2007a), “Cutoff Sampling 

and Inference,” InterStat, April 2007, http://interstat.statjournals.net/; Knaub, 

J.R., Jr. (2008), “Cutoff Sampling.” Definition in Encyclopedia of Survey 

Research Methods, Editor: Paul J. Lavrakas, Sage, to appear; Knaub, J.R., Jr. 

(2000), “Using Prediction-Oriented Software for Survey Estimation - Part II: 

Ratios of Totals,” InterStat, June 2000, http://interstat.statjournals.net/;

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/.

2 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.

3 The Form EIA-923 superseded Forms EIA-906, EIA-920, EIA-423, FERC 

Form 423, and part of Form EIA-767 in 2008. However, it was used to 

collect certain 2007 data including environmental data that previously were 

collected on the Form EIA-767, and utility and nonutility data collected 

annually on the Forms EIA-906 and EIA-920. 

4 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.

5 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.

6 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.

7 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.

8 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.pdf.

9 Business classifications are based on the North American Industry 

Classification System (NAICS).

87
Electric Power Annual 2010

Released: November 2011Next Update: November 2012

Table A1. Sulfur Dioxide Uncontrolled Emission Factors(Units and Factors)

Emissions Units

(Lbs = pounds, 

MMCF = million 

cubic feet, 

MG = thousand 

gallons)

Agricultural Byproducts (AB) Source: 1 Lbs per ton 0.08 0.01 0.08 0.08 0.08 0.08 

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 

Bituminous Coal (BIT)* Source: 2, Table 

1.1-3

Lbs per ton 38 3.8 38 38 38 38 

Black Liquor (BLQ) Source: 1 Lbs per ton ** 7 0.7 7 7 7 7

Distillate Fuel Oil (DFO)* Source: 2, Table 

3.1-2a, 3.4-1 & 1.3-1

Lbs per MG 157 15.7 157 157 157 157 

Jet Fuel (JF)* Assumed to have 

emissions similar to DFO.

Lbs per MG 157 15.7 157 157 157 157 

Kerosene (KER)* Assumed to have 

emissions similar to DFO.

Lbs per MG 157 15.7 157 157 157 157 

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 

Lignite Coal (LIG)* Source: 2, Table 

1.7-1

Lbs per ton 30 3 30 30 30 30 

Tangential Boiler

All Other Boiler 

Types

Fuel, Code, Source and Emission units Combustion System Type/Firing Configuration

Fuel And EIA Fuel Code

Source and Tables 

(As appropriate) Cyclone Boiler

Fluidized Bed 

Boiler

Opposed Firing 

Boiler

Spreader Stoker 

Boiler

88
Municipal Solid Waste (MSW) Source: 1 Lbs per ton 1.7 0.17 1.7 1.7 1.7 1.7 

Natural Gas (NG) 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 

Other Biomass Gas (OBG) Sources: 1 

(including footnote 7 within source); 2, Table 1.4-2 (including footnote d within source)

Lbs per MMCF 0.6 0.06 0.6 0.6 0.6 0.6 

Other Biomass Liquids (OBL)* Source: 1 

(including footnotes 3 and 16 

within source)

Lbs per MG 157 15.7 157 157 157 157 

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 

Other Gases (OG) Source: 1 

(including footnote 7 within source)

Lbs per MMCF 0.6 0.06 0.6 0.6 0.6 0.6 

Other (OTH) Assumed to have 

emissions similar to NG.

Lbs per MMCF 0.6 0.06 0.6 0.6 0.6 0.6 

Petroleum Coke (PC)* Source: 1 Lbs per ton 39 3.9 39 39 39 39 Propane Gas (PG) 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 

Residual Fuel Oil (RFO)* Source: 2, Table 

1.3-1

Lbs per MG 157 15.7 157 157 157 157 

Synthetic Coal (SC)* Assumed to have 

the emissions similar to Bituminous Coal.

Lbs per ton 38 3.8 38 38 38 38 

Sludge Waste (SLW) Source: 1 

(including footnote 11 within source)

Lbs per ton ** 2.8 0.28 2.8 2.8 2.8 2.8 

89
Subbituminous Coal (SUB)* Source: 2, Table 

1.1-3

Lbs per ton 35 3.5 35 38 35 35 

Tire-Derived Fuel (TDF)* Source: 1 

(including footnote 13 within source)

Lbs per ton 38 3.8 38 38 38 38 

Waste Coal (WC)* Source: 1 

(including footnote 20 within source)

Lbs per ton 30 3 30 30 30 30 

Wood Waste Liquids (WDL)* Source: 1 

(including footnotes 3 and 16 

within source)

Lbs per MG 157 15.7 157 157 157 157 

Wood Waste Solids (WDS) Source: 1 Lbs per ton 0.29 0.08 0.29 0.08 0.29 0.29 

Waste Oil (WO)* Source: 2, Table 

1.11-2

Lbs per MG 147 14.7 147 147 147 147 

** Although Sludge Waste and Black Liquor consist substantially of liquids, these fuels are measured and reported to EIA in tons.Sources:

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.g

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 cprovide 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 (ava

at:http://www.epa.gov/appcdwww/aptb/EPA-600-R-01-109A.pdf). 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. En

Factor and Inventory Group (D205-01), Emissions, Monitoring and Analysis Division, Research Triangle Park; and 

90
Electric Power Annual 2010

Released: November 2011Next Update: November 2012

Table A2. Nitrogen Oxides Uncontrolled Emission Factors (Units and Factors)

Emissions Units

(Lbs = pounds, 

MMCF = million 

cubic feet, 

MG = thousand 

gallons)

Agricultural Byproducts (AB) Source: 1 Lbs per ton 1.2 1.2 1.2 1.2 1.2 1.2 

Blast Furnace Gas (BFG) Sources: 1 

(including footnote 7 within source); EIA estimates

Lbs per MMCF 15.4 15.4 15.4 15.4 15.4 15.4 

Bituminous Coal (BIT) Source: 2, Table 

1.1-3

Lbs per ton 33 5 12 [31] 11 10.0 [14.0] 12.0 [31.0] 

Black Liquor (BLQ) Source: 1 Lbs per ton ** 1.5 1.5 1.5 1.5 1.5 1.5 

Distillate Fuel Oil (DFO) Source: 2, Tables 

3.4-1 & 1.3-1

Lbs per MG 24 24 24 24 24 24 

Jet Fuel (JF) Source: 2, Tables 

3.1-2a, 3.4-1 & 1.3-1

Lbs per MG 24 24 24 24 24 24 

Kerosene (KER) Source: 2, Tables 

3.1-2a, 3.4-1 & 1.3-1

Lbs per MG 24 24 24 24 24 24 

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 

Lignite Coal (LIG) Source: 2, Table 

1.7-1

Lbs per ton 15 3.6 6.3 5.8 7.1 6.3 

Municipal Solid Waste (MSW) Source: 1 Lbs per ton 5 5 5 5 5 5

Natural Gas (NG) Source: 2, Tables 

1.4-1, 3.1-1, and 3.4-1

Lbs per MMCF 280 280 280 280 170 280 

Fuel And EIA Fuel Code

Source and Tables 

(As appropriate) Cyclone Boiler

Fluidized Bed 

Boiler

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

Opposed Firing 

Boiler

Spreader Stoker 

Boiler Tangential Boiler

All Other Boiler 

Types

91
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 

Other Biomass Liquids (OBL) Source: 1 

(including footnote 3 within source)

Lbs per MG 19 19 19 19 19 19 

Other Biomass Solids (OBS) Source: 1 

(including footnote 11 within source)

Lbs per ton 2 2 2 2 2 2

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 

Other (OTH) Assumed to have 

emissions similar to natural gas.

Lbs per MMCF 280 280 280 280 170 280 

Petroleum Coke (PC) Source: 1 

(including footnote 8 within source)

Lbs per ton 21 5 21 21 21 21 

Propane Gas (PG) Sources: 3; EIA 

estimates

Lbs per MMCF 215 215 215 215 215 215 

Residual Fuel Oil (RFO) Source: 2, Table 

1.3-1

Lbs per MG 47 47 47 47 32 47 

Synthetic Coal (SC) Assumed to have 

emissions similar to Bituminous Coal.

Lbs per ton 33 5 12 [31] 11 10.0 [14.0] 12.0 [31.0] 

Sludge Waste (SLW) Source: 1 

(including footnote 11 within source)

Lbs per ton **5 5 5 5 5 5 

Subbituminous Coal (SUB) Source: 2, Table 

1.1-3

Lbs per ton 17 5 7.4 [24] 8.8 7.2 7.4 [24.0] 

Tire-Derived Fuel (TDF) Source: 1 

(including footnote 13 within source)

Lbs per ton 33 5 12 [31] 11 10.0 [14.0] 12.0 [31.0] 

Waste Coal (WC) Source: 1 

(including footnote 20 within source)

Lbs per ton 15 3.6 6.3 5.8 7.1 6.3 

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 

Wood Waste Solids (WDS) Source: 1 Lbs per ton 2.51 2 2.51 1.5 2.51 2.51 

92
Waste Oil (WO) Source: 2, Table 

1.11-2

Lbs per MG 19 19 19 19 19 19 

Note: ** Although Sludge Waste and Black Liquor consist substantially of liquids, these fuels are measured and reported to EIA in tons.Sources:

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.g

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

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. En

Factor and Inventory Group (D205-01); Emissions, Monitoring and Analysis Division, Research Triangle Park; 

93
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table A3. Carbon Dioxide Uncontrolled Emission Factors

(Pounds of CO2 per Million Btu)

Factor 

(Pounds of CO2 Per Million Btu)***

Bituminous Coal (BIT) Source: 1 205.3

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: 1 215.4

Natural Gas (NG) Source: 1 117.08

Petroleum Coke (PC) Source: 1 225.13

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. 205.3

Subbituminous Coal (SUB) Source: 1 212.7

Tire-Derived Fuel (TDF) Source: 1 189.538

Waste Coal (WC) Assumed to have emissions similar to Bituminous Coal. 205.3

Waste Oil (WO) Source: 2, Table 1.11-3 (assumes typical heat content of 4.4 

MMBtus per barrel)

210

Note: *** CO2 factors do not vary by combustion system type or boiler firing configuration.

Sources: 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; available at: http://www.eia.doe.gov/oiaf/1605/coefficients.html; and 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/.

Municipal Solid Waste (MSW) Source: 1 (including footnote 2 within source) 91.9

 Fuel, Code, Source, and Emission Factor

Fuel And EIA Fuel Code Source and Tables (As appropriate)

94
Electric Power Annual 2010

Released: November 2011

Next Update: November 2012

Table A4. Nitrogen Oxides Control Technology Emissions Reduction Factors

Nitrogen Oxides Reduction Factor

Control Technology (Percent)

Advanced Overfire Air AA 30[1]

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 30[1]

Other (or Unspecified) OT 20

Overfire Air OV 20[1]

Selective Catalytic Reduction SR 70

Selective Catalytic Reduction 

 With Low Nitrogen Oxide Burners 

Selective Noncatalytic Reduction SN 30

Selective Noncatalytic Reduction 

 With Low NOx Burners 

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: Energy Information Administration, Form EIA-860, "Annual Electric Generator Report;" Babcock and Wilcox, Steam 41st Edition, 2005.

EIA-Code(s)

SR and LN 90

SN and LN 50

95
Electric Power Annual 2010

Released: November 2011 

Next Update: November 2012

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: Energy Information Administration, Office of Electricity, Renewables, and Uranium Statistics

96
U.S. Energy Information Administration/Electric Power Annual 2010 

97