#  



# Electric Power Annual 2010

November 2011

I ndependent 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 A dditions 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 Fuel

Ͳ Switching Capacity of 1.7. Generators Reporting Natural Gas as the Primar y Fuel, by Producer Type 1.8. Generators Reporting Petroleum Liquids as the Primary Fuel, by Producer Type 1.9. Fuel

Ͳ Switching Capacity: From Natural Gas to Petroleum Liquids, by Type of Prime Mover 1.10. Fuel

Ͳ Switching Capacity: From Natural Gas to Petroleum Liquids, by Year of Initial Commercial Operation Interc onnection 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 O utput 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. End

Ͳ of

Ͳ Year 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 Re ceipts 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 Combined

Ͳ Heat

Ͳ and

Ͳ Power Plants 3.10. Number and Capacity of Fossil

Ͳ Fuel Steam

Ͳ Electric Generators with Environmental Equipment 3.11. Average Flue Gas Des ulfurization Costs

Chapter 4. Demand, Capacity Resources, and Capacity Margins 4.1.A. Noncoincident Peak Load by North American Electric Reliability Corporation Assessment Area, 1999

Ͳ 2010 Actual 4.1.B. Noncoincident Peak Load by North American Electric Reliability Corporation Assessment Area, 2010 Actual, 2011

Ͳ 2015 Projected Net Internal Demand 4.2.A. Net Energy for Load by North American Ele ctric Reliability Corporation Assessment Area, 1999

Ͳ 2010 Actual 4.2.B. Net Energy for Load by North American Electric Reliability CorporationAssessment Area, 2010 Actual, 2011

Ͳ 2015 Projected 4.3.A. Summer Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Assessment Area, 1999

Ͳ 2010 Actual 4.3.B. Summer Ne t Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Corporation Assessment Area, 2010 Actual, 2011

Ͳ 2015 Projected 4.4.A. Winter Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Assessment Areas, 2001

Ͳ 2010 Actual 4.4.B. Winter Net Internal Demand, Capacity Resources, and Capacity Margins by North Amer ican Electric Reliability Corporation Assessment Area, 2010 Actual, 2011

Ͳ 2015 Projected 4.5.A. Existing Transmission Capacity by High

Ͳ Voltage Size, 2010 4.5.B. Proposed Transmission Capacity Additions by High

Ͳ Voltage Size, 2011

Ͳ 2017

Chapter 5. Characteristics of the Electric Power Industry 5.1. Count of Electric Power Industry Power Plants, by Sector, by Pr edominant Energy Sources within Plant Average 5.2. Capacity Factors by Energy Source Ͳ forthcoming 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 Re tail Sales of Electricity to Ultimate Customers by Sector, by Provider 7.4. Average Retail Price of Electricity to Ultimate Customers by End

Ͳ Use 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. Investor

Ͳ Owne d Electric Utilities 8.2. Average Power Plant Operating Expenses for Major U.S. Investor

Ͳ Owned 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 Utiliti es Ͳ forthcoming

Chapter 9. Demand

Ͳ Side Management 9.1. Demand

Ͳ Side Management Actual Peak Load Reductions by Program Category Demand

Ͳ Side 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. Sulf ur 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. Unit

Ͳ of

Ͳ Measure 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 Annual2010Released: November 2011Revised: March 2012Next Update: November 2012Table ES2. Supply and Disposition of Electricity, 1999 through 2010(Million Megawatthours)Category2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999SupplyGenerationElectric Utilities 2,472 2,373 2,475 2,504 2,484 2,475 2,505 2,462 2,549 2,630 3,015 3,174Independent Power Producers1,339 1,278 1,332 1,324 1,259 1,247 1,119 1,063955781458201Combined Heat and Power, Electric162159167177165180184196194170165155Electric Power Sector Generation Subtotal3,972 3,810 3,974 4,005 3,908 3,902 3,808 3,721 3,698 3,580 3,638 3,530Combined Heat and Power, Commercial988888877789Combined Heat and Power, Industrial144132137143148145154155153149157156Industrial and Commercial Generation Subtotal153140145151157153162162160157165165Total Net Generation4,125 3,950 4,119 4,157 4,065 4,055 3,971 3,883 3,858 3,737 3,802 3,695Total Imports455257514344343037394943Total Supply4,170 4,003 4,176 4,208 4,107 4,099 4,005 3,914 3,895 3,775 3,851 3,738DispositionRetail SalesFull-Service Providers3,365 3,289 3,434 3,468 3,438 3,413 3,318 3,285 3,324 3,297 3,310 3,236Energy-Only Providers3792952862832192372221891419811276Facility Direct Retail Sales101314141211820NANANANATotal Electric Industry Retail Sales3,754 3,597 3,733 3,765 3,670 3,661 3,547 3,494 3,465 3,394 3,421 3,312Direct Use132127132126147150168168166163171172Total Exports191824202419232416161514Losses and Unaccounted For265261287298266269266228248202244240Total Disposition4,170 4,003 4,176 4,208 4,107 4,099 4,005 3,914 3,895 3,775 3,851 3,738NA = Not available.R = Revised.Notes:• Facility Direct Retail Sales typicallyrepresent bilateral electric power sales between industrial and commercial generatingfacilities. • Direct Use represents commercial and industrial facilityuse of onsite net electricitygeneration; electricitysales or transfers to adjacent or co-located facilities; and barter transactions.Losses and Unaccounted For includes: (1) reporting by utilities and power marketers thatrepresent losses incurred in transmission and distribution, as well as volumesunaccounted for in their own energy balance; and (2) discrepancies among the differing categories upon balancing the table. • Totals may not equal sum of components because of independent rounding.Sources:U.S. Energy Information Administration, Form EIA-923, "Power Plant Operations Report" and predecessor form(s) including U.S. Energy Information Administration, Form EIA-906, "Power Plant Report;" and Form EIA-920, "CombinedHeat and Power Plant Report;" Form EIA-861, "Annual Electric Power Industry Report;"and predecessor forms.Imports and Exports: Mexico data - DOE, Fossil Fuels, Office of Fuels Programs, Form OE-781R, "Annual Report of InternationalElectrical 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 biom ass, 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 condui t 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 bu nker 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.



### 5Electric Power A nnual 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, an d 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 (prima ry) 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), wo od 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



### 9Table 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 capaci ty 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, "A nnual 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 bu nker 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, ut ility poles, w ood 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, an d 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 C o n v e n

t i o n a l 7 2 2 2 1 1 9 2 1 1 12 7 4 2 8 7 3 2 4 W i n d 6 9 4 , 5 6 5 4 , 5 4 5 4 , 5 4 6 2 2 2 22 7 1 2 9 6 2 9 1 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 Pu

m

ped Storag e -- -- -- -- -- -- -- -- -- 39 1 O t h e r [ 8 ] 1 1 1 1 25 0 3 9 3 9 3 4 3 4 3 4

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 bu nker 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, ut ility 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, an d 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 c apacity 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 genera tor in the count of number of generators. Source: U.S. Energy Information Administration, Form EIA-860, "A nnual Electric Generator Report."



### 11Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 1.6.A. Capacity of Dispersed Generators by Technology Type, 2005 through 2010(Count, Megawatts)InternalCombustionCombustionTurbineSteamTurbineHydroelectricWind andOtherWind Photovoltaic Storage Other(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) Number of (MW)2005*4290335 1262 1311,373 4,7662006*6524346 157389,536 7,0372007*7866268 10231 3011,057 8,2972008*933586 24834 7012,262 9,7732009*9751329 20481 10813,928 10,4752010277164 1486957 18 16,874 2,984PeriodTotalNote:Dispersed generators are commercial and industrial generators which are not connected to the grid. They may be installed at or near a customer`s site, or at other locations. They may be owned byeither 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.12Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 1.6.B. Capacity of Distributed Generators by Technology Type, 2005 through 2010(Count, Megawatts)InternalCombustionCombustionTurbineSteamTurbineHydroelectricWind andOtherWind Photovoltaic Storage Other(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) Number of (MW)2005[1]*40251917 1830 999 995 17,371 9,7662006*36461298 2582 806 1081 5,044 9,4112007*46241990 3596 1051 1441 7,103 12,7022008*51121949 3060 1154 1588 9,591 12,8632009*43394147 4621 1166 1729 13,006 16,0022010887186 110 97 99 236 0 373 15,630 1,988* During these years, generators above 1 MW were also counted. This changed in 2010 when only generators smaller than 1 MW were counted.PeriodTotal[1] Distributed generator data in 2005 include a significant number of generators reported by one respondent, which may be forresidential applications.Note:Distributed generators are commercial and industrial generators which are connected to the grid. They may be installed at ornear a customer`s site, or at other locations. They may be owned by eitherthe customers of the distribution utility or by the utility. Other includes generators for which technology is not specified.Source:U.S. Energy Information Administration, FormEIA-861, "Annual Electric Power Industry Report."13Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 1.6.C. Total Capacity of Dispersed and Distributed Generators by Technology Type, 2005 through 2010(Count, Megawatts)InternalCombustionCombustionTurbineSteamTurbineHydroelectricWind andOtherWind Photovoltaic Storage Other(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) Number of (MW)2005[1]*83152252 1956 1001 1008 28,744 14,5322006*101691644 2739 809 1088 14,580 16,4482007*124902258 3698 1082 1471 18,160 20,9992008*144472035 3308 1188 1658 21,853 22,6362009*140904476 4825 1248 1838 26,934 26,47720103658250 124 106 105 332 7 391 32,504 4,972* During these years, generators above 1 MW were also counted. This changed in2010 when only generators smaller than 1 MW were counted.PeriodTotal[1] Distributed generator data in 2005 include a significant number of generators reported by one respondent, which may be for residential applications.Note:Dispersed and distributed generators are commercial and industrial generators. Dispersed generators are not connected to the grid. Distributed generators are connected to the grid. Both typesof generators may be installed at or near a customer`s site, or at other locations, and both types of generators may be owned by either the customers of the distribution utility or by the utility. Otherincludes generators for which technology is not specified.Source:U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."14Electric 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 bu nker 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, "A nnual 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 bu nker 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 bu nker C fuel oil), jet fuel, kerosene, and waste oil.

Source: U.S. Energy Information Administration, Form EIA-860, "A nnual 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 Commerc ial 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 bu nker C fuel oil), jet fuel, kerosene, and waste oil.

Source: U.S. Energy Information Administration, Form EIA-860, "A nnual 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 gene rator 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 in terconnection 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, substation s, switching stations and other equipment necessary for interconnection. Units and Nameplate Capacity represent the number of units and associated capac ity 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 devic es, substations, switching stations and other equipment necessary for interconnection. Units and Nameplate Capacity represent the number of uni ts 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 wi nd, 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 stake holders. Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."

20Electric Power A nnual 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



### 212010 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 Phot ovoltaic, 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 Infor mation 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 bunke r 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 hydroel ectric power excluding pumped storage fac ilities.

Note: Totals may not equal sum of components because of independent rounding 6 The quantity of output from a hydroelectric pumped storage fac ility represents production minus energy used for pumping.

7 Non-biogenic municipal solid waste, batteries, chemicals, hydrogen, pitch, purchased steam, sulfur, tire-derived fuels and mi scellaneous technologies.

8 Electric utility CHP plants are included in El ectricity Generators, Electric Ut ilities.

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, "An nual 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 liqu ids, 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.



### 24Electric 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 Generat or 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 bunk er 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 mis cellaneous technologies. Notes: • The methodology to allocate fuel use by combined heat and power plants to electric power generation and useful thermal outpu t 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. • Tot als 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 bu nker 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 u seful thermal output (UTO) was implemented with publication of the preliminary 2008 data, and retroactively applied to 2004-2007 data. The new meth odology 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, "An nual 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 20 10 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 betwee n electric power generation and useful thermal output (UTO) was implemented with publication of the preliminary 2008 data, and retroactively app lied to 2004-2007 data. The new methodology evenly distributes a combined heat and power (CHP) plant`s losses between the two output products (electric pow er 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 el ectric 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 bu nker 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 A nnual 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 bu nker 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.



### 30Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 3.4. End-of-Year Stocks of Coal and Petroleum by Type of Producer, 1999 through 2010CoalPetroleumCoalPetroleumCoalPetroleum(Thousand Tons)[1](Thousand Barrels)[2](Thousand Tons)[1](Thousand Barrels)[2](Thousand Tons) (Thousand Barrels)1999 141,604 54,109 129,041 46,169 12,563 7,9402000 102,296 40,932 90,115 30,502 12,180 10,4302001138,49657,031117,14737,30821,34919,7232002141,71452,490116,95231,24324,76121,2472003121,56753,17097,83129,95323,73623,2182004106,66951,43484,91732,28121,75119,1532005101,13750,06277,45731,40023,68018,6612006140,96451,583110,27732,08230,68819,5022007151,22147,203120,50429,29730,71717,9062008161,58944,498127,46328,45034,12616,0482009189,46746,181154,81531,77834,65214,4022010174,91740,800143,74429,05031,17311,750Sources: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, subbituminous, lignite, and synthetic coal, excludes waste coal.[2] Distillate fuel oil (all diesel and No. 1, No. 2, and No. 4 fuel oils), residual fuel oil (No. 5 and No. 6 fuel oils and bunker C fuel oil), jet fuel, kerosene, petroleum coke (converted to liquidNA = Not available.Note:Totals may not equal sum of components because of independent rounding.PeriodElectric Power Sector Electric Utilities Independent Power Producers31Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 3.5. Receipts, Average Cost, and Quality of Fossil Fuels for the Electric Power Industry, 1999 through 2010All FossilFuelsAverageCostAverageCost1999 908,232 1.01 122 24.72 145,939 1.51 236 14.81 2,809,455 257 1442000 790,274 0.93 120 24.28 108,272 1.33 418 26.30 2,629,986 430 1742001 762,815 0.89 123 24.68 124,618 1.42 369 23.20 2,148,924 449 17320025884,287 0.94 125 25.52 120,851 1.64 334 20.77 5,607,737 356 1862003986,026 0.97 128 26.00 185,567 1.53 433 26.78 5,500,704 539 22820041,002,032 0.97 136 27.42 186,655 1.66 429 26.56 5,734,054 596 24820051,021,437 0.98 154 31.20 194,733 1.61 644 39.65 6,181,717 821 32520061,079,943 0.97 169 34.09 100,965 2.31 623 37.66 6,675,246 694 30220071,054,664 0.96 177 35.48 88,347 2.10 717 43.50 7,200,316 711 32320081,069,709 0.97 207 41.14 96,341 2.21 1,087 64.89 7,879,046 902 4112009981,477 1.01 221 43.74 88,951 2.14 702 41.64 8,118,550 474 3042010979,918 1.04 227 44.64 75,285 2.20 954 56.35 8,673,070 509 326Receipts(thousandbarrels)Avg. SulfurPercent byWeight4Average CostAverage Cost(dollars/ton)(cents perMMBtu)(dollars/barrel)(cents perMMBtu)PeriodCoal1Petroleum2Natural Gas3Receipts(thousand tons)Avg. SulfurPercent byWeightNotes:• 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, cost, andquality 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 notable increase infuel receipts beginning with 2008 data.Sources:U.S. Energy Information Administration (EIA), Form EIA-923, "Power Plant Operations Report" and predecessor form(s) includingForm EIA-423, "Monthly Cost and Qualityof Fuels for Electric Plants Report" and Federal Energy Regulatory Commission (FERC), FERC Form 423, "Monthly Report of Cost and Quality of Fuels for Electric Plants."(cents perMMBtu)1Anthracite, bituminous, subbituminous, lignite, waste coal, and synthetic coal.2Distillate 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 liquidpetroleum, see Technical Notes for conversion methodology), and waste oil.3Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately. Natural gas valuesfor 2001 forward do not include blast furnace gas or othergas.4Beginning in 2006, receipts of petroleum liquids went down substantially, while the receipts of petroleum coke remained the nearly the same. The Average Sulfur Percent by Weight ishigher 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.5Beginning in 2002, data from the historical Form EIA-423 for independent power producers and combined heat and power producersare included in this table. Prior to 2002, these datawere not collected; the data for 2001 and previous years include only data collected from electric utilities via the historicalFERC Form 423.Receipts(thousand Mcf)(cents perMMBtu)32Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 3.6. Receipts and Quality of Coal Delivered for the Electric Power Industry, 1999 through 2010Receipts(thousandtons)Avg. SulfurPercent byWeightAvg. AshPercent byWeightReceipts(thousand tons)Avg. SulfurPercent byWeightAvg. AshPercent byWeightReceipts(thousandtons)Avg. SulfurPercent byWeightAvg. AshPercent byWeightReceipts(thousandtons)Avg. SulfurPercent byWeightAvg. AshPercent byWeight1999 137 0.64 37.8 444,399 1.57 10.2 386,271 0.38 6.6 77,425 0.90 14.22000 11 0.64 37.2 375,673 1.45 10.1 341,242 0.35 6.3 73,349 0.91 14.220011------ 348,703 1.42 10.4 349,340 0.35 6.1 64,772 0.98 13.920022------ 412,589 1.47 10.1 391,785 0.36 6.2 65,555 0.93 13.32003------ 436,809 1.49 9.9 432,513 0.38 6.4 79,869 1.03 14.42004------ 441,186 1.50 10.3 445,603 0.36 6.0 78,268 1.05 14.22005------ 451,680 1.55 10.5 456,856 0.36 6.2 77,677 1.02 14.02006------ 462,992 1.57 10.5 504,947 0.35 6.1 75,742 0.95 14.42007------ 439,154 1.61 10.3 505,155 0.34 6.0 71,930 0.90 14.02008------ 463,943 1.68 10.6 522,228 0.34 5.8 68,945 0.86 13.82009------ 418,688 1.77 10.5 484,007 0.34 5.8 64,966 0.95 14.02010------ 403,619 1.90 10.5 491,425 0.33 5.8 71,416 0.92 14.22Beginning in 2002, data from the historical Form EIA-423 for independent power producers and combined heat and power producers are included in this table. Prior to 2002, these data were notcollected; the data for 2001 and previous years include only data collected from electric utilities via the historical FERC Form423.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 data are imputed for plantsbetween 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 receipts beginning with 2008 data.Sources:U.S. Energy Information Administration (EIA), Form EIA-923, "Power Plant Operations Report" and predecessor form(s) includingForm EIA-423, "Monthly Cost and Quality of Fuelsfor Electric Plants Report" and Federal Energy Regulatory Commission (FERC), FERC Form 423, "Monthly Report of Cost and Qualityof Fuels for Electric Plants."PeriodAnthraciteBituminousSubbituminousLignite1Beginning in 2001, anthracite coal receipts were no longer reported separately. From 2001 forward, all anthracite coal receipts have been combined with bituminous coal receipts.33Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 3.7. Average Quality of Fossil Fuel Receipts for the Electric Power Industry,1999 through 2010Natural Gas3199910,1631.019.0149,4071.511,019200010,1150.938.8149,8571.331,020200110,2000.898.8147,8571.421,0202002410,1680.948.7147,9021.641,025200310,1370.979.0147,0861.531,030200410,0740.979.0147,2861.661,027200510,1070.989.0146,4811.611,028200610,0630.979.0143,8832.311,027200710,0280.968.8144,5452.101,02720089,9470.979.0142,2052.211,02720099,9021.018.9141,3212.141,02520109,8421.048.9140,5982.201,022Average Btu per PoundAverage Sulfur Percentby WeightAverage Ash Percent byWeightAverage Btu per GallonAverage Sulfur Percentby WeightSources:U.S. Energy Information Administration (EIA), Form EIA-923, "Power Plant Operations Report" and predecessor form(s) includingForm EIA-423, "Monthly Cost andQuality of Fuels for Electric Plants Report" and Federal Energy Regulatory Commission (FERC), FERC Form 423, "Monthly Report ofCost and Quality of Fuels for Electric Plants."Average Btu per CubicFoot1Anthracite, bituminous, subbituminous, lignite, waste coal, and synthetic coal.2Distillate 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 toliquid petroleum, see Technical Notes for conversion methodology), and waste oil.3Natural gas, including a small amount of supplemental gaseous fuels that cannot be identified separately. Natural gas values for 2001 forward do not includeblast furnace gas or othergas.4Beginning in 2002, data from the historical Form EIA-423 for independent power producers and combined heat and power producersare included in this table. Prior to 2002, these datawere not collected; the data for 2001 and previous years include only data collected from electric utilities via the historicalFERC 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 quality data are imputed for plantsbetween 1 and 50 MW and are included in the data collected from plants at or above the 50 MW theshold. Therefore, there may bea notable increase in fuel receipts beginning with 2008data.YearCoal1Petroleum234Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 3.8. Weighted Average Cost of Fossil Fuels for the Electric Power Industry, 1999 through 2010Receipts(trillionBtu)AverageCost (centsperMMBtu)Receipts(trillionBtu)AverageCost (centsperMMBtu)Receipts(trillionBtu)AverageCost (centsperMMBtu)Receipts(trillionBtu)AverageCost (centsperMMBtu)Receipts(trillionBtu)AverageCost (centsperMMBtu)Receipts(trillionBtu)AverageCost (centsperMMBtu)Receipts(trillionBtu)AverageCost (centsperMMBtu)199910,722 131 6,740 110 996 93 18,461 122 916 236 2,862 257 22,238 14420009,050 130 5,991 108 947 94 15,988 120 681 418 2,682 430 19,351 17420018,312 139 6,134 104 839 109 15,286 123 783 369 2,209 449 18,278 17320029,932 142 6,878 105 851 104 17,982 125 751 334 5,750 356 24,483 186200310,543 144 7,598 110 1,026 103 19,990 128 1,146 433 5,663 539 26,799 228200410,538 156 7,817 112 1,012 106 20,189 136 1,155 429 5,891 596 27,234 248200510,833 184 8,004 119 1,008 107 20,647 154 1,198 644 6,357 821 28,202325200611,129 204 8,842 131 982 115 21,735 169 610 623 6,856 694 29,201 302200710,580 208 8,826 145 925 128 21,152 177 536 717 7,396 711 29,085 323200811,110 250 9,087 162 896 141 21,280 207 575 1,087 8,089 902 29,945 411200910,010 275 8,421 164 835 158 19,438 221 528 702 8,319 474 28,285 30420109,652 281 8,545 173 925 162 19,290 227 445 954 8,867 509 28,602 326All Coal RanksNotes:• Totals may not equal sum of components because of independent rounding. • Beginning in 2008 with the Form EIA-923, receipts, cost, and quality data are imputed for plants between 1 and 50 MW, inaddition 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) includingForm EIA-423, "Monthly Cost and Quality of Fuels for ElectricPlants Report" and Federal Energy Regulatory Commission (FERC), FERC Form 423, "Monthly Report of Cost and Quality of Fuels forElectric Plants."YearCoalPetroleum Natural GasTotal Fossil FuelsBituminousSubbituminousLignite35Electric Power Annual 2010Released: November 2011Revised: March 2012Next Update: November 2012Table 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 2001 2000 1999Carbon Dioxide (CO2)2,388,5962,269,5082,484,0122,547,0322,488,9182,543,8382,486,9822,445,0942,423,9632,418,6072,470,8342,366,302Sulfur Dioxide (SO2)5,401 5,970 7,830 9,042 9,524 10,340 10,309 10,646 10,881 11,174 11,904 12,843Nitrogen Oxides (NOx)2,491 2,395 3,330 3,650 3,799 3,961 4,143 4,532 5,194 5,290 5,638 5,955Source: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 of the sources and methodology used todevelop 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 revised downward from 11,963 thousandmetric 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 2 010

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 me thodology takes generator status into account where previously the data only reflected boiler and flue gas desulfurization unit statuses. • Data for Independent Powe r 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 fr om 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. • Dat a for Independent Power Producer and Combined Heat and Power plants are included beginning with 2001 data. • Totals may not equal sum of components bec ause of independent rounding. Sources: Through 2005, U.S. Energy Information Administration, Form EIA-767, "Steam-Electric Plant Operation and Design Report; " and from 2007 forward, U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report" for Average Installed Capital Costs, and Form EIA

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

38Electric 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 46,67 6 44,836 46,550 45,722 NPCC 52,855 50,057 55,949 56,012 55,018 52,549 58,960 63,241 58,31 4 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 6 2,188 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 41,70 1 45,275 53,022 46,135
NPCC 45,227 43,852 42,670 46,009 48,079 48,176 46,828 46,697 46,79 5 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 5 0,408 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/eia 411/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 u tilities 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 Corpora tion (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



### 39Electric 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, 2011-201 5 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 Corpora tion (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



### 40Electric Power Annual 2010Released: 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)InterconnectionNERC Regional AssesmentArea1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010FRCC 188,598 196,561 200,134 211,116 219,021 220,335 226,544230,115 232,405 226,874 225,966233,034NPCC 277,902 281,518 282,670 286,199 288,791 292,725 303,607294,319 301,766 297,362 285,625294,276Balance of EasternRegion2,147,860 2,210,739 2,203,509 2,301,321 2,255,233 2,313,180 2,385,461 2,361,721 2,432,475 2,406,730 2,293,617 2,456,553ECAR 547,846 545,958 546,167 567,897 545,109 553,236 NA NA NA NA NA NAMAAC 255,741 262,320 263,841 273,907 276,600 283,646 NA NA NA NA NA NAMAIN 243,278 259,608 271,053 279,264 267,068 274,760 NA NA NA NA NA NAMAPP NA NA NA NA NA NA NA NA NA NA NA 30,691MISO NA NA NA NA NA NA NA NA NA NA NA 585,274MRO 152,350 145,981 144,893 150,058 153,918 152,975 216,633222,748 217,602 227,536 213,797 NAPJM NA NA NA NA NA NA NA NA NA NA NA 712,731RFC NA NA NA NA NA NA1,005,226926,279954,700936,201880,377NASERC 768,408 803,211 787,139 835,319 826,964 856,734 962,0541,011,173 1,049,298 1,035,390 997,142870,367SPP 180,237 193,661 190,416 194,876 185,574 191,829 201,548201,521 210,875 207,603 202,301257,491ERCOT TRE 268,622 286,313 278,226 280,269 283,868 289,146 299,225305,672 307,064 312,401 308,278 319,097Western Interconnection WECC 635,503 663,913 638,746 666,696 664,754 682,053 685,624 720,087 739,018 745,691 718,694713,177All 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 3,989,058 3,832,180 4,016,137Notes: • 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. Thehistorical dataseries for these regions have not been adjusted. Instead, the Balance of Eastern Region category was introduced to to providea 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 Interconnection41Electric Power A nnual 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 Pro jected (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/eia 411/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 A reas, 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



### 42Electric 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 Asses sment 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 2 1.3 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 c onstruction, 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 ca pacity 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/eia 411/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 Corpora tion (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 Sourc e: 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



### 43Electric 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 Corpo ration 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 c onstruction, 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 ca pacity 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/eia 411/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



### 44Electric 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 Asses sment 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 c onstruction, 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 ca pacity 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 Corpora tion (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



### 45Electric 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 Corpo ration 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 reliab ility authority and is equal to Internal Demand less Direct Control Load Management and Interruptible Demand. [2] Capacity Resources: Utility and nonu tility-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 capab ility 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/eia 411/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 u tilities 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 Contigious U.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 5 8,415 AC 400-599 1,201 473 - 2,551 8,617 47 - 12,72 9 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 - - - 2,1 37 2,203 DC 600+ - - - - - - - - - DC Total - 1,802 48 66 - - - 2,1 37 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/electr icity/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 avail able 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 All Years 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/eia 411/eia411.html • Circuit miles do not equal physical miles on the ground; the reference terminol ogy 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

48Electric 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 a s the most predominant energy source for at least one of its generators. If all genera tors for a site have the same ener gy source reported as the most pr edominant, that site will be count ed 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 predom inant 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 add ition, 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 bun ker 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 weig hted 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 rat e is reported at full load conditions for electric utilities and independent power producers. • The average heat rates above are weighted by Net Summer Ca pacity. • 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."



### 51Electric Power Annual 2010Released: 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 2001 2000 1999U.S. Total5,770,134 5,028,647 5,612,781 5,411,422 5,502,584 6,092,285 6,998,549 6,979,669 8,754,807 7,555,276 2,345,540 2,039,969Electric Utilities2,353,086 2,364,648 2,483,927 2,504,002 2,605,315 2,760,043 2,725,694 2,610,525 2,620,712 3,045,854 2,250,382 1,949,574Energy-Only Providers3,319,211 2,564,407 3,024,730 2,805,833 2,793,288 3,250,298 4,170,331 4,264,102 6,050,159 4,412,064NANAIPP23,976 27,922 25,431 24,942 26,628 12,201 24,258 37,921 15,80197,357[1]10,622 4,358CHP73,861 71,669 78,693 76,646 77,353 69,744 78,267 67,122 68,135NA 84,536 86,037Sources:U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report." For unregulated entities prior to 2001. Form EIA-860B, "Annual Electric Generator Report - Nonutility," andpredecessor 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 equal sum of components because ofindependent rounding. • The data collection instrument was changed in 2001 to collect data at the corporate level, rather than the plant level. As a result, comparisons with data prior to 2001 and after 2001 should be done withcaution.[1] For 2001, CHP purchases are combined with IPP data above.NA = Not available.R = Revised.52Electric Power Annual 2010Released: 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 2001 2000 1999U.S. Total5,929,211 5,065,031 5,680,733 5,479,394 5,493,473 6,071,659 6,758,975 6,920,954 8,568,678 7,345,319 2,355,154 1,998,090Electric Utilities1,541,554 1,495,636 1,576,976 1,603,179 1,698,389 1,925,710 1,923,440 1,824,030 1,838,901 2,146,689 1,715,582 1,635,614Energy-Only Providers2,946,452 2,240,399 2,718,661 2,476,740 2,446,104 2,867,048 3,756,175 3,906,220 5,757,283 4,386,632NANAIPP1,404,137 1,295,857 1,355,017 1,368,310 1,321,342 1,252,796 1,053,364 1,156,796 943,531811,998[1]611,150 335,122CHP37,068 33,139 30,079 31,165 27,638 26,105 25,996 33,909 28,963NA 28,421 27,354Sources:U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report." For unregulated entities prior to 2001. Form EIA-860B, "Annual Electric Generator Report - Nonutility," andpredecessor 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 instrument was changed in 2001 tocollect data at the corporate level, rather than the plant level. As a result, comparisons with data prior to 2001, and after2001 should be done with caution. • Totals may not equal sum of components because of independentrounding.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 inclu ded 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 re ported under Full-Service Providers. Energy-Only Providers sell energy to end use customers; incumbent utility distribution firms pro vide 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 Oper ations 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 "F ull-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 oth er 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 su m 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.

60Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 7.5. Net Metering and Green Pricing Customers by End Use Sector, 2003 - 2010(Count)Residential Non ResidentialTotalResidential Non ResidentialTotal2003819,57957,547877,1265,8709436,8132004864,79463,539928,33314,1141,71215,8262005871,77470,998942,77219,2441,90221,1462006[1]606,91935,937642,85630,6892,93033,6192007773,39162,260835,65144,8863,94348,8292008918,28464,711982,99564,4005,60970,00920091,058,18565,5931,123,77888,2228,28496,50620101,137,04779,5351,216,582141,84413,997155,841Source: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 than297,600 customers in green pricing programs reverted to sNotes:• Green Pricing programs allow electricity customers the opportunity to purchase electricity generated from renewable resources, thereby encouraging renewable energy develPeriodGreen Pricing Net Metering61Table 8.1. Revenue and Expense Statistics for Major U.S. Investor-Owned Electric Utilities, 1999 through 2010(Million Dollars)Description2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Utility Operating Revenues284,373 276,124 298,962 270,964 275,501 265,652 238,759 230,151 219,609 267,276 233,915 213,090Electric Utility260,113 249,303 266,124 240,864 246,736 234,909 213,012 206,268 200,360 243,982 213,634 197,010Other Utility24,260 26,822 32,838 30,100 28,765 30,743 25,747 23,883 19,250 23,294 20,281 16,081Utility Operating Expenses250,122 244,243 267,263 241,198 245,589 236,786 206,960 201,057 189,062 234,910 210,250 180,467Electric Utility226,845 219,544 236,572 213,076 218,445 207,830 183,121 179,044 171,604 213,458 191,564 165,942Operation159,585 154,925 175,887 153,885 158,893 150,645 131,560 125,436 116,660 161,233 132,607 107,686Production128,808 118,816 140,974 121,700 127,494 120,586 103,871 98,305 90,715 135,791 107,554 82,791Cost of Fuel44,115 40,242 47,337 39,548 37,945 36,106 28,544 26,871 24,149 29,434 32,407 29,605Purchased Power67,284 67,630 84,724 74,112 79,205 77,902 67,126 63,749 58,810 98,020 62,608 42,663Other13,013 10,970 8,937 8,058 10,371 6,599 8,226 7,709 7,776 8,359 12,561 10,551Transmission6,948 6,742 6,950 6,051 6,179 5,664 4,531 3,653 3,560 3,385 2,713 2,480Distribution4,007 3,947 3,997 3,765 3,640 3,502 3,287 3,214 3,117 3,208 3,092 2,959Customer Accounts5,091 5,203 5,286 4,652 4,409 4,229 4,077 4,262 4,168 4,432 4,239 4,190Customer Service4,741 3,857 3,567 2,939 2,536 2,291 2,013 1,902 1,820 1,855 1,826 1,854Sales185178225239240219237238264282405474Administrative and General17,115 15,991 14,718 14,346 14,580 14,130 13,537 13,863 13,018 12,292 12,768 12,950Maintenance14,962 14,092 14,192 13,181 12,838 12,033 11,743 11,340 10,861 11,154 12,064 12,359Depreciation20,930 20,095 19,049 17,936 17,373 17,123 16,322 15,981 16,199 17,476 20,636 20,232Taxes and Other27,646 29,081 26,202 27,000 28,149 26,805 22,190 25,027 26,716 21,765 24,479 23,786Other Utility23,277 24,698 30,692 28,122 27,143 28,956 23,839 22,013 17,457 21,452 18,686 14,525Net 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 32,623Notes:• 2007 financial data does not include information on Entergy Gulf State Louisiana LLC and Entergy Texas Inc. as both were notreported on the FERC Form for that year. • Missing or erroneous respondent data may result in slightimbalances 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."62Electric Power Annual 2010Released: 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 Type2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999OperationNuclear10.50 10 9.89 9.54 9.03 8.26 8.97 9.12 9 8.44 6.03 8.17Fossil Steam4.04 4.23 3.72 3.63 3.57 3.21 3.13 2.74 2.59 2.47 2.17 2.16Hydroelectric[1]5.33 4.88 5.78 5.44 3.76 3.95 3.83 3.47 3.71 4.27 3.52 3.35Gas Turbine and Small2.79 3.05 3.77 3.26 3.51 3.69 4.27 3.5 3.26 3.65 3.93 5.01MaintenanceNuclear6.80 6.34 6.2 5.79 5.69 5.27 5.38 5.23 5.04 5.02 4.96 5.01Fossil Steam3.99 3.96 3.59 3.37 3.19 2.98 2.96 2.72 2.67 2.61 2.42 2.46Hydroelectric[1]3.81 3.5 3.89 3.87 2.7 2.73 2.76 2.32 2.62 2.89 2.22 2.03Gas Turbine and Small2.73 2.58 2.72 2.42 2.16 1.89 2.14 2.26 2.38 3.33 3.26 4.78FuelNuclear6.68 5.35 5.29 4.99 4.85 4.63 4.58 4.6 4.6 4.67 4.9 5.16Fossil Steam27.73 32.3 28.43 23.88 23.09 21.69 18.21 17.29 16.09 18.15 17.73 15.5Hydroelectric[1]-- -- -- -- -- -- -- -- -- -- -- --Gas Turbine and Small43.21 51.93 64.23 58.75 53.89 55.52 45.18 43.89 31.84 43.55 41.76 27.95TotalNuclear23.98 21.69 21.37 20.32 19.57 18.15 18.93 18.95 18.65 18.13 15.89 18.35Fossil Steam35.76 40.48 35.75 30.88 29.85 27.88 24.31 22.75 21.36 23.23 22.32 20.12Hydroelectric[1]9.15 8.38 9.67 9.32 6.46 6.68 6.6 5.79 6.33 7.16 5.74 5.38Gas Turbine and Small48.74 57.55 70.72 64.43 59.56 61.1 51.59 49.66 37.47 50.53 48.94 37.74[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 (equivalent to 1/10 ofone 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 VentyxGlobal EnergyVelocity Suite."63Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 8.3. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (With Generation Facilities), 1999through 2010(Million Dollars)Description2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Operating Revenue - ElectricNANANANANANANA33,90632,77638,02831,84326,767Operating Expenses - ElectricNANANANANANANA29,63728,63832,78926,24421,274Operation Including FuelNANANANANANANA22,64221,73125,92219,57515,386ProductionNANANANANANANA17,94817,17621,76415,74211,923TransmissionNANANANANANANA872858785781732DistributionNANANANANANANA696680605574516Customer AccountsNANANANANANANA582537600507415Customer ServiceNANANANANANANA280315263211160SalesNA NA NA NA NA NA NA 84 74 73 66 49Administrative and GeneralNANANANANANANA2,1802,0901,8321,6951,591MaintenanceNANANANANANANA2,0861,9261,9041,8151,686Depreciation and AmortizationNANANANANANANA3,8443,9074,0093,9193,505Taxes and Tax EquivalentsNANANANANANANA1,0661,074954936697Net Electric Operating IncomeNANANANANANANA4,2684,1385,2385,5985,493NA = 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.64Electric Power Annual2010Released: November 2011Next Update: November 2012Table 8.4. Revenue and Expense Statistics for Major U.S. Publicly Owned Electric Utilities (Without Generation Facilities), 1999 through 2010(Million Dollars)Description20102009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Operating Revenue - ElectricNANANANANANANA12,45411,54610,4179,9049,354Operating Expenses - ElectricNANANANANANANA11,48110,7039,8209,3558,737Operation Including FuelNANANANANANANA10,0959,4398,8648,4247,874ProductionNANANANANANANA8,8658,3117,8637,4867,015TransmissionNANANANANANANA10593616448DistributionNANANANANANANA348320311280261Customer AccountsNANANANANANANA172163164155143CustomerServiceNA NA NA NA NA NA NA 31 39 26 22 22SalesNA NA NA NA NA NA NA 11 10 15 16 14Administrative and GeneralNANANANANANANA562504423402371MaintenanceNANANANANANANA418389304286272Depreciation and AmortizationNANANANANANANA711631405394369Taxes and Tax EquivalentsNANANANANANANA257244247251223Net Electric Operating IncomeNANANANANANANA974843597549617NA = 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.65Electric Power Annual2010Released: November 2011Next Update: November 2012Table 8.5. Revenue and Expense Statistics for U.S. Federally Owned Electric Utilities, 1999 through 2010(Million Dollars)Description2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Operating Revenue - ElectricNANANANANANANA11,79811,47012,45810,68510,186Operating Expenses - ElectricNANANANANANANA8,7638,66510,0138,1397,775Operation Including FuelNANANANANANANA6,4986,4197,3885,8735,412ProductionNANANANANANANA5,1755,2366,2475,4974,890TransmissionNANANANANANANA307244354332349DistributionNA NA NA NA NA NA NA11122CustomerAccountsNA NA NA NA NA NA NA 4 10 16 6 1CustomerServiceNA NA NA NA NA NA NA 63 60 60 48 50SalesNA NA NA NA NA NA NA 20 6 6 10 28Administrative and GeneralNANANANANANANA927862705467528MaintenanceNANANANANANANA600566521488436Depreciation and AmortizationNANANANANANANA1,3351,3511,7901,4711,623Taxes and Tax EquivalentsNANANANANANANA329328315308304Net Electric Operating IncomeNANANANANANANA3,0352,8052,4452,5462,411NA = 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.66Electric Power Annual 2010Released: November 2011Revised: January 2012Next Update: November 2012Table 9.1. Demand-Side Management Actual Peak Load Reductions by Program Category, 1999 through 2010(Megawatts)Item2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Total Actual Peak LoadReduction33,283 31,682 31,735 30,253 27,240 25,710 23,532 22,904 22,936 24,955 22,901 26,455Energy Efficiency20,808 19,766 19,707 17,710 15,959 15,351 14,272 13,581 13,420 13,027 12,873 13,452Load Management12,475 11,916 12,028 12,543 11,281 10,359 9,260 9,323 9,516 11,928 10,027 13,003Notes:• Data presented are reflective of large utilities. • See Technical Notes for the Demand-Side Management definitions located within the Form EIA-861 section. • Totals may not equal sum ofSource:U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."67Electric Power Annual 2010Released: November 2011Revised: January 2012Next Update: November 2012Table 9.2. Demand-Side Management Program Annual Effects by Program Category, 1999 through 2010(MW, MWh)Item2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Annual 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 13,027 52,827 49,691Energy Savings (Thousand MWh)86,926 76,891 74,861 67,134 62,951 58,891 52,662 48,245 52,285 52,946 12,873 13,452Annual 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 11,928 10,027 13,003Potential Peak Load Reductions (MW)25,880 26,178 26,246 23,087 21,270 21,282 20,998 25,290 26,888 27,730 28,496 30,118Energy Savings (Thousand MWh)913 1,015 1,813 1,857 865 1,006 2,047 2,020 1,790 990 875 872Notes:• 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."68Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 9.3. Demand-Side Management Program Incremental Effects by Program Category, 1999 through 2010(MW, MWh)Item2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Incremental Effects – Energy EfficiencyLarge UtilitiesActual Peak Load Reduction (MW)4,736 2,941 5,764 1,649 1,177 1,403 1,521 945 1,054 999 720 695Energy Savings (Thousand MWh)13,560 12,698 10,407 7,426 5,385 5,872 4,522 2,939 3,543 4,402 3,284 3,027Small UtilitiesActual Peak Load Reduction (MW)28 777 567 349 91 302 204 90 49 20 25 22Energy Savings (Thousand MWh)32 209 21 254 9 7 10 8 192 8 8 8Incremental Effects – Load ManagementLarge UtilitiesActual Peak Load Reduction (MW)2,601 2,152 2,923 1,356 1,495 1,009 907 1,084 1,160 1,297 919 1,568Potential Peak Load Reductions (MW)4,987 5,811 6,636 3,342 2,544 2,005 2,622 1,981 2,655 2,448 2,439 6,457Energy Savings (Thousand MWh)49 65 167 132 95 133 2 29 65 79 63 67Small UtilitiesActual Peak Load Reduction (MW)108 75 371 1,036 195 153 242 81 54 45 137 54Potential Peak Load Reductions (MW)246 232 620 1,423 273 218 422 131 76 177 190 84Energy Savings (Thousand MWh)111545442492Notes:• 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."69Electric Power Annual 2010Released: November 2011Revised: January 2012Next Update: November 2012Table 9.4. Demand-Side Management Program Annual Effects by Sector, 1999 through 2010(MW, Thousand MWh)Item2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Actual Peak Load Reductions (MW)Large UtilitiesResidential14,094 12,605 12,910 13,192 10,730 9,432 8,870 9,431 9,137 9,619 9,446 9,976Commercial10,882 11,399 11,097 8,054 7,779 7,926 7,194 6,774 6,839 8,210 6,987 7,777Industrial8,160 7,666 7,602 8,990 8,692 8,343 7,454 6,594 6,500 6,553 6,141 6,360Transportation147 12 126 17 39 9 14 105 NA NA NA NAOtherNA NA NA NA NA NA NA NA 460 573 327 2,342Total33,283 31,682 31,735 30,253 27,240 25,710 23,532 22,904 22,936 24,955 22,901 26,455Potential Peak Load Reductions (MW)Large UtilitiesResidential17,293 15,986 16,831 15,263 13,040 12,097 11,967 12,525 12,072 12,274 12,970 12,812Commercial14,060 14,366 13,850 10,201 10,006 10,214 9,624 8,943 9,298 10,469 9,114 8,868Industrial15,053 15,502 15,103 15,271 14,119 14,260 13,665 17,298 18,321 17,344 18,775 17,237Transportation282 90 169 62 64 62 14 105 NA NA NA NAOtherNA NA NA NA NA NA NA NA 617 670 510 4,653Total46,688 45,944 45,953 40,797 37,229 36,633 35,270 38,871 40,308 40,757 41,369 43,570Energy Savings (Thousand MWh)Large UtilitiesResidential32,436 27,811 26,534 23,688 21,437 19,255 17,763 13,469 15,438 16,027 16,287 16,263Commercial37,659 35,019 34,869 30,725 28,982 28,416 24,624 25,089 24,391 24,217 25,660 23,375Industrial17,655 15,002 15,196 14,470 13,348 12,178 12,273 11,156 11,339 10,487 9,160 8,156Transportation89 76 76 109 50 48 51 551 NA NA NA NAOtherNA NA NA NA NA NA NA NA 2,907 3,206 2,593 2,770Total87,839 77,907 76,674 68,992 63,817 59,897 54,710 50,265 54,075 53,936 53,701 50,563NA = 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 rounding.Source:U.S. Energy Information Administration, Form EIA-861, "Annual Electric Power Industry Report."70Electric 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, "A nnual 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 equ al sum of components because of independent rounding.



### 71Electric Power Annual 2010Released: November 2011Next Update: November 2012Table 9.6. Demand-Side Management Program Energy Savings, 1999 through 2010(Thousand Megawatthours)Item2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 1999Total Energy Savings87,839 77,907 76,674 68,992 63,817 59,897 54,710 50,265 54,075 53,936 53,701 50,563Energy Efficiency86,926 76,891 74,861 67,134 62,951 58,891 52,662 48,245 52,285 52,946 52,827 49,691Load Management913 1,015 1,813 1,857 865 1,006 2,047 2,020 1,790 990 875 872Notes:• Data presented are reflective of large utilities. • Totals may notequal 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 ) t (x ) t (x-) t (x

1 1 2 

#  ̧  ̧ 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 DataAnnual 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 (t 1 

## ) and x (t 2 

## ) denote the quantity at period t 1 

## and subsequent period t 2 

## .

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

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# 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 Reliability First 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 Reliability First 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

cu stomer demand that, in accordance with

con tractual arrangements, can be interrupted at the time of the Regional Council’s seasonal peak by direct control of the System

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# 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 EIA423 2 

## 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

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# 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 wasamended 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 inJanuary 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 thispublication 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

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# 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 formsform 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 ofcapacity 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.

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# 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 thatare 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 t he 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)

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# 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 FormsEIA-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 allother 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

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# 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. Theaverage 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 56Nonbiogenic 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 75Nonbiogenic 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 (CO 2 

## ) from electric generating plants for 1989 through 2009, as well as the estimated emissions of sulfur dioxide (SO 2 

## ) and nitrogen oxides (NO x 

## ) 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 SO 2 

## and NO x 

## emissions for all plants are made by applying an emissions factor to fuelconsumption 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 NO x 

## and SO 2 

## emissions. As discussed below,

83

# 11 physical quantities are converted to millions of Btus for calculating CO 2 

## emissions. For some fuels, the calculation of SO 2 

## 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 SO 2 

## emission factors used for this report.
In the case of SO 2 

## and NO x 

## 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, NO x 

## 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 SO 2 

## and NO x 

## , 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 SO 2 

## is the fluidized bed boiler, in which the sulfur removal process is integral with the operation of the boiler. The SO 2 

## emission factors shown in Table A1 for fluidized bed boilers already account for 90 percent removal of SO 2 

## since, in effect, the plant has no uncontrolled emissions of this pollutant. Although SO 2 

## and NO x 

## 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 CO 2 

## are incomplete and are not used in this report.) The CEMS data account for the bulk of SO 2 

## and NO x 

## emissions from the electric power industry. For those plants for which CEMS data are available, the EIA estimates of SO 2 

## and NO x 

## 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.
CO 2 

## Emissions: CO 2 

## 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 CO 2 

## emissions, the fuel-specific emission factor from Table A3 is multiplied by the fuel consumption in MMBtu. The estimation procedure calculates uncontrolled CO 2 

## emissions. CO 2 

## control technologies are currently in the early stages of research and there are no commercial systems installed. Therefore, no estimates of controlled CO 2 

## emissions are made.
SO 2 

## and NO x 

## Emissions: To comply with environmental regulations controlling SO 2 

## emissions, many coal-fired generating plants have installed flue gas desulfurization (FGD) units. Similarly, NO x 

## control regulations require many fossil-fueled plants to install low-NO x 

## burners, selective catalytic reduction systems, or other technologies to reduce emissions. It is common for power plants to employ two or even three NO x 

## control technologies; accordingly, the NO x 

## 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 FormEIA-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 fuels 7 

## 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 SO 2 

## and NO x 

## 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 datawere collected on the Forms EIA-860 and EIA923. For SO 2 

## , the reported efficiency of the plant’s FGD units is used to convert uncontrolled to controlled emission estimates. For NO x 

## , the reduction percentages shown in Table A4 are applied to the uncontrolled estimates.

84

# 12 x For plants and prime movers not reported on thehistorical 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, includingwhether 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 SO 2 

## or NO x 

## 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 NAICS 9 

## 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 , 41 st 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).



### 87Electric Power Annual 2010Released: November 2011Next Update: November 2012Table A1. Sulfur Dioxide Uncontrolled Emission Factors(Units and Factors)Emissions Units(Lbs = pounds,MMCF = millioncubic feet,MG = thousandgallons)Agricultural Byproducts (AB) Source: 1 Lbs per ton0.080.010.080.080.080.08NANABlast Furnace Gas (BFG)Sources: 1(including footnote7 within source); 2,Table 1.4-2(including footnoted within source)Lbs per MMCF0.60.060.60.60.60.60.60.6Bituminous Coal (BIT)*Source: 2, Table1.1-3Lbs per ton383.838383838NANABlack Liquor (BLQ)Source: 1 Lbs per ton **70.77 7 7 7NA NADistillate Fuel Oil (DFO)*Source: 2, Table3.1-2a, 3.4-1 & 1.3-1Lbs per MG15715.7157157157157140140Jet Fuel (JF)*Assumed to haveemissions similar toDFO.Lbs per MG15715.7157157157157140140Kerosene (KER)*Assumed to haveemissions similar toDFO.Lbs per MG15715.7157157157157140140Landfill Gas (LFG)Sources: 1(including footnote7 within source); 2,Table 1.4-2(including footnoted within source)Lbs per MMCF0.60.060.60.60.60.60.60.6Lignite Coal (LIG)*Source: 2, Table1.7-1Lbs per ton30330303030NANATangential BoilerAll Other BoilerTypesCombustionTurbineInternalCombustionEngineFuel, Code, Source and Emission unitsCombustion System Type/Firing ConfigurationFuel And EIA Fuel CodeSource and Tables(As appropriate)Cyclone BoilerFluidized BedBoilerOpposed FiringBoilerSpreader StokerBoiler88Municipal Solid Waste (MSW) Source: 1 Lbs per ton1.70.171.71.71.71.7NANANatural Gas (NG)Sources: 1(including footnote7 within source); 2,Table 1.4-2(including footnoted within source)Lbs per MMCF0.60.060.60.60.60.60.60.6Other Biomass Gas (OBG)Sources: 1(including footnote7 within source); 2,Table 1.4-2(including footnoted within source)Lbs per MMCF0.60.060.60.60.60.60.60.6Other Biomass Liquids (OBL)* Source: 1(includingfootnotes 3 and 16withinsource)Lbs per MG15715.7157157157157140140Other Biomass Solids (OBS) Source: 1(including footnote11 within source)Lbs per ton0.230.020.230.230.230.23NANAOther Gases (OG)Source: 1(including footnote7 within source)Lbs per MMCF0.60.060.60.60.60.60.60.6Other (OTH)Assumed to haveemissions similar toNG.Lbs per MMCF0.60.060.60.60.60.60.60.6Petroleum Coke (PC)*Source: 1 Lbs per ton393.939393939NANAPropane Gas (PG)Sources: 1(including footnote7 within source); 2,Table 1.4-2(including footnoted within source)Lbs per MMCF0.60.060.60.60.60.60.60.6Residual Fuel Oil (RFO)*Source: 2, Table1.3-1Lbs per MG15715.7157157157157NANASynthetic Coal (SC)*Assumed to havethe emissionssimilar toBituminous Coal.Lbs per ton383.838383838NANASludge Waste (SLW)Source: 1(including footnote11 within source)Lbs per ton **2.80.282.82.82.82.8NANA89Subbituminous Coal (SUB)* Source: 2, Table1.1-3Lbs per ton353.535383535NANATire-Derived Fuel (TDF)*Source: 1(including footnote13 within source)Lbs per ton383.838383838NANAWaste Coal (WC)*Source: 1(including footnote20 within source)Lbs per ton30330303030NANAWood Waste Liquids (WDL)* Source: 1(includingfootnotes 3 and 16withinsource)Lbs per MG15715.7157157157157140140Wood Waste Solids (WDS)Source: 1 Lbs per ton0.290.080.290.080.290.29NANAWaste Oil (WO)*Source: 2, Table1.11-2Lbs per MG14714.7147147147147NANA** 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.gov/ttn/chief/ap42/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 donot require the sulfur percentage in the calculation). Note that EIA data do notprovide 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 (availableat: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. Environmental Protection Agency, EmissionFactor and Inventory Group (D205-01), Emissions, Monitoring and Analysis Division, Research Triangle Park; and90Electric Power Annual 2010Released: November 2011Next Update: November 2012Table A2. Nitrogen Oxides Uncontrolled Emission Factors(Units and Factors)Emissions Units(Lbs = pounds,MMCF = millioncubic feet,MG = thousandgallons)Agricultural Byproducts (AB) Source: 1 Lbs per ton1.21.21.21.21.21.2NANABlast Furnace Gas (BFG)Sources: 1(including footnote7 within source);EIA estimatesLbs per MMCF15.415.415.415.415.415.430.4256.55Bituminous Coal (BIT)Source: 2, Table1.1-3Lbs per ton33512 [31]1110.0 [14.0] 12.0 [31.0]NANABlack Liquor (BLQ)Source: 1 Lbs per ton **1.51.51.51.51.51.5NANADistillate Fuel Oil (DFO)Source: 2, Tables3.4-1 & 1.3-1Lbs per MG242424242424122443.8Jet Fuel (JF)Source: 2, Tables3.1-2a, 3.4-1 & 1.3-1Lbs per MG242424242424118432Kerosene (KER)Source: 2, Tables3.1-2a, 3.4-1 & 1.3-1Lbs per MG242424242424118432Landfill Gas (LFG)Sources: 1(including footnote7 within source);EIA estimatesLbs per MMCF72.4472.4472.4472.4472.4472.441441215.22Lignite Coal (LIG)Source: 2, Table1.7-1Lbs per ton153.66.35.87.16.3NANAMunicipalSolidWaste(MSW) Source:1 Lbsperton5 5 5 5 5 5NA NANatural Gas (NG)Source: 2, Tables1.4-1, 3.1-1, and3.4-1Lbs per MMCF2802802802801702803282768Fuel And EIA Fuel CodeSource and Tables(As appropriate)Cyclone BoilerFluidized BedBoilerFuel, Code, Source, and Emission UnitsCombustion System Type/Firing ConfigurationFactors for Wet-Bottom Boilers are in Brackets; All Other Boiler Factors are for Dry-BottomCombustionTurbineInternalCombustionEngineOpposed FiringBoilerSpreader StokerBoiler Tangential BoilerAll Other BoilerTypes91Other Biomass Gas (OBG)Sources: 1(including footnote7 within source);EIA estimatesLbs per MMCF 112.83112.83112.83112.83112.83112.83313.62646.48Other Biomass Liquids (OBL) Source: 1(including footnote3 within source)Lbs per MG191919191919NANAOther Biomass Solids (OBS) Source: 1(including footnote11 within source)Lbsperton 2 2 2 2 2 2NA NAOther Gases (OG)Sources: 1(including footnote7 within source);EIA estimatesLbs per MMCF 152.82152.82152.82152.82152.82152.82263.822226.41Other (OTH)Assumed to haveemissions similar tonatural gas.Lbs per MMCF2802802802801702803282768Petroleum Coke (PC)Source: 1(including footnote8 within source)Lbs per ton21521212121NANAPropane Gas (PG)Sources: 3; EIAestimatesLbs per MMCF215215215215215215330.752791.22Residual Fuel Oil (RFO)Source: 2, Table1.3-1Lbs per MG474747473247NANASynthetic Coal (SC)Assumed to haveemissions similar toBituminous Coal.Lbs per ton33512 [31]1110.0 [14.0] 12.0 [31.0]NANASludge Waste (SLW)Source: 1(including footnote11 within source)Lbsperton**5 5 5 5 5 5 NA NASubbituminous Coal (SUB)Source: 2, Table1.1-3Lbs per ton1757.4 [24]8.87.27.4 [24.0]NANATire-Derived Fuel (TDF)Source: 1(including footnote13 within source)Lbs per ton33512 [31]1110.0 [14.0] 12.0 [31.0]NANAWaste Coal (WC)Source: 1(including footnote20 within source)Lbs per ton153.66.35.87.16.3NANAWood Waste Liquids (WDL) Source: 1(including footnote16 within source)Lbs per MG5.435.435.435.435.435.43NANAWood Waste Solids (WDS)Source: 1 Lbs per ton2.5122.511.52.512.51NANA92Waste Oil (WO)Source: 2, Table1.11-2Lbs per MG191919191919NANANote: ** Although Sludge Waste and Black Liquor consist substantially of liquids, these fuels are measured and reported to EIAin 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.gov/ttn/chief/ap42/; and3. U.S. Environmental Protection Agency, Factor Information Retrieval (FIRE) Database, Version 6.25; available at: http://www.epa.gov/ttn/chief/software/fire/index.html1. Eastern Research Group, Inc. and E.H. Pechan & Associates, Inc.,Documentation for the 2002 Electric Generating Unit National Emissions Inventory, Table 6, September 2004. Prepared for the U.S. Environmental Protection Agency, EmissionFactor 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 CO 2 

# per Million Btu)

Factor (Pounds of CO 2 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 Forecastin g 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 p er barrel ) 210

Note: *** CO 2 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 Ga ses 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)



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### 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 NO x 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 NO x Burners Slagging SC 20

1. Starting with 1995 data, reduction factors for advanced overfire air, low NO x burners, and overfire air were reduced by 10 percent. Sources: Energy Information Administration, Form EIA-860, "A nnual Electric Generator Report;" Babcock and Wilcox, Steam 41st Edition, 2005. 

### EIA-Code(s)

SR and LN 90

SN and LN 50



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### 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 M illion) Watts Gigawatt (GW) 1,000,000,000 (One B illion) Watts Terawatt (TW) 1,000,000,000,000 (One Tr illion) Watts

Gigawatt 1,000,000 (One M illion) Kilowatts Thousand Gigawatts 1,000,000,000 (One B illion) Kilowatts

Kilowatthours (kWh) 1,000 (One Thousand) Watthours Megawatthours (MWh) 1,000,000 (One M illion) Watthours Gigawatthours (GWh) 1,000,000,000 (One B illion) Watthours Terawatthours (TWh) 1,000,000,000,000 (One Tr illion) Watthours

Gigawatthours 1,000,000 (One M illion) Kilowatthours Thousand Gigawatthours 1,000,000,000(One B illion) 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



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