1

EPA v5.13 Base Case Documentation Supplement to Support 

EPA’s Proposed Carbon Pollution Guidelines for Existing Electric Generating Units 

Overview 

This supplement includes details on several modeling assumptions used as part of EPA’s 

analysis of the Clean Power Plan (Carbon Pollution Guidelines for Existing Electric Generating 

Units) using the EPA v5.13 Base Case using Integrated Planning Model (IPM). The 

modifications include an enhanced capability for existing coal steam-fired units to adopt 

improvements to their heat rates and a modified calculation for stack emissions associated with 

biomass combustion. This supplement also includes more detail on the specific modeling 

parameters that were used to reflect the state goals that are part of the proposed rule. 

Heat Rate Improvements (HRI) 

A new capability has been introduced to offer coal steam model plants a heat rate 

improvement option that is fully integrated into the IPM modeling framework. This capability 

enables IPM to solve for the optimal deployment of heat rate improvement (HRI) technologies 

on a plant-by-plant basis in the regulatory scenarios analyzed. 

EPA has conducted a thorough technical assessment of the engineering and cost 

parameters of potential heat rate improvements that reduce auxiliary power and fuel consumption 

so as to increase net electrical output per unit of heat input (i.e., heat rate).1

 EPA has relied upon 

an analysis of historical data, as well as several recent studies that have examined opportunities 

for efficiency improvements as a means of reducing heat rate and emissions from coal-fired 

power plants (see list of technical reports and studies below). 

The EPA’s analysis finds that on average, coal steam generation can realize a 6% heat 

rate improvement through two types of changes: best practices that have the potential to improve 

heat rate by 4%, and equipment upgrades that have the potential to improve heat rate by 2%. 

This assumption of 6% heat rate improvement is represented in the heat rate improvement 

retrofit option offered in modeling scenarios analyzing the proposed regulatory option (Option 

1). An alternative level of 4% heat rate improvement is represented in the heat rate improvement 

retrofit option offered in modeling scenarios analyzing the regulatory alternative (Option 2). 

Most of the methods that can be applied to achieve a sustained HRI on a coal-steam EGU 

will entail a capital cost. The modeling assumes $100/kW as a combined HRI capital cost to 

achieve the aforementioned HRI levels (the same cost is used for both Option 1 and Option 2). 

Biomass Emissions Calculation 

Biomass is included in the model as a fuel for existing dedicated biomass power plants 

and potential (new) biomass direct fired boilers. It is also included in the model as a co-firing 

                                                            

1

 See chapter 2 of the Greenhouse Gas Abatement Measures Technical Support Document (TSD) in support of the 

Proposed Carbon Pollution Guidelines for Existing Electric Generating Units 
2

fuel available to all coal-fired power plants. EPA Base Case v.5.13 uses biomass supply curves 

based on those in AEO 2013. In past EPA modeling applications of IPM, biomass was not 

assigned a CO2 emission factor associated with its combustion, unlike other fuels that emit CO2

when combusted such as coal, natural gas, oil, and waste fuels. 

In all the scenarios analyzed for the Proposed Clean Power Plan, including both the base 

case and the illustrative compliance scenarios, an emission factor of 195 lbs/MMBtu (88.45 

kg/MMBtu) has been assigned to combustion from biomass fuels (including dedicated biomass 

facilities and coal steam-fired sources that are co-firing biomass, as determined by the model).2 

This factor reflects the average CO2 emissions that result from the combustion of biogenic 

feedstocks, and does not include any evaluation of stack biogenic CO2 emissions relative to the 

net landscape and process-related carbon fluxes associated with the production and use of the 

biogenic feedstocks combusted. 

Modeling of State Guidelines

In the illustrative compliance scenarios analyzed, the average emissions rate of the source 

types included in the calculation of the state goals must be, on average, less than or equal to the 

proposed goals over the entire compliance period. That is, the CO2 emission rate constraints 

imposed to represent the state goals are applied only to the sources whose generation was 

originally included in the calculation of the state goals being analyzed. Electricity savings (in 

megawatt-hours avoided) from assumed improvements in demand-side energy efficiency are also 

incorporated, in the same manner as zero-emitting generation is incorporated, into the average 

emission rates that must not exceed the CO2 emission rate constraints. 

Generation and emissions from the following sources are included in the average 

emissions rates that are evaluated against the state goals for compliance: 

 Existing IGCC and fossil steam boilers with nameplate capacity greater than 25 

MW 

 Existing NGCC units 

 Simple cycle combustion turbines with nameplate capacity greater than 25 MW, 

capacity factor greater than a 33%, and 2012 (historical) generation greater than 

219,000 MWh 

 New and existing non-hydro renewable capacity3

 At risk and under construction nuclear.4 

                                                            

2

 Taken from EIA - Accounting for carbon dioxide emissions from biomass energy combustion (Annual Energy 

Outlook 2010 Issues in Focus), 2010. http://www.eia.gov/oiaf/archive/aeo10/carbon_dioxide.html. 3

 CO2 emissions from landfill gas and municipal solid waste (MSW) are not included in the average emissions rate 

subject to the CO2 constraints, but they are included in projections of total emissions. CO2 emissions from 

biomass consumption are included in the average emissions rate subject to the CO2 constraints. 4

 All generation from under-construction units and 7.97% of generation from existing units is included in the 

average emissions rate evaluated for compliance. Because this modeling was conducted before the associated 

rule was issued, the amount of at-risk generation quantified and included in this modeling is slightly higher than 

the amount ultimately quantified and included in state goals in the proposed Clean Power Plan. For more 
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 Demand-side energy efficiency savings 

 Table 1 presents the absolute electricity savings in each model run-year for each state 

from assumed demand-side energy efficiency improvements that are included in the analyses 

conducted for the proposed Clean Power Plan. The quantification of these data is explained in 

the Greenhouse Gas Abatement Measures TSD for the proposed Clean Power Plan. Table 1 also 

reflects the proportion of those electricity savings that is incorporated into the average emissions 

rate subject to the CO2 constraints modeled. The preamble for the proposed Clean Power Plan 

explains why only a subset of the absolute electricity savings quantified for certain states (whose 

historic data showed a net importation of electricity) is incorporated into the computation of the 

relevant state goal and, correspondingly, incorporated into the average emission rate in these 

modeled scenarios that is subject to the CO2 constraint representing that state goal. 

Table 1. Demand-Side Energy Efficiency Savings Included in Emission Rate Calculation in 

Option 1 Modeled Scenarios (GWh) 

State 2020 2025 2030 2040 2050 

Alabama 1,350 6,472 11,108 15,149 16,547 

Arizona 4,782 9,243 12,162 14,301 16,241 

Arkansas 829 3,663 6,100 8,094 8,714 

California 11,434 22,845 30,030 34,268 37,272 

Colorado 2,387 5,638 7,812 9,454 10,584 

Connecticut 1,495 3,058 3,974 4,287 4,353 

Delaware 71 379 663 882 916 

District Of Columbia 0 0 0 0 0 

Florida 5,135 18,896 29,906 39,373 44,029 

Georgia 2,526 10,150 16,490 21,811 23,837 

Idaho 543 1,305 1,803 2,141 2,334 

Illinois 6,943 15,024 19,926 22,095 22,925 

Indiana 3,727 10,008 14,054 16,235 16,795 

Iowa 2,413 5,006 6,589 7,337 7,763 

Kansas 557 2,840 4,920 6,549 6,933 

Kentucky 1,929 7,325 11,643 15,057 16,154 

Louisiana 1,083 5,831 10,327 14,163 15,246 

Maine 673 1,260 1,596 1,691 1,719 

Maryland 1,911 4,245 5,684 6,390 6,683 

Massachusetts 2,114 4,512 5,932 6,451 6,546 

Michigan 5,411 11,276 14,778 16,159 16,686 

Minnesota 3,305 6,705 8,770 9,724 10,291 

Mississippi 774 3,618 6,138 8,227 8,857 

Missouri 1,441 6,169 10,087 12,905 13,487 

Montana 555 1,454 2,056 2,481 2,701 

Nebraska 764 2,634 4,014 4,945 5,198 

                                                            

information on quantification of at-risk nuclear generation, please see the Greenhouse Gas Abatement Measures 

TSD. 
4

Nevada 1,224 3,505 5,083 6,237 6,781 

New Hampshire 329 954 1,365 1,577 1,593 

New Jersey 856 4,286 7,372 9,722 10,096 

New Mexico 867 2,413 3,501 4,395 4,969 

New York 6,903 14,763 19,425 21,148 21,452 

North Carolina 3,264 10,822 16,512 21,134 23,339 

North Dakota 230 1,073 1,806 2,359 2,476 

Ohio 6,531 14,587 19,504 21,755 22,562 

Oklahoma 1,280 4,952 7,920 10,278 11,102 

Oregon 2,603 5,424 7,232 8,379 9,147 

Pennsylvania 7,601 15,704 20,627 22,878 23,950 

Rhode Island 322 752 1,011 1,118 1,133 

South Carolina 2,095 7,047 10,800 13,861 15,306 

South Dakota 188 796 1,300 1,669 1,753 

Tennessee 1,860 6,435 9,891 12,530 13,450 

Texas 7,345 29,206 47,140 61,549 66,619 

Utah 1,286 3,202 4,461 5,327 5,803 

Vermont 0 0 0 0 0 

Virginia 956 4,914 8,633 11,981 13,208 

Washington 4,687 10,419 14,131 16,565 18,068 

West Virginia 603 2,381 3,792 4,757 4,902 

Wisconsin 3,143 6,477 8,466 9,257 9,563 

Wyoming 324 1,382 2,284 3,040 3,295 

Table 2. Demand-Side Energy Efficiency Savings Included in Emission Rate Calculation in 

Option 2 Modeled Scenarios (GWh) 

State 2020 2025 2030 2040 2050 

Alabama 1,069 4,753 7,809 10,490 11,504 

Arizona 3,212 6,278 8,340 9,927 11,282 

Arkansas 675 2,707 4,303 5,606 6,060 

California 8,211 15,860 20,768 23,797 25,922 

Colorado 2,022 4,103 5,500 6,550 7,355 

Connecticut 1,145 2,168 2,773 2,980 3,033 

Delaware 53 276 464 612 638 

District Of Columbia 108 555 935 1,232 1,285 

Florida 4,425 14,118 21,217 27,246 30,592 

Georgia 2,122 7,543 11,665 15,100 16,572 

Idaho 467 953 1,272 1,484 1,623 

Illinois 5,596 10,813 13,984 15,343 15,963 

Indiana 3,375 7,442 9,991 11,255 11,694 

Iowa 1,860 3,556 4,599 5,096 5,403 

Kansas 427 2,074 3,452 4,539 4,823 
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Kentucky 1,644 5,464 8,255 10,426 11,236 

Louisiana 813 4,242 7,230 9,811 10,603 

Maine 452 856 1,095 1,177 1,198 

Maryland 1,577 3,076 3,999 4,435 4,652 

Massachusetts 1,692 3,242 4,161 4,482 4,561 

Michigan 4,232 8,048 10,338 11,227 11,621 

Minnesota 2,466 4,713 6,097 6,756 7,162 

Mississippi 617 2,662 4,320 5,699 6,159 

Missouri 1,181 4,566 7,125 8,945 9,387 

Montana 496 1,074 1,457 1,719 1,878 

Nebraska 666 1,966 2,851 3,426 3,618 

Nevada 1,108 2,605 3,608 4,318 4,715 

New Hampshire 297 712 972 1,093 1,110 

New Jersey 660 3,134 5,176 6,739 7,028 

New Mexico 786 1,791 2,483 3,041 3,452 

New York 5,535 10,614 13,631 14,692 14,947 

North Carolina 2,879 8,081 11,724 14,624 16,222 

North Dakota 183 789 1,271 1,635 1,723 

Ohio 5,434 10,594 13,738 15,102 15,710 

Oklahoma 1,086 3,689 5,611 7,117 7,720 

Oregon 1,982 3,835 5,036 5,815 6,361 

Pennsylvania 5,834 11,140 14,391 15,892 16,673 

Rhode Island 276 550 715 776 789 

South Carolina 1,842 5,259 7,665 9,592 10,639 

South Dakota 154 589 918 1,157 1,220 

Tennessee 1,623 4,797 7,018 8,674 9,356 

Texas 6,182 21,720 33,366 42,621 46,325 

Utah 1,132 2,351 3,153 3,691 4,035 

Vermont 216 409 523 562 572 

Virginia 736 3,589 6,053 8,296 9,180 

Washington 3,814 7,510 9,915 11,487 12,565 

West Virginia 507 1,771 2,687 3,297 3,413 

Wisconsin 2,418 4,600 5,910 6,432 6,660 

Wyoming 268 1,023 1,613 2,105 2,291 

All compliance scenarios modeled include an assumption that affected sources are able to 

meet state goals collectively, by averaging all of their emissions relative to all of their 

generation. This approach enables some sources to emit at rates higher than the relevant goal, as 

long as there is corresponding generation coming from sources that emit at a lower rate such that 

the goal (in lbs/MWh) is met across all affected sources collectively. 
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The illustrative compliance scenarios also assume that state plans allow for intertemporal 

averaging in the initial compliance periods for both Option 1 and Option 2. That is, for the initial 

compliance period for which the “interim” state goal is applied, the average emissions rate at 

affected sources must be less than or equal to the applicable state goal, on average, over the 

entire compliance period, but not in any particular year. The initial compliance period for Option 

1 is 2020 to 2029, and for Option 2 it is 2020 to 2024. After the initial compliance period, the 

average emission rate of the affected sources in each year must be less than or equal to the 

“final” state goal in each model run-year thereafter. 

The intertemporal flexibility described above for the initial compliance periods is 

represented in these modeling scenarios by a combination of: 

 an endogenous “banking” behavior, whereby the model may choose to reduce 

emission rates below the interim goal levels in earlier years to offset exceedances 

of the interim goals in later years of the initial compliance period5; and 

 an exogenously assumed “borrowing” pattern, whereby states are assumed to 

exceed the interim goal in earlier years while offsetting those exceedances with 

additional emission rate reductions below the interim goal levels in later years of 

the initial compliance period. 

The exogenously assumed borrowing pattern is represented by imposing intermediate 

CO2 emission rate constraints in each run-year of the initial compliance period that are consistent 

with the annual values used to calculate the interim state goals for the relevant regulatory option. 

Those annual values are reported in the Goal Computation TSD, and Tables 3 through 5 below 

show the CO2 intermediate CO2 emission rate constraints derived from those values and imposed 

for each state in these modeling scenarios. 

For combined heat and power (CHP) units that are covered under the rule, the emissions 

and energy output associated with the useful thermal output not used for electricity production 

are included in the state goal and would be reported under the proposed Clean Power Plan’s 

reporting guidelines if the unit meets the rule’s applicability criteria. The emissions and energy 

output associated with the useful thermal output are explained in the Goal Computation TSD. 

The state goals, as shown in the proposed rule and Tables 2 through 4 below, reflect total 

emissions divided by total net energy output (i.e., net electricity generation + useful thermal 

output). For purposes of IPM modeling, state goals are adjusted by removing non-electric useful 

thermal output (which is not simulated in IPM) from the denominator in an amount based on the 

unit-level 2012 electric generation and energy output data 

The proposed state goals are shown in Table 3. Table 4 shows the corresponding, CO2

emission rates that have been adjusted to exclude useful (non-electric) thermal output that is 

captured in the state goals but is not simulated in IPM at combined heat and power (CHP) units. 

Table 5 shows the CO2 emission rate constraints that were modeled in IPM to inform the 

illustrative compliance scenarios that are the basis of the costs and benefits analysis found in the 

                                                            

5

 Banking is not allowed in the modeling to contribute to compliance with the final state goals imposed beyond the 

initial compliance period. In other words, the model must demonstrate full compliance with the interim state 

goals in the initial compliance periods independently from demonstrating compliance with the final state goals in 

subsequent years. 
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RIA. The rates in Table 5 differ slightly from the proposed state goals because they have been 

adjusted to exclude useful (non-electric) thermal output that is captured in the state goals but is 

not simulated in IPM at combined heat and power (CHP) units. These rates also reflect minor 

adjustments to the proposal’s computations of state goals that were made after this modeling was 

conducted. 

Table 3. Proposed State Goals, Interim and Final (Adjusted MWh-Weighted-Average 

Pounds of CO2 Per Net MWh from Affected Generation Included in State Goals) for 

Options 1 & 2

STATE6

OPTION 1 OPTION 2 

Interim Goal 

(2020-2029) 

Final Goal 

(2030 Forward) 

Interim Goal 

(2020-2024) 

Final Goal 

(2025 Forward) 

ALABAMA 1,147 1,059 1,270 1,237 

ALASKA 1,097 1,003 1,170 1,131 

ARIZONA * 735 702 779 763 

ARKANSAS 968 910 1,083 1,058 

CALIFORNIA 556 537 582 571 

COLORADO 1,159 1,108 1,265 1,227 

CONNECTICUT 597 540 651 627 

DELAWARE 913 841 1,007 983 

FLORIDA 794 740 907 884 

GEORGIA 891 834 997 964 

HAWAII 1,378 1,306 1,446 1,417 

IDAHO 244 228 261 254 

ILLINOIS 1,366 1,271 1,501 1,457 

INDIANA 1,607 1,531 1,715 1,683 

IOWA 1,341 1,301 1,436 1,417 

KANSAS 1,578 1,499 1,678 1,625 

KENTUCKY 1,844 1,763 1,951 1,918 

LOUISIANA 948 883 1,052 1,025 

MAINE 393 378 418 410 

MARYLAND 1,347 1,187 1,518 1,440 

MASSACHUSETTS 655 576 715 683 

MICHIGAN 1,227 1,161 1,349 1,319 

MINNESOTA 911 873 1,018 999 

MISSISSIPPI 732 692 765 743 

MISSOURI 1,621 1,544 1,726 1,694 

MONTANA 1,882 1,771 2,007 1,960 

NEBRASKA 1,596 1,479 1,721 1,671 

NEVADA 697 647 734 713 

                                                            

6

 The EPA has not developed goals for Vermont and the District of Columbia because current information indicates 

those jurisdictions have no affected EGUs. Also, as noted above, EPA is not proposing goals for tribes or U.S. 

territories at this time. Alaska and Hawaii also have state goals, but they are not modeled in IPM. 
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NEW HAMPSHIRE 546 486 598 557 

NEW JERSEY 647 531 722 676 

NEW MEXICO * 1,107 1,048 1,214 1,176 

NEW YORK 635 549 736 697 

NORTH CAROLINA 1,077 992 1,199 1,156 

NORTH DAKOTA 1,817 1,783 1,882 1,870 

OHIO 1,452 1,338 1,588 1,545 

OKLAHOMA 931 895 1,019 986 

OREGON 407 372 450 420 

PENNSYLVANIA 1,179 1,052 1,316 1,270 

RHODE ISLAND 822 782 855 840 

SOUTH CAROLINA 840 772 930 897 

SOUTH DAKOTA 800 741 888 861 

TENNESSEE 1,254 1,163 1,363 1,326 

TEXAS 853 791 957 924 

UTAH * 1,378 1,322 1,478 1,453 

VIRGINIA 884 810 1,016 962 

WASHINGTON 264 215 312 284 

WEST VIRGINIA 1,748 1,620 1,858 1,817 

WISCONSIN 1,281 1,203 1,417 1,380 

WYOMING 1,808 1,714 1,907 1,869 

* Excludes EGUs located in Indian country. 

Table 4. Adjusted CO2 Emission Rates Excluding Useful Thermal Output 

 OPTION 1 OPTION 2 

STATE 2020 2025 2030-2050 2020 2025 

ALABAMA 1,228 1,138 1,059 1,301 1,237 

ARIZONA * 778 728 703 797 763 

ARKANSAS 1,089 1,014 960 1,165 1,113 

CALIFORNIA 627 581 567 638 606 

COLORADO 1,247 1,138 1,111 1,307 1,229 

CONNECTICUT 663 589 541 677 628 

DELAWARE 973 908 841 1,029 983 

FLORIDA 851 786 739 933 885 

GEORGIA 967 877 835 1,030 965 

IDAHO 266 239 228 270 254 

ILLINOIS 1,504 1,365 1,287 1,568 1,475 

INDIANA 1,708 1,599 1,539 1,759 1,691 

IOWA 1,398 1,331 1,301 1,457 1,417 

KANSAS 1,707 1,554 1,499 1,747 1,625 

KENTUCKY 1,934 1,829 1,763 1,984 1,918 

LOUISIANA 1,174 1,080 1,011 1,233 1,169 
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MAINE 415 389 378 426 410 

MARYLAND 1,544 1,322 1,187 1,597 1,441 

MASSACHUSETTS 739 645 576 749 683 

MICHIGAN 1,410 1,301 1,242 1,482 1,411 

MINNESOTA 972 907 879 1,046 1,005 

MISSISSIPPI 783 721 692 783 736 

MISSOURI 1,705 1,607 1,544 1,757 1,694 

MONTANA 2,037 1,888 1,793 2,087 1,987 

NEBRASKA 1,724 1,577 1,479 1,771 1,671 

NEVADA 759 693 652 762 718 

NEW HAMPSHIRE 637 526 486 639 557 

NEW JERSEY 803 661 548 808 708 

NEW MEXICO * 1,197 1,087 1,048 1,253 1,176 

NEW YORK 763 648 570 809 725 

NORTH CAROLINA 1,183 1,060 992 1,243 1,158 

NORTH DAKOTA 1,852 1,811 1,783 1,894 1,870 

OHIO 1,573 1,441 1,340 1,634 1,547 

OKLAHOMA 996 916 896 1,056 986 

OREGON 475 391 375 485 423 

PENNSYLVANIA 1,337 1,203 1,080 1,403 1,307 

RHODE ISLAND 867 815 782 871 840 

SOUTH CAROLINA 921 829 772 962 898 

SOUTH DAKOTA 870 787 741 914 861 

TENNESSEE 1,353 1,239 1,163 1,402 1,326 

TEXAS 1,049 941 881 1,108 1,027 

UTAH * 1,446 1,366 1,322 1,503 1,453 

VIRGINIA 990 852 806 1,074 968 

WASHINGTON 381 285 241 394 322 

WEST VIRGINIA 1,860 1,748 1,624 1,902 1,823 

WISCONSIN 1,382 1,271 1,208 1,462 1,386 

WYOMING 1,899 1,798 1,714 1,944 1,896 

* Excludes EGUs located in Indian country. 

Table 5. Modeled CO2 Emission Rate Constraints (Adjusted MWh-Weighted-Average 

Pounds of CO2 Per Net MWh from Affected Generation Included in State Goals) for 

Options 1 & 2 

 OPTION 1 OPTION 2 

STATE 2020 2025 2030 

forward 

2020 2025 

forward 

ALABAMA 1,196 1,105 1,024 1,274 1,208 

ARIZONA 767 716 691 785 751 
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ARKANSAS 1,077 1,003 950 1,153 1,101 

CALIFORNIA 618 573 558 630 599 

COLORADO 1,254 1,136 1,112 1,317 1,232 

CONNECTICUT 651 580 533 664 617 

DELAWARE 985 917 848 1,058 1,010 

FLORIDA 811 741 692 818 771 

GEORGIA 962 869 826 1,025 958 

IDAHO 264 236 225 268 252 

ILLINOIS 1,512 1,372 1,293 1,577 1,484 

INDIANA 1,723 1,611 1,549 1,774 1,704 

IOWA 1,409 1,340 1,310 1,468 1,428 

KANSAS 1,728 1,571 1,516 1,769 1,644 

KENTUCKY 1,955 1,846 1,778 2,006 1,937 

LOUISIANA 1,170 1,067 993 1,242 1,171 

MAINE 445 419 407 456 440 

MARYLAND 1,521 1,298 1,166 1,573 1,417 

MASSACHUSETTS 732 636 567 741 675 

MICHIGAN 1,433 1,321 1,261 1,508 1,434 

MINNESOTA 948 880 851 1,023 981 

MISSISSIPPI 775 705 673 777 729 

MISSOURI 1,705 1,607 1,544 1,757 1,694 

MONTANA 2,034 1,881 1,781 2,084 1,980 

NEBRASKA 1,713 1,568 1,471 1,760 1,661 

NEVADA 757 688 644 760 714 

NEW HAMPSHIRE 630 523 485 632 553 

NEW JERSEY 783 641 531 788 688 

NEW MEXICO 1,188 1,074 1,000 1,244 1,163 

NEW YORK 749 634 557 799 715 

NORTH CAROLINA 1,172 1,046 977 1,233 1,145 

NORTH DAKOTA 1,857 1,815 1,788 1,899 1,874 

OHIO 1,594 1,453 1,349 1,657 1,566 

OKLAHOMA 984 900 879 1,061 986 

OREGON 472 388 375 483 418 

PENNSYLVANIA 1,323 1,189 1,067 1,389 1,293 

RHODE ISLAND 866 809 773 871 837 

SOUTH CAROLINA 880 790 736 921 858 

SOUTH DAKOTA 868 780 731 913 856 

TENNESSEE 1,336 1,219 1,142 1,384 1,307 

TEXAS 1,029 917 855 1,101 1,016 

UTAH 1,446 1,364 1,318 1,502 1,451 

VIRGINIA 978 840 793 1,061 955 

WASHINGTON 376 279 235 389 316 

WEST VIRGINIA 1,872 1,760 1,636 1,915 1,835 
11

WISCONSIN 1,363 1,249 1,185 1,444 1,366 

WYOMING 1,897 1,790 1,701 1,941 1,862 

* Excludes EGUs located in Indian country. 

Partial list of recent heat rate improvement studies: 

“Coal-fired Power Plant Heat Rate Reductions”, Sargent & Lundy SL-009597 Final Report 

(Project 12301-001), (January 2009), available at 

http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf 

“Reducing CO2 Emissions by Improving the Efficiency of the Existing Coal-fired Power Plant 

Fleet”, DOE/NETL-2008/1329, (July 2008), available at http://www.netl.doe.gov/energyanalyses/pubs/CFPP%20Efficiency-FINAL.pdf 

“Power Plant Performance Reporting and Improvement under the Provision of the Indian Energy 

Conservation Act – Output 1.1”, Evonik/VGB (2008), available at http://www.emtindia.net/PowerPlantComponent/Output1.1/Output1.1.pdf 

“Opportunities to Improve the Efficiency of Existing Coal-fired Power Plants, Workshop 

Report”, NETL (July 2009), available at http://www.netl.doe.gov/energyanalyses/pubs/NETL%20Power%20Plant%20Efficiency%20Workshop%20Report%20Final.pdf 

“Improving the Efficiency of Coal-fired Power Plants for Near Term Greenhouse Gas Emission 

Reductions”, DOE/NETL-2010/1411 (April 2010), available at http://www.netl.doe.gov/energyanalyses/pubs/ImpCFPPGHGRdctns_0410.pdf 

“Power Generation from Coal - Measuring and Reporting Efficiency Performance and CO2

Emissions”, OECD/IEA-CIAB (2010), available at 

http://www.iea.org/ciab/papers/power_generation_from_coal.pdf 

“Opportunities to Enhance Electric Energy Efficiency in the Production and Delivery of 

Electricity”, EPRI Technical Report