### 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 mo deling assumptions used as part of EPA’s analysis of the Clean Power Plan (Carbon Pollu tion Guidelines for Existing Electric Generating Units) using the EPA v5.13 Base Case using Integrated Planning Model (IPM). The modifications include an enhan ced capability for existing coal steam-fired units to adopt improvements to their heat rates and a modified calculation for st ack emissions associated with biomass combustion. This supplement also includes more detail on the specific modeling parameters that were used to reflect the stat e goals that are part of the proposed rule. Heat Rate Improvements (HRI) A new capability has been introduced to offe r 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 asse ssment of the engineering and cost parameters of potential heat rate improvements th at reduce auxiliary power and fuel consumption so as to increase net electrical output per unit of heat inpu t (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 reduc ing 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, co al steam generation can realize a 6% heat rate improvement through two types of changes: best practices thathave the potential to improve heat rate by 4%, and equipment upgrades that ha ve the potential to impr ove heat rate by 2%. This assumption of 6% heat rate improvement is represented in the heat rate improvement retrofit option offered in mode ling scenarios analyzing the propos ed regulatory option (Option 1). An alternative level of 4% heat rate improvement is represen ted in the heat rate improvement retrofit option offered in modeli ng scenarios analyzing the regulat ory 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 assu mes $100/kW as a combinedHRI 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 incl uded 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 mode ling applications of IPM, biomass was not assigned a CO 2 

### emission factor associatedwith its combustion, unlike other fuels that emit CO 2 

### when combusted such as coal, natura l 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 s ources that are co-firing biomass, as determined by the model). 2 

### This factor reflects the average CO 2 

### emissions that result from the combustion of biogenic feedstocks, and does not include an y evaluation of stack biogenic CO 2 

### emissions relative to the net landscape and process-relate d 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 aver age, less than or equal to the proposed goals over the entire comp liance period. That is, the CO 2 

### emission rate constraints imposed to represent the state goals are appl ied only to the sources whose generation was originally included in the calculation of the stat e goals being analyzed. Electricity savings (in megawatt-hours avoided) from assumed improvemen ts in demand-side energy efficiency are also incorporated, in the same manner as zero-emittin g generation is incorporated, into the average emission rates that must not exceed the CO 2 

### emission rate constraints.

Generation and emissions from the followi ng sources are included in the average emissions rates that are evaluated against the state goals for compliance:

 Existing IGCC and fossil steam boilers withnameplate 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 (histori cal) generation greater than 219,000 MWh

 New and existing non-hydro renewable capacity 3



###  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 CO 2 emissions from landfill gas and municipal solid waste (MSW) are not included in the average emissions rate subject to the CO 2 constraints, but they are included in projections of total emissions. CO 2 emissions from biomass consumption are included in the average emissions rate subject to the CO 2 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 wa s 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 in cluded in state goals in the prop osed Clean Power Plan. For more

### 3 

###  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 im provements 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 elec tricity savings that is incorporated into the average emissions rate subject to the CO 2 

### 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 incorporat ed into the computation of the relevant state goal and, correspondingly, incorporat ed into the average em ission rate in these modeled scenarios that is subject to the CO 2 

### constraint representi ng 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 generatio n, 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

### 5 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 high er 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.

### 6 

### The illustrative compliance scenarios also assume that state plans allow for intertemporal averaging in the initial compliance periods for bothOption 1 and Option 2. That is, for the initial compliance period for which the “interim” state go al is applied, the aver age 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 in itial compliance period for Option 1 is 2020 to 2029, and for Option 2 it is 2020 to 2 024. After the initial compliance period, the average emission rate of the aff ected sources in each year mustbe less than or equal to the “final” state goal in each model run-year thereafter. The intertemporal flexibility described a bove for the initial compliance periods is represented in these modeling scenarios by a combination of:

 an endogenous “banking” behavior, wh ereby 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 period 5 

### ; and

 an exogenously assumed “borrowing” patte rn, whereby states are assumed to exceed the interim goal in earlier years while offsetting those exceedances with additional emission rate reduc tions below the interim goal levels in later years of the initial comp liance period. The exogenously assumed borrowing pattern is represented by imposing intermediate CO 2 

### emission rate constraints in each run-year of the initial compliance period that are consistent with the annual values used to calculate the inte rim state goals for the relevant regulatory option. Those annual values are reported in the Goal Co mputation TSD, and Tables 3 through 5 below show the CO 2 

### intermediate CO 2 

### emission rate constraints derive d from those values and imposed for each state in these modeling scenarios. For combined heat and power (CHP) units that are covered under th e rule, the emissions and energy output associated withthe useful thermal output not used for electricity production are included in the state goal and would be re ported 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 inthe Goal Computation TSD. The state goals, as shown in the proposed ru le and Tables 2 through 4 below, reflect total emissions divided by total net ener gy 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 gene ration and energy output data The proposed state goals are shown in Table 3. Table 4 shows the corresponding, CO 2 

### emission rates that have been adjusted to excl ude useful (non-electric) thermal output that is captured in the state goals but is not simulated inIPM at combined heat and power (CHP) units. Table 5 shows the CO 2 

### emission rate constraints that we re 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.

### 7 

### RIA. The rates in Table 5 differ slightly from the proposed state goals because they have been adjusted to exclude useful (non-el ectric) thermal output that is cap tured 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 we re made after this modeling was conducted. Table 3. Proposed State Goals, Interim and Final (Adjusted MWh-Weighted-Average Pounds of CO 2 

### Per Net MWh from Affected Genera tion Included in State Goals) for Options 1 & 2

STATE 6 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 note d 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.

### 8 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 CO 2 

### 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

### 9 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 CO 2 

### Emission Rate Constraints (A djusted MWh-Weighted-Average Pounds of CO 2 

### Per Net MWh from Affected Genera tion 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

### 10 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 Reduc tions”, Sargent & Lundy SL-009597 Final Report (Project 12301-001), (January 2009), available at http://www.epa.gov/airmarkets/r esource/docs/coalfired.pdf “Reducing CO 2 

### Emissions by Improving the Efficiency of the Existing Coal-fired Power Plant Fleet”, DOE/NETL-2008/1329, (July 2008), ava ilable at http://www.netl.doe.gov/energyanalyses/pubs/CFPP%20Efficiency-FINAL.pdf “Power Plant Performance Reporting and Improvem ent 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), availabl e at http://www.netl.doe.gov/energyanalyses/pubs/NETL%20Power%20Plant%20Eff iciency%20Workshop%20Report%20Final.pdf “Improving the Efficiency of Coal-fired Powe r Plants for Near Term Greenhouse Gas Emission Reductions”, DOE/NETL-2010/1411 (April 2010), av ailable at http://www.netl.doe.gov/energyanalyses/pubs/ImpCFPPGHGRdctns_0410.pdf “Power Generation from Coal - Measuring and Reporting Efficiency Performance and CO 2 

### Emissions”, OECD/IEA-CIA B (2010), available at http://www.iea.org/ciab/papers/ power_generation_from_coal.pdf “Opportunities to Enhance Electric Energy E fficiency in the Produc tion and Delivery of Electricity”, EPRI Technical Report