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EPA v5.15 Base Case Documentation Supplement

to Support EPA’s Clean Power Plan

Overview

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

Clean Power Plan using the EPA v5.15 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 emission performance rates that are part of the CPP.

Heat Rate Improvements (HRI)

As in the modeling that supported the proposed rule, the modeling supporting the final rule also offers 

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 heat rate improvement of 

4.3% in the Eastern Interconnection, 2.3% in the Texas Interconnection, and 2.1% in the Western 

Interconnection. This assumption of 2.1% to 4.3% heat rate improvement, based on the location of 

generator, is represented in the heat rate improvement retrofit option offered in modeling scenarios 

analyzing the CPP.

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.

Biomass Emissions Calculation

As in the modeling that supported the proposed rule, 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 fuel available to all coal-fired power plants. EPA Base Case v.5.15 

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.

 1 See chapter 2 of the Greenhouse Gas Mitigation Measures Technical Support Document (TSD)
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In all the scenarios analyzed for the 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 Emission Performance Rates

The EPA modeled two illustrative plan approaches, each at the state level, based on a rate-based 

approach and a mass-based approach. The rate-based plan approach requires affected sources in each 

state to achieve a single average emissions rate in each period as represented by the statewide goals. 

The mass-based plan approach requires affected sources in each state to limit their aggregate emissions 

not to exceed the mass goal for that state. 

In each of these scenarios, affected EGUs include:

• Existing fossil steam boilers with nameplate capacity greater than 25 MW

• Existing NGCC units

In the rate-based scenario, the affected EGUs within each state are required to achieve an average 

emissions rate that is less than or equal to the state goals for each state. The generation (or avoided 

generation) from these additional sources represented in the model is counted toward meeting state 

goals:

• All renewable capacity (hydro, solar PV, wind, geothermal) that comes online after 2012

• Under-construction nuclear3

• Demand-side energy efficiency in addition to levels implicit in base case electricity demand.

Furthermore, in the rate-based scenario, the affected sources have the ability to do one or both of the 

following:

• generate in amounts within that state such that the average emissions rate is achieved, and/or

• include in the average emissions rate calculation new renewable generation or demand-side 

energy efficiency located outside of the state but within each of the illustrative Interconnectionbased regions shown in Figure 1 below.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 Includes three nuclear facilities at which construction has already commenced: Watts Barr (TN), Vogtle (GA), and 

Summer (SC)

4 In this illustrative scenario, energy efficiency/renewable energy procurement is limited to within one of the three 

illustrative regions. Since the interconnections do not always follow state borders, certain states that fall into more 

than one region were grouped in regions where there was a majority of geographic territory (area) or generation. 

Depending on the elements of their respective state’s plan, sources in states that have adopted certain rate-based 
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Figure 1. Illustrative Regions for Demand-Side Energy Efficiency/Renewable Energy Procurement 

Used in this Analysis

The mass-based scenario includes a 5 percent set-aside of allowances that would be allocated to 

recognize deployment of new renewable capacity, which is represented by lowering the capital cost of 

new renewable capacity in a compliance period by the estimated value of the allowances in the setaside in that period. The value of the set-aside is estimated in each model run year as the total 

allowances in the set-asides of each state in the contiguous U.S. multiplied by the projected average 

allowance price over the contiguous U.S. for that year. This total value is then assumed to apply evenly 

to all new renewable capacity.

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 illustrative compliance analyses 

conducted for the Clean Power Plan. The quantification of these data is explained in the Demand-Side 

Energy Efficiency TSD for the Clean Power Plan.

Table 1. Demand-Side Energy Efficiency Savings Included in CPP Scenarios (GWh)

2020 2025 2030 2040 2050

Alabama 91 3,290 7,266 9,822 10,584

Arizona 795 4,791 7,215 8,605 9,433

Arkansas 241 2,517 4,275 5,290 5,747

California 2,724 16,221 24,125 28,007 30,069

Colorado 522 3,349 5,079 6,060 6,615

Connecticut 305 1,802 2,651 2,989 3,052

Delaware 1 351 847 1,126 1,160

District of Columbia 51 555 936 1,099 1,133

Florida 389 9,054 18,673 24,551 26,617

 

plans may be able to procure energy efficiency/renewable energy from states outside of these illustrative regions. 

See the preamble for discussion.
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Georgia 357 5,894 11,327 14,582 15,720

Idaho 136 1,318 2,175 2,617 2,802

Illinois 1,452 8,584 12,641 14,287 14,744

Indiana 1,002 6,311 9,383 10,628 10,968

Iowa 483 2,869 4,250 4,882 5,112

Kansas 2 1,264 3,077 4,196 4,416

Kentucky 338 4,252 7,591 9,541 10,251

Louisiana 23 2,903 6,976 9,733 10,564

Maine 121 716 1,054 1,188 1,213

Maryland 631 3,723 5,468 6,137 6,326

Massachusetts 565 3,338 4,912 5,539 5,656

Michigan 1,051 6,199 9,106 10,222 10,508

Minnesota 710 4,217 6,246 7,175 7,514

Mississippi 119 2,157 4,240 5,529 6,005

Missouri 419 4,312 7,203 8,525 8,872

Montana 79 765 1,262 1,519 1,627

Nebraska 49 1,201 2,488 3,211 3,360

Nevada 175 1,850 3,133 3,806 4,076

New Hampshire 17 424 873 1,108 1,130

New Jersey 530 4,195 6,498 7,400 7,629

New Mexico 138 1,295 2,129 2,605 2,855

New York 1,478 8,643 12,551 13,648 13,598

North Carolina 813 7,371 11,953 14,436 15,604

North Dakota 3 516 1,238 1,678 1,755

Ohio 1,539 9,098 13,399 15,144 15,628

Oklahoma 168 2,739 5,262 6,818 7,431

Oregon 498 2,967 4,420 5,154 5,519

Pennsylvania 1,350 8,662 12,884 14,499 14,947

Rhode Island 80 470 692 780 796

South Carolina 384 4,151 7,098 8,744 9,451

South Dakota 16 463 981 1,277 1,336

Tennessee 321 4,607 8,556 10,914 11,724

Texas 800 16,340 32,907 43,447 47,574

Utah 256 1,828 2,804 3,295 3,529

Vermont 57 338 497 560 572

Virginia 28 3,699 8,882 12,307 13,289

Washington 970 5,785 8,617 10,048 10,760

West Virginia 79 1,339 2,558 3,165 3,265

Wisconsin 707 4,174 6,142 6,924 7,131

Wyoming 31 695 1,420 1,846 1,976

Continental U.S. Total 23,043 193,044 325,023 395,563 420,514
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The rate-based and mass-based performance rates analyzed in these illustrative scenarios are included 

in Table 2. Note that the performance rates in Table 2 differ slightly from performance rates of the 

interim and final periods. For purposes of modeling the illustrative CPP compliance plan scenarios, the 

CPP goals for the year 2025 are applied in the IPM modeling run year for that same year, which 

represents the interim period. In 2030, the final rule 2030 goals are the modeled goals for the 2030 IPM 

analysis year and all subsequent IPM analysis years.

Table 2. Modeled CO2 Emission Constraints, Illustrative Rate-Based Scenario and Mass-Based Scenario

Rate-Based Scenario

(Adjusted MWh-WeightedAverage Pounds of CO2 Per 

Net MWh from Affected 

Generation)

Mass-Based Scenario

(Adjusted Output-WeightedAverage Short Tons of CO2 From 

All Affected Fossil Fuel-Fired 

EGUs)

2025 2030-2050 2025 2030-2050

Alabama 1,186 1,018 62,301,383 56,787,453

Arizona 1,203 1,031 33,141,475 30,149,400

Arkansas 1,333 1,130 33,777,688 30,301,183

California 936 828 51,128,347 48,412,792

Colorado 1,391 1,174 33,478,664 29,871,662

Connecticut 881 786 7,244,349 6,936,604

Delaware 1,052 916 5,072,066 4,708,488

District of Columbia

Florida 1,056 919 113,188,612 105,017,231

Georgia 1,227 1,049 51,052,586 46,314,052

Idaho 862 771 1,458,943 1,402,956

Illinois 1,484 1,245 75,038,487 66,430,150

Indiana 1,480 1,242 85,888,253 76,060,014

Iowa 1,533 1,283 28,350,412 25,003,581

Kansas 1,547 1,293 24,941,614 21,975,278

Kentucky 1,538 1,286 71,547,475 63,081,489

Lands of the Fort Mojave 

Tribe 862 771 611,571 588,102

Lands of the Navajo Nation 1,562 1,305 24,639,838 21,685,245

Lands of the Uintah and 

Ouray Reservation 1,562 1,305 2,570,003 2,261,830

Louisiana 1,321 1,121 39,419,262 35,401,962

Maine 872 778 2,159,689 2,072,189

Maryland 1,539 1,287 16,262,767 14,337,483

Massachusetts 932 824 12,755,593 12,089,027

Michigan 1,384 1,169 53,213,012 47,510,437

Minnesota 1,442 1,213 25,511,952 22,662,330

Mississippi 1,090 945 27,392,465 25,286,424
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Missouri 1,519 1,272 62,772,857 55,423,669

Montana 1,562 1,305 12,834,064 11,295,116

Nebraska 1,551 1,296 20,712,602 18,243,038

Nevada 971 854 14,364,505 13,514,005

New Hampshire 976 858 4,249,634 3,994,748

New Jersey 915 811 17,445,663 16,587,984

New Mexico 1,354 1,146 13,855,088 12,403,822

New York 1,054 918 33,621,701 31,201,703

North Carolina 1,340 1,136 57,146,893 51,229,970

North Dakota 1,562 1,305 23,711,776 20,868,467

Ohio 1,412 1,190 82,774,830 73,717,634

Oklahoma 1,252 1,068 44,724,737 40,459,552

Oregon 993 871 8,656,441 8,112,904

Pennsylvania 1,287 1,095 99,596,269 89,758,762

Rhode Island 862 771 3,660,189 3,519,728

South Carolina 1,366 1,156 29,053,443 25,980,578

South Dakota 1,380 1,166 3,948,744 3,526,611

Tennessee 1,439 1,211 31,882,568 28,328,349

Texas 1,217 1,041 208,600,955 189,454,688

Utah 1,397 1,179 26,645,320 23,761,376

Vermont

Virginia 1,076 934 29,636,920 27,413,690

Washington 1,140 983 11,705,162 10,731,571

West Virginia 1,562 1,305 58,277,140 51,289,055

Wisconsin 1,393 1,176 31,350,938 27,967,194

Wyoming 1,556 1,300 35,899,031 31,612,047