Technical Support Document (TSD) 

for the Transport Rule 

Docket ID No. EPA-HQ-OAR-2009-0491 

Updates to EPA Base Case v3.02 EISA Using the Integrated 

Planning Model 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

June 17, 2010 
2

Updates to EPA Base Case v3.02 EISA Using the 

Integrated Planning Model

This document describes EPA Base Case v3.02 EISA using the Integrated Planning 

Model (IPM), the version used to model electric generation for the proposed Transport 

Rule. It builds on the last major update, EPA Base Case 2006 (v3.0), and a subsequent 

minor update from 2007 (v3.01). 

In the fall of 2006, EPA released Base Case 2006 (v3.0) using IPM, which included 

extensive updates of IPM’s assumptions, inputs, and capabilities. The model was again 

updated in the summer of 2007 for purposes of climate modeling (v3.01). In preparing 

these base cases, EPA obtained input from nationally recognized experts in fuels, 

technology, and power system operation. Power companies provided information on 

generating resources and emission controls. EPA also obtained input from Regional 

Planning Organizations, States, and their constituent organizations. Key updates 

included: 

z Coal Supply and Transportation Assumptions 

z Natural Gas Assumptions 

z Federal and State Emission Regulations and Enforcement Actions 

z Cost and Performance of Generating Technologies and Emission Controls 

z Sulfur Dioxide (SO2), Nitrogen Oxide (NOX) emissions 

z Power System Operating Characteristics and Structure 

z Electric Generating Unit Inventory 

z Modeling Time Horizon and Run Years (2010, 2015, 2020, 2025) 

z Carbon capture and storage for potential (new) units 

z Biomass co-firing capability for existing coal boilers 

z Updated constraints on new nuclear and renewable capacity builds 

The detailed assumptions for Base Case 2006 (v3.0), titled “Documentation for EPA 

Base Case 2006 (v3.0) Using the Integrated Planning Model” (November 2006) can be 

found at http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html#docs. Likewise, 

documentation on the updates made for v3.01 can be found at 

http://www.epa.gov/airmarkt/progsregs/epa-ipm/docs/Documentation%20for%20EPA%2

7s%20Base%20Case%20v3.01%20Using%20IPM.pdf 

Compared to these earlier versions, v3.02 EISA contains updates to several key features 

of the model: 

1. Revised electricity demand (largely driven by the Energy Independence and 
3

Security Act of 2007 (EISA)) 

2. Updated power technology costs for new units 

3. Updated power technology costs for retrofit controls 

4. Updated natural gas supply assumptions 

5. Updated NSR and state rules (through February 3, 2009) 

6. Dispatchable flue gas deposition (FGD) and selective catalytic reduction (SCR) 

retrofits 

7. Updates to the National Electric Energy Data System (NEEDS) 

8. Title IV SO2 allowance bank estimate 

9. Updated mapping of model run years 

10. Updated financial assumptions 

The following document summarizes the key features and changes found in Base Case 

v3.02 EISA. 

Overview of IPM and EPA Modeling Applications1

EPA uses the Integrated Planning Model (IPM) to analyze the projected impact of 

environmental policies on the electric power sector in the 48 contiguous states and the 

District of Columbia. Developed by ICF Resources, Inc., and used to support public and 

private sector clients, IPM is a multi-regional, dynamic, deterministic linear 

programming model of the electric power sector. It provides forecasts of least-cost 

capacity expansion, electricity dispatch, and emission control strategies for meeting 

electricity demand, environmental, transmission, dispatch, and reliability constraints. 

IPM can be used to evaluate the cost and emissions impacts of proposed policies to limit 

emissions of sulfur dioxide (SO2), nitrogen oxides (NOX), carbon dioxide (CO2), and 

mercury (Hg) from the electric power sector and is used extensively by EPA to support 

regulatory activities. Updates for this version of the model were primarily focused on 

allowing strong analysis of regional SO2 and NOX reductions. 

Among the factors that make IPM particularly well suited to model multi-emissions 

control programs are (1) its ability to capture complex interactions among the electric 

power, fuel, and environmental markets; (2) its detail-rich representation of emission 

control options encompassing a broad array of retrofit technologies along with emission 

reductions through fuel switching, changes in capacity mix and electricity dispatch 

strategies; (3) its capability to model a variety of environmental regulatory structures 

such as state and regional cap and trade programs and source specific controls; and its 

ability to generate the detailed, location-specific emission data required for air quality 

 

1

 See also Appendix I of this document. 
4

modeling. IPM’s ability to capture the dynamics of the allowance market (including 

banking) and its provision of a wide range of emissions reduction options are particularly 

important for assessing the impact of multi-emissions environmental policies for the 

power sector. 

IPM is a single sector, linear programming model that captures the economic behavior of 

the power sector. It has been used by itself to analyze many power specific policies 

including: the Title IV NOX Program, the NOX SIP Call and CAIR. The model has also 

been employed by EPA in conjunction with broader macroeconomic models to help 

provide deeper resolution of the power sector than is available in most macro-economic 

models. 

1. Electricity Demand 

The electric load assumptions in Base Case v3.02 EISA are shown in Table 1 below. 

These values were derived based on the electricity sales forecast in the U.S. Energy 

Information Administration’s Annual Energy Outlook (AEO) 2008 reflecting EISA 2007. 

The revised growth rate used in the reference case is nearly 1%, compared to a growth 

rate of 1.5% in past IPM modeling applications. 

Table 1. Net Energy for Load in EPA v3.02 EISA Base Case (GWh) 

Year Net Energy For Load (GWh) 

2012 4,223,337 

2015 4,287,367 

2020 4,498,173 

2025 4,717,525 

2. Potential (New) Unit Costs 

All costs for potential units have been updated to incorporate the market conditions 

reflected in AEO 2008. EPA uses both EIA and independent analysis to support cost and 

performance assumptions for new power generating technologies in IPM. Tables 2 and 3 

below show the cost and performance characteristics of the modeled potential (new) build 

units. 
5

Table 2. Performance and Unit Cost Assumptions for Potential (New) 

Capacity from Conventional Technologies in v3.02 EISA Base Case 

Advanced 

Combined 

Cycle

Advanced 

Combustion 

Turbine

Nuclear

Integrated 

Gasification 

Combined Cycle - 

Bituminous

Integrated 

Gasification 

Combined Cycle - 

Subbituminous

Integrated Gasification 

Combined Cycle with 

Carbon CaptureBituminous

Integrated Gasification 

Combined Cycle with 

Carbon Capture - 

Subbituminous

Supercritical 

Pulverized 

Coal - Wet 

Bituminous

Supercritical 

Pulverized Coal -

Dry SubBituminous

Size (MW) 400 230 1350 550 550 380 380 600 600

First Year Available 2013 2012 2020 2015 2015 2015 2015 2015 2015

Lead Time (Years) 326 4 4 4 4 4 4

Vintage #1 (years covered) 2012 - 2013 2012 - 2013 -- -- -- -- -- -- --

Vintage #2 (years covered) 2014 - 2017 2014 - 2017 -- 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017

Vintage #3 (years covered) 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022

Vintage #4 (years covered) 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035

Availability 87% 92% 90% 80% 80% 80% 80% 85% 85%

Heat Rate (Btu/kWh) 6,720 10,200

Capital (2006$/kW) 800 535

Fixed O&M (2006$/kW/yr) 9.8 11.6

Variable O&M (2006$/MWh) 1.32 2.42

Heat Rate (Btu/kWh) 6,720 10,200 8,920 9,310 10,510 11,000 9,000 9,170

Capital (2006$/kW) 780 519 1,980 2,310 2,610 3,000 1,800 1,750

Fixed O&M (2006$/kW/yr) 9.8 11.6 35.3 39.5 43.7 48.6 25.7 25.2

Variable O&M (2006$/MWh) 1.32 2.42 6.49 7.17 8.1 9.0 4.97 4.87

Heat Rate (Btu/kWh) 6,720 10,200 10,400 8,920 9,310 10,510 11,000 9,000 9,170

Capital (2006$/kW) 765 508 3,000 1,936 2,259 2,553 2,934 1,768 1,719

Fixed O&M (2006$/kW/yr) 9.8 11.6 66.1 35.3 39.5 43.7 48.6 25.7 25.2

Variable O&M (2006$/MWh) 1.32 2.42 0.48 6.49 7.17 8.1 9.0 4.97 4.87

Heat Rate (Btu/kWh) 6,720 10,200 10,400 8,920 9,310 10,510 11,000 9,000 9,170

Capital (2006$/kW) 745 490 2,784 1,883 2,197 2,482 2,853 1,739 1,691

Fixed O&M (2006$/kW/yr) 9.8 11.6 66.1 35.3 39.5 43.7 48.6 25.7 25.2

Variable O&M (2006$/MWh) 1.32 2.42 0.48 6.49 7.17 8.1 9.0 4.97 4.87

Note: Capital costs represent overnight capital costs

Vintage #3

Vintage #4

Vintage #2

--

Vintage #1

-- -- -- -- -- -- --

Table 3. Performance and Unit Cost Assumptions for Potential (New) 

Renewable and Non-Conventional Technology Capacity in v3.02 EISA 

Base Case 

LGHI LGLo LGVLo

Size (MW) 35 120 10 50 5 100 50

First Year Available 2012 2020 2012 2012 2012 2012 2012

Lead Time (Years) 3 4 3 4 2 33

Vintage #1 (years covered) 2012 - 2013 -- 2012 - 2013 2012 - 2013 2012 - 2013 2012 - 2013 2012 - 2013 2012 - 2013 2012 - 2013

Vintage #2 (years covered) 2014 - 2017 -- 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017

Vintage #3 (years covered) 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022

Vintage #4 (years covered) 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035

Availability 85% 80% 87% 87% 90% 90% 95%

Generation Capability Economic Dispatch Economic Dispatch Generation Profile Generation Profile Generation Profile

Heat Rate (Btu/kWh) 13,500 7,930 29,660 - 397,035 13,648 13,648 13,648 0 0 0

Capital (2006$/kW) 3,000 5,374 1,049 - 13,352 1,881 2,370 3,649 4,915 3,004 1,707 - 4,558

Fixed O&M (2006$/kW/yr) 83.0 5.5 147 - 212 111.2 111.2 111.2 11.4 55.2 29.5

Variable O&M (2006$/MWh) 11.30 46.62 0 0.01 0.01 0.01 0 0 0

Heat Rate (Btu/kWh) 13,500 7,930 13,648 13,648 13,648 0 0 0

Capital (2006$/kW) 3,000 5,374 1,881 2,370 3,649 4,915 3,004 1,707 - 4,558

Fixed O&M (2006$/kW/yr) 83.0 5.5 111.2 111.2 111.2 11.4 55.2 29.5

Variable O&M (2006$/MWh) 11.30 46.62 0.01 0.01 0.01 0 0 0

Heat Rate (Btu/kWh) 13,500 9,800 7,930 13,648 13,648 13,648 0 0 0

Capital (2006$/kW) 2,700 2,600 5,374 1,828 2,304 3,547 4,330 2,523 1,693 - 4,522

Fixed O&M (2006$/kW/yr) 83.0 47.0 5.5 111.2 111.2 111.2 11.4 55.2 29.5

Variable O&M (2006$/MWh) 11.30 8.60 46.62 0.01 0.01 0.01 0 0 0

Heat Rate (Btu/kWh) 13,500 9,800 7,930 13,648 13,648 13,648 0 0 0

Capital (2006$/kW) 2,700 2,600 5,374 1,828 2,304 3,547 4,330 2,523 1,693 - 4,522

Fixed O&M (2006$/kW/yr) 83.0 47.0 5.5 111.2 111.2 111.2 11.4 55.2 29.5

Variable O&M (2006$/MWh) 11.30 8.60 46.62 0.01 0.01 0.01 0 0 0

Note: Capital costs represent overnight capital costs

2012 - 2035

3

Landfill Gas

Fuel Cells Solar Photovoltaic Geothermal

2012

30

Solar Thermal Wind Biomass 

Conventional

Biomass 

Gasification 

Combined Cycle

90%

Economic Dispatch Economic Dispatch

Vintage #1

--

Vintage #2

-- --

Vintage #3

--

Vintage #4

--

3. Pollution Retrofit Costs 

The following is a tabular representation of the engineering equations that were used to 

generate the input costs for NOX control retrofits in IPM. Specifically, Table 4 and the 

accompanying notes provide the coefficients, terms and scaling factors of the engineering 

equations that were used to derive the capital, FOM (fixed operating and maintenance), 

and VOM (variable operating and maintenance) cost rates used in IPM for NOX retrofit 
6

emission controls. In the notes under Table 4 examples are provided to illustrate how 

these cost rates would be derived for a 275 MW unit from the values shown in the table. 

Table 4. NOX Control Retrofit Cost Assumptions for Existing Coal-fired 

Units in v3.02 EISA Base Case (2006$) 

Post-Combustion 

Control Technology 

Coefficients Percent 

Capital ($/kW) Removal Fixed O&M 

($/kW-year) 

Variable O&M 

(mills/kWh) 

SCR2 169 0.79 0.71 90%1

SNCR3 Term1: 29 Term1: 0.30 0.79 35% Term2: 33 Term2: 0.35 

SNCR4 (Cyclone) 17 0.17 1.55 35% 

SNCR5 (Fluidized Bed) 29 0.31 0.91 50% 

Notes:

The “Coefficients” in the table above are multiplied by the terms below to determine costs. 

“MW” in the terms below is the unit’s capacity in megawatts. 

1

 Cannot provide reductions any further beyond 0.06 lbs/mmBtu. 

2

 SCR Cost Equations:

SCR Capital Cost ($/kW) = 169 * (242.72/MW)0.27 

SCR Fixed O&M Cost ($/kW-year) = 0.79 * (242.72/MW)0.27

SCR Variable O&M Cost (mills/kWh) = 0.71 (242.72/MW)0.11 

The cost equations shown above apply up to 600 MW. The cost obtained for a 600 MW unit applies for 

units larger than 600 MW. 

Example for 275 MW unit: 

 SCR Capital Cost ($/kW) = 169 * (242.72/275)0.27 ≈ 163 $/kW

 SCR FOM Cost ($/kW-year) = 0.79 * (242.72/275)0.27 ≈ 0.76 $/kW-year

 SCR VOM Cost (mills/kWh) = 0.71 * (242.72/275)0.11 ≈ 0.70 mills/kWh 

3

 SNCR Cost Equations:

SNCR Capital Cost ($/kW) = (29*(200/MW)0.577 + 33*(100/MW)0.681)/2 

SNCR Fixed O&M Cost ($/kW-year) = (0.30*(200/MW)0.577 + 0.35*(100/MW)0.681)/2 

Example for 275 MW unit: 

 SNCR Capital Cost ($/kW) = (29 * (200/275)0.577 + 33 * (100/275)0.681)/2 ≈ 20 $/kW 

 SNCR FOM Cost ($/kW-year) = (0.30 * (200/275)0.577 + 0.35 * (100/275)0.681)/2 ≈ 0.21 $/kW-year 

 SNCR VOM Cost (mills/kWh) = 0.79 mills/kWh 

4

 Cyclone Cost Equations:

Coal SNCR—Cyclone Capital Cost ($/kW) = 17 (300/MW)0.577 

Coal SNCR—Cyclone Fixed O&M Cost ($/kW-year) = 0.17 (300/MW)0.577

Example for 275 MW unit: 

 Capital Cost for Cyclone Coal SNCR ($/kW) = 17 * (300/275)0.577 ≈ 18 $/kW 

 FOM Cost for Cyclone Coal SNCR ($/kW-year) = 0.17 * (300/275)0.577 ≈ 0.18 $/kW-year 
7

 VOM Cost for Cyclone Coal SNCR (mills/kWh) = 1.55 

5

 Fluidized Bed Cost Equations:

SNCR - Fluidized Bed Capital Cost ($/kW) = 29 * (200/MW)0.577 

SNCR - Fluidized Bed Fixed O&M Cost ($/kW-year) = 0.31 * (200/MW)0.577

Example for 275 MW unit: 

 Fluidized Bed Capital Cost for SNCR ($/kW) = 29 * (200/275)0.577 ≈ 24 $/kW 

 Fluidized Bed FOM Cost for SNCR ($/kW-year) = 0.31 * (200/275)0.577 ≈ 0.26 $/kW-year 

 Fluidized Bed VOM Cost for SNCR (mills/kWh) = 0.91 

Reference 

Khan, S. and Srivastava, R. “Updating Performance and Cost of NOX Control Technologies in the 

Integrated Planning Model,” Mega Symposium, August 30, 2004 - September 2, 2004, Washington, 

D.C. 

For comparison, Table 4.a. provides the same parameters as in Table 4 but from 

the IPM analysis for the final CAIR. The EPA’s modeling for CAIR used IPM Base 

Case 2004 (v.2.1.9). The information in Table 4.a is taken from Table 5.6 in Chapter 5 in 

the documentation for v.2.1.9.2

 The CAIR analysis was performed using 1999 dollars 

and costs in Table 4.a are also presented in 1999 dollars. 

Table 4.a NOX Control Retrofit Cost Assumptions for Existing Coalfired Units in CAIR v2.1.9 Base Case (1999$) 

 

2

 Standalone Documentation for EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning Model, 

EPA 2005 (http://epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html#version2004). 
8

Table 5 on the next page shows the capital, FOM, and VOM cost rates for the two SO2

emission control retrofit technologies represented in the IPM – Limestone Forced 

Oxidation (LSFO) scrubbers and Lime Spray Dryer (LSD) – for a representative range of 

generating units differentiated by their capacities, heat rates, and coals.3 The engineering 

equations and related assumptions used to derive the values shown in this table are 

presented in two papers: James E. Staudt and Sikander R. Khan, “Updating Performance 

and Cost of SO2 Control Technologies in the Integrated Planning Model and the Coal 

Utility Environmental Cost Model,” The Mega Symposium, August 28–31, 2006, 

Baltimore, Maryland, and “SO2 Control Technology Performance and Cost Study” by 

Andover Technology Partners, EPA Contract No. 68-W-03-02, April 2006. 

 

3

 LSFO and LSD have removal rates of 95% and 90% respectively, as detailed in Table 5.2 of the v3.0 

documentation referenced earlier. 
9

Table 5. Application of SO2 Control Retrofit Cost Assumptions for 

Existing Coal-fired Units in v3.02 EISA Base Case (2006$) 

Scrubber Type Capacity 

(MW) 

Heat Rate (Btu/kWh) Cost 9,000 10,000 11,000 

Limestone Forced Oxidation 

(LSFO) 

Minimum Cutoff: 100 MW 

Maximum Cutoff: None 

Assuming 5.0 lbs/MMBtu SO2

Coal 

100 

705 708 711 Capital Cost ($/kW) 

20.3 20.3 20.3 Fixed O&M ($/kW-year) 

1.39 1.49 1.60 Variable O&M (mills/kWh) 

300 

345 348 351 Capital Cost ($/kW) 

11.7 11.7 11.7 Fixed O&M ($/kW-year) 

1.39 1.49 1.60 Variable O&M (mills/kWh) 

500 

259 263 266 Capital Cost ($/kW) 

9.6 9.6 9.6 Fixed O&M ($/kW-year) 

1.39 1.49 1.60 Variable O&M (mills/kWh) 

700 

212 215 218 Capital Cost ($/kW) 

8.5 8.5 8.5 Fixed O&M ($/kW-year) 

1.39 1.49 1.60 Variable O&M (mills/kWh) 

1000 

179 182 186 Capital Cost ($/kW) 

7.5 7.5 7.5 Fixed O&M ($/kW-year) 

1.39 1.49 1.60 Variable O&M (mills/kWh) 

Lime Spray Dryer (LSD) 

Minimum Cutoff: 100 MW 

Maximum Cutoff: None 

Assuming 3.0 lbs/MMBtu SO2

Coal 

100 

422 433 443 Capital Cost ($/kW) 

11.7 13.9 12.8 Fixed O&M ($/kW-year) 

2.24 2.56 2.77 Variable O&M (mills/kWh) 

300 

224 235 247 Capital Cost ($/kW) 

8.5 8.5 8.5 Fixed O&M ($/kW-year) 

2.24 2.56 2.77 Variable O&M (mills/kWh) 

500 

188 198 210 Capital Cost ($/kW) 

6.4 6.4 6.4 Fixed O&M ($/kW-year) 

2.24 2.56 2.77 Variable O&M (mills/kWh) 

700 

168 179 191 Capital Cost ($/kW) 

5.3 5.3 5.3 Fixed O&M ($/kW-year) 

2.24 2.56 2.77 Variable O&M (mills/kWh) 

1000 

157 170 182 Capital Cost ($/kW) 

4.3 4.3 4.3 Fixed O&M ($/kW-year) 

2.24 2.56 2.77 Variable O&M (mills/kWh) 

The values shown above in Tables 4 and 5 incorporate scaling factors to capture cost 

increases that have occurred since the equations were originally developed. In general, 

capital costs incorporate the market conditions reflected in AEO 2008. 
10

Table 6. Post-Combustion NOX Controls for Oil/Gas Steam Units 

(2006$) in v3.02 EISA Base Case 

Post-Combustion 

Control Technology 

Coefficients 

Variable O&M 

(mills/kWh) 

Percent 

Removal Capital 

($/kW) 

Fixed O&M 

($/kW-year) 

SCR1 49 1.05 0.12 80% 

SNCR2 16 0.18 0.53 50% 

Notes:

The “Coefficients” in the table above are multiplied by the terms below to determine costs. 

“MW” in the terms below is the unit’s capacity in megawatts. 

 

1

 SCR Cost Equations:

SCR Capital Cost ($/kW) = 49 * (200/MW)0.35 

SCR Fixed O&M Cost ($/kW-year) = 1.05 * (200/MW)0.35

The cost equations shown above apply up to 500 MW. The cost obtained for a 500 MW unit applies for 

units larger than 500 MW. 

Example for 275 MW unit:

SCR Capital Cost ($/kW) = 49 * (200/275)0.35 ≈ 44 $/kW 

SCR FOM Cost ($/kW-year) = 1.05 * (200/275)0.35 ≈ 0.94 $/kW-year 

SCR VOM Cost (mills/kWh) = 0.12 mills/kWh 

2

 SCNR Cost Equations:

SNCR Capital Cost ($/kW) = 16 * (200/MW)0.577 

SNCR Fixed O&M Cost ($/kW-year) = 0.18 * (200/MW)0.577

The cost equations shown above apply up to 500 MW. The cost obtained for a 500 MW unit applies for 

units larger than 500 MW. 

Example for 275 MW unit:

SNCR Capital Cost ($/kW) = 16 * (200/275)0.577 ≈ 13 $/kW

SNCR FOM Cost ($/kW-year) = 0.18 * (200/275)0.577 ≈ 0.15 $/kW-year 

SNCR VOM Cost (mills/kWh) = 0.53 mills/kWh 

 

Reference:

Cost Estimates for Selected Applications of Nox Control Technologies on Stationary Combustion Boilers, 

Bechtel Power Corporation for US EPA, June 1997. 

For comparison, Table 6.a. provides the same parameters as in Table 6 but from 

the IPM analysis for the final CAIR. The EPA’s modeling for CAIR used IPM Base 

Case 2004 (v.2.1.9). The information in Table 6.a is taken from Table 5.7 in Chapter 5 in 

the documentation for v.2.1.9.4

 The CAIR analysis was performed using 1999 dollars 

 

4

 Standalone Documentation for EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning Model, 

EPA 2005 (http://epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html#version2004). 
11

and costs in Table 6.a are also presented in 1999 dollars. 

Table 6.a NOX Control Retrofit Cost Assumptions for Oil/Gas Steam 

Units in CAIR v2.1.9 Base Case (1999$) 

 

Table 7. Cost (2006$) of NOX Combustion Controls for Coal Boilers 

in Base Case v3.02 EISA 

Boiler Type Technology Coefficients Variable 

O&M 

(mills/kWh) Capital 

($/kW) 

Fixed O&M 

($/kW-year) 

Dry Bottom 

Wall-Fired 

Low NOX Burner without Overfire Air (LNB without OFA) 29 0.31 0.064 

Low NOX Burner with Overfire Air (LNB with OFA) 39 0.43 0.085 

TangentiallyFired Low NOX Coal-and-Air Nozzles with Close-Coupled 

Overfire Air (LNC1) 

15 0.17 0.000 

Low NOX Coal-and-Air Nozzles with Separated Overfire 

Air (LNC2) 

21 0.22 0.029 

Low NOX Coal-and-Air Nozzles with Close-Coupled and 

Separated Overfire Air (LNC3) 

24 0.27 0.029 

Notes:

For all of the above combustion controls the following equations are used to obtain the capital and fixed 

operating and maintenance costs applicable to the capacity (in megawatts) of the unit taking on 

combustion controls: 

Capital Cost ($/kW) = X * (300/MW)0.359

Fixed O&M Cost ($/kW-year) = X * (300/MW)0.359

where “X” is the appropriate coefficient shown in the above table (in $/kW or $/kW-year for Capital or 

Fixed O&M respectively) and “MW” is the capacity (in megawatts) of the unit taking on combustion 

controls. 

No scaling is applied in calculating the variable operating and maintenance cost (i.e., the Variable O&M 

values above apply for all sizes). 
12

Example for 275 MW dry bottom wall-fired unit installing LNB with OFA:

Capital Cost ($/kW) = 39 * (300/275)0.359 ≈ 40 $/kW 

Fixed O&M Cost ($/kW-year) = 0.43 * (300/275)0.359 ≈ 0.44 $/kW-year 

Variable O&M Cost (mills/kWh) = 0.085 mills/kWh 

4. Updated Natural Gas Supply Projections 

The natural gas supply curves are based on the same assessment of available gas resource 

through the U.S. and Canada as used in ICF’s Gas Market Model (GMM) as of late 2007, 

including resources in Alaska and the Mackenzie Delta area of the Canadian arctic. The 

Base Case assumes that pipelines will be built to transport gas from these two areas to 

North American demand markets. The curves assumes a Mackenzie Delta gas pipeline is 

built in 2015 with a capacity of 1 Bcfd, and an Alaska pipeline is built in 2020 with an 

initial capacity of 4 Bcfd, which is expanded in 2023 to 6 Bcfd. Together, gas production 

from Mackenzie Delta and Alaska make up roughly 11 percent of gas supplies by 2030. 

The gas supply curves also assume significant growth in North American liquefied 

natural gas (LNG) imports, based on projected growth in liquefaction capability and 

taking into account the expect growth in gas demand in other importing countries in 

Europe and Asia. LNG imports are expected to grow to over 7 Bcfd, or roughly 11 

percent of gas supplies by 2030. 

See Appendix II for detailed natural gas supply curves. 

5. Power Sector Regulatory Environment 

The model includes policies affecting the power sector: the Title IV of the Clean Air Act 

(the Acid Rain Program); the NOX SIP Call; various New Source Review (NSR) 

settlements5

; and several state rules6 affecting emissions of SO2 and NOX that were 

finalized through February 3, 2009. IPM includes state rules that have been finalized 

and/or approved by a state’s legislature or environmental agency. Appendixes III and IV 

show the rules and settlements newly modeled. 

 

5

 The NSR settlements include agreements between EPA and Southern Indiana Gas and Electric Company 

(Vectren), Public Service Enterprise Group, Tampa Electric Company, We Energies (WEPCO), 

Virginia Electric & Power Company (Dominion), Santee Cooper, Minnkota Power Coop, American 

Electric Power (AEP), East Kentucky Power Cooperative (EKPC), Nevada Power Company, Illinois 

Power, Mirant, Ohio Edison, and Kentucky Utilities. 6

 These include current and future state programs in Connecticut, Delaware, Georgia, Illinois, Maine, 

Maryland, Massachusetts, Minnesota, Missouri, New Hampshire, North Carolina, New Jersey, New 

York, Oregon, Texas, and Wisconsin. 
13

The Clean Air Visibility Rule (CAVR) and the Clean Air Mercury Rule (CAMR) were 

removed from the baseline. On February 8, 2008, the D.C. Circuit Court vacated EPA's 

rule removing power plants from the Clean Air Act list of sources of hazardous air 

pollutants and at the same time, the Court vacated the CAMR. In June 2005, EPA 

finalized guidelines for States to use in determining which facilities must install controls 

and the type of controls the facilities must use to satisfy Best Available Retrofit 

Technology (BART) requirements to address regional haze (also known as the CAVR). 

Because of uncertainty regarding the precise measures and requirements States will 

adopt, the specific CAVR power sector assumptions that were formerly modeled in IPM 

have been removed. 

6. Dispatchable Controls 

As detailed in chapter 7 of the proposed Transport Rule Regulatory Impact Analysis, 

developing the Transport Rule presented a unique regulatory situation to represent in 

IPM: the possibility of an area moving to less stringent control requirements than were 

expected previously (e.g., under CAIR). To model this situation, v3.02 EISA decides 

economically whether to operate certain advanced SO2 and NOX emissions controls. In 

areas transitioning from a more stringent to less stringent regulatory regime (for example, 

a state affected by CAIR but potentially not affected by the proposed Transport Rule), 

operators may have economic incentive to bypass or reduce operation of FGD or SCR. 

At the same time, units built to comply with settlements, state rules, or other past policies 

would be required to continue to operate regardless of changes to the CAIR program. 

In order to represent these decisions accurately within the framework of IPM, v3.02 

EISA models this choice as a retrofit option without capital cost. If a particular FGD, 

SCR, or ACI is dispatchable, it is removed from NEEDS for the purposes of modeling. 

In its place, the affected model plant receives a special FGD or SCR retrofit option that 

matches the operating characteristics of the removed control but, unlike a normal retrofit, 

has zero capital cost. The model will use this retrofit if the control is economical to 

operate, but it will not use the retrofit if the control is not economical. Hence the model 

makes the control “dispatchable.” 

Base Case v3.02 EISA incorporates a set of rules to determine which EGUs have 

dispatchable controls. These rules are designed to target controls not affected by 

continuing mandates to operate, such as those installed for compliance with EPAadministered trading programs like the Acid Rain Programs for SO2. The rules listed 

below apply to FGD, SCR, and ACI on coal-fired units. 

Note that as in previous IPM modeling, a set of rules applies to all units to determine 

their NOX rates. These rules are discussed in detail in Section 3 of the documentation for 
14

EPA Base Case 2006 (v3.0): http://www.epa.gov/airmarkt/progsregs/epaipm/docs/Section-3.pdf. The model can choose whether to install a dispatchable postcombustion NOX control, but once installed, it is treated the same as any other control 

under the Section 3 rules in determining a unit’s NOX rate. 

Rules for dispatchable scrubbers on coal units 

1. If the unit online year is 1990 or later then the scrubber will not be dispatchable. 

Such units are likely to be new units required to control. 

2. If the unit is online before 1990 and if the scrubber is online in 1992 or earlier 

then the scrubber will not be dispatchable. These scrubbers were most likely built 

for a reason other than compliance with the Title IV Acid Rain Program. 

3. If the unit is online before 1990 and if the scrubber is online in 1993 or later then 

the scrubber will not be dispatchable if it is mandated by NSR, state settlement or 

state-specific rule and the scrubber is online by the end of 2011. 

4. If the criteria in (1–3) are not met, then scrubbers will be dispatchable. 

Rules for dispatchable SCR controls on coal units within the CAIR region 

but outside the SIP Call region 

1. If the unit online year is 1990 or later then the SCR will not be dispatchable. 

Such units are likely to be new units required to control. 

2. If the unit’s firing type is cyclone and the SCR is online in 1999 or earlier then the 

SCR will not be dispatchable. Such a control was most likely installed for 

compliance with the Title IV NOX Program or an earlier mandate. 

3. If the unit is online before 1990 then the SCR will not be dispatchable if the SCR 

control is mandated by NSR, state settlement or state-specific rule and the control 

is online by the end of 2011. 

4. If the criteria in (1–3) are not met then SCR controls will be dispatchable. 

Rules for dispatchable SCR controls on coal units outside the CAIR region 

and/or within the SIP Call region 

No SCR controls will be dispatchable. (They are still subject to Section 3 rules for 

determining NOX rates; see above.) 

Rules for dispatchable SNCR controls on coal units 

No SNCR controls will be dispatchable. 
15

Rules for dispatchable ACI on coal units 

ACI will not be dispatchable if any of the following criteria is met: 

a) If the ACI control is mandated by NSR, state settlement or state-specific rule and 

the control is online by the end of 2011. 

b) If the unit is online after 2005 (i.e., those treated as committed by NEEDS). 

c) If the unit is in one of the following states with mercury rules: GA; IL; ME; MD; 

MN; NH; WI. 

7. Updates to National Electric Energy Data System (NEEDS) 

The National Electric Energy Data System or “NEEDS” database contains the generation 

unit records used to construct the “model” plants that represent existing and 

planned/committed units in EPA modeling applications of IPM. NEEDS includes basic 

geographic, operating, air emissions, and other data on these generating units. NEEDS 

was updated for Base Case v3.02 EISA. 
16

Table 8. Data Sources for NEEDS v3.02 EISA

Data Source1 Data Source Documentation 

DOE's Form EIA-860 

(2005) 

DOE's Form EIA-860 is an annual survey of utility power plants at the 

generator level. It contains data such as summer, winter and nameplate 

capacity, location (state and county), status, prime mover, primary energy 

source, in-service year, and a generator-level cogenerator flag. 

DOE's Form EIA-767 

(2005) 

DOE's Form EIA-767 is an annual survey, "Steam-Electric Plant Operation 

and Design Report", that contains data for steam boilers such as fuel 

quantity and quality; boiler identification, location, status, and design 

information; and post-combustion NOX control, FGD scrubber and 

particulate collector device information. Note that boilers in plants with 

less than 10 MW do not report all data elements. The relationship 

between boilers and generators is also provided. Note that boilers and 

generators are not necessarily in a one-to-one correspondence. 

NERC Electricity Supply 

and Demand (ES&D) 

database (2006) 

The NERC ES&D is released annually. It contains generator-level 

information such as summer, winter and nameplate capacity, state, NERC 

region and sub-region, status, primary fuel and on-line year. 

EIA’s Annual Energy 

Outlook (AEO 2008) 

The Energy Information Administration (EIA) Annual Energy Outlook 

presents annually updated forecasts of energy supply, demand and prices 

covering a 20-25 year time horizon. The projections are based on results 

from EIA’s National Energy Modeling System (NEMS). Information from 

AEO 2008, such as heat rates and renewable builds in response to state 

renewable portfolio standards (RPS) were used in NEEDS V3.02 EISA. 

Global Energy Decisions 

New Entrants database 

(August 2007) 

Global Energy’s New Entrants database has information on new power 

plant builds, rerates and retirements. This was used in NEEDS v3.02 

EISA for information on planned-committed units. 

EPA's Emission Tracking 

System (ETS 2006) 

The Emission Tracking System (ETS) database is updated quarterly and 

certified annually. It contains boiler-level information such as primary fuel, 

heat input, SO2 and NOX controls, and SO2, NOX and CO2 emissions. 

NEEDS V3.02 EISA used ETS data for developing emission rate and 

post-combustion control information. 

Utility and RPO (Regional 

Planning Organizations) 

Comments 

Comments from selected U.S. utilities and RPOs regarding the population 

in NEEDS as well as unit characteristics were used in NEEDS V3.02 

EISA. 

1

Indicated under “Data Source” are the primary issue dates of the indicated data sources that were used. Other 

vintages of these data sources were also used in instances where data were not available for the indicated 

issue date or where there were methodological reasons for using other vintages of the data. 
17

Table 9. Rules Used in Populating NEEDS v3.02 EISA 

Scope

Geographic Excluded units in Alaska or Hawaii 

Capacity Excluded units with reported nameplate, summer and winter capacity of zero 

Status Excluded units on long-term scheduled maintenance or retired (i.e. units with 

status codes “OS” or “RE” in EIA Forms) 

Status of boiler(s) and associated generator(s) were taken into account for 

determining operation status 

Planned or 

Future Units 

Included planned units that had broken ground or secured financing and were 

expected to be online by the end of 2011 

Firm/Non-firm 

Electric Sales 

Excluded non-utility onsite generators that do not produce electricity for sale to 

the grid. 

Excluded all mobile and distributed generators 

Table 10. Hierarchy of Data Sources for Capacity 

in NEEDS v3.02 EISA 

Sources Presented in Hierarchy 

Capacity from Utility/Regional Planning 

Organization(RPO) Comments

2005 EIA 860 Summer Capacity 

NERC ES&D 2006 Summer Capacity 

2005 EIA 860 Winter Capacity 

NERC ES&D 2006 Winter Capacity 

2005 EIA 860 Nameplate Capacity 

Notes: 

1. If a unit’s capacity was shown as zero, it was not included in 

NEEDS v3.02 EISA. 
18

Table 11. Summary Population (through 2005) in NEEDS v3.02 EISA

Plant Type Number of Units Capacity (MW) 

Biomass 126 2,124 

Coal Steam 1,247 306,062 

Combined Cycle 1,493 172,567 

Combustion Turbine 5,248 131,366 

Fossil Waste 19 581 

Geothermal 201 2,194 

Hydro 3,724 77,414 

IGCC 4 529 

Landfill Gas 572 892 

Municipal Solid Waste 172 2,054 

Non-Fossil Waste 48 530 

Nuclear 104 101,099 

O/G Steam 698 113,618 

Pumped Storage 150 20,864 

Solar 18 411 

Tires 3 44 

Wind 275 8,711 

Total 14,102 941,060 
19

Table 12. Data Sources for Unit Configuration in NEEDS v3.02 EISA 

Unit 

Component 

Primary Data 

Source 

Secondary Data 

Source 

Tertiary Data 

Source 

 Other Sources Default 

Firing Type Utility/RPO 

Comments 

2005 EIA 767 - - - 

Bottom Type Utility/RPO 

Comments 

2005 EIA 767 - - Dry 

SO2 

Pollution 

Control 

NSR Settlement 

or Utility/RPO 

Comments 

EPA’s Emission 

Tracking System 

(ETS) - 2006 

2005 EIA 767 

See Note1

No 

Control 

NOX

Pollution 

Control 

NSR Settlement 

or Utility/RPO 

Comments 

EPA’s Emission 

Tracking System 

(ETS) - 2006 

2005 EIA 767 See Note1 No 

Control 

Particulate 

Matter 

Control 

NSR Settlement 

or Utility/RPO 

Comments 

EPA’s Emission 

Tracking System 

(ETS) - 2006 

2005 EIA 767 1999 Hg ICR 

 - 

1

In addition to the primary, secondary and tertiary data sources listed here, the web sites of generating unit owners and 

operators were also consulted. 

8. Title IV SO2 Allowance Bank Estimate 

The Title IV SO2 bank going into 2012 was assumed to be 1.6 million allowances. This 

was based on calculations that assumed increasing overall emissions following the 

remand of CAIR. Since early 2009, when Base Case v3.02 EISA was completed, SO2

emissions have instead continued to decline. Even if the Title IV bank does not decline 

to 1.6 million allowances by 2012, EPA believes there will be little or no resulting effect 

on the costs and emissions resulting from the Transport Rule or similar policies that do 

not directly relate to Title IV allowances.
20

9. Run year mapping 

Table 13. Run Years and Analysis Year Mapping Used in the IPM Base 

Case v3.02 EISA 

Run Year Year Mapping 

2012 2012 – 2013 

2015 2014 – 2017 

2020 2018 – 2022 

2025 2023 – 2027 

10. Financial Assumptions 

Table 14. Capital Charge Rates and Real Discount Rates by Plant Type 

in Base Case v3.02 EISA 

Investment Technology Capital 

Charge 

Rate 

Discount 

Rate 

Environmental Retrofits 11.4% 5.5% 

Conventional Pulverized Coal 11.2% 5.5% 

Advanced Combined Cycle 12.2% 6.1% 

Advanced Combustion Turbine 13.0% 6.9% 

Nuclear 10.8% 5.5% 

Renewable Generation Technologies 12.2% 6.1% 

11. Small-unit Retrofit Options Present in Policy Case Model 

Runs 

In the proposed Transport Rule base case (TR_Base_Case), coal-fired EGUs under 100 

MW capacity do not have the option of retrofitting FGD or SCR. In model runs other 

than the Transport Rule base case, coal-fired EGUs greater than 25 MW do have the 

option of retrofitting FGD and SCR. Because FGD and SCR retrofits to such small units 

are very costly in any case, EPA believes the absence of that option has little or no effect 

on emissions or cost results in the base case. A summary of available SO2 control 

options, based on an approximate extrapolation from retrofit costs for larger capacity 
21

units, appears in Table 15 below.7

 SCR costs for these units follow the same formula 

described above in Section 3. 

Table 15. Application of SO2 Retrofit Options for Coal-fired Units 

at 25 MW and below 100 MW Capacity (2006$) 

Scrubber Type 

Limestone Forced Oxidation 

(LSFO) 

Minimum Cutoff: ≥ 25 MW 

Maximum Cutoff: < 100 MW 

Lime Spray Dryer 

(LSD) 

Minimum Cutoff: ≥

25 MW 

Maximum Cutoff: < 

100 MW 

Capacity (MW) 25 50 75 25 50 75 

Capital Cost ($/kW) 1,368 934 748 487 396 350 

Fixed O&M ($/kWyear) 39.7 28.5 23.4 21.1 16.1 13.8 

Variable O&M 

(mills/kWh) 1.47 1.47 1.47 2.50 2.50 2.50 

12. Unit-specific Adjustments Present in Some Model Runs 

In the course of deriving budgets for the proposed Transport Rule, some EGUs were 

noted as demonstrating unusually high emissions rates in model results relative to the 

emissions rates of the same units in recent data. As a result, the rates of 30 units were 

constrained in subsequent runs to provide more accurate emissions results for those units. 

Additionally, 3 units possessed existing controls not accounted for in NEEDS; these were 

accounted for with removal percentages assumed for their emissions. 

These adjustments are present neither in the proposed Transport Rule base case nor in the 

analysis of significant contribution using the Air Quality Assessment Tool. They are 

present in runs representing the three remedy options for the proposed Transport Rule 

and in the A–4 analysis runs conducted for Regulatory Impact Analysis. The units and 

their rates are listed below in Table 16. 

 

7

 These LSFO and LSD match the characteristics shown in Table 5.2 of the v3.0 documentation referenced 

earlier, including removal rates of 95% and 90% respectively. 
22

Table 16. Unit-specific Adjustments to Transport Rule Remedy Runs 

NEEDS ID ORIS 

Code 

Plant Name Unit ID Pollutant Emissions Rate Limit 

(lbs/mmBTU) or Other 

Modification 

568_B_BHB3 568 Bridgeport Station BHB3 Annual SO2 0.131 

856_B_1 856 E D Edwards 1 Annual SO2 0.461 

856_B_2 856 E D Edwards 2 Annual SO2 0.457 

856_B_3 856 E D Edwards 3 Annual SO2 0.429 

2516_B_1 2516 Northport 1 Annual SO2 0.132 

2516_B_2 2516 Northport 2 Annual SO2 0.344 

2516_B_3 2516 Northport 3 Annual SO2 0.299 

2516_B_4 2516 Northport 4 Annual SO2 0.244 

2517_B_3 2517 Port Jefferson 3 Annual SO2 0.294 

2517_B_4 2517 Port Jefferson 4 Annual SO2 0.305 

3788_B_1 3788 Potomac River 1 Annual SO2 0.383 

3788_B_2 3788 Potomac River 2 Annual SO2 0.343 

3803_B_1 3803 Chesapeake 1 Annual SO2 0.891 

3803_B_2 3803 Chesapeake 2 Annual SO2 0.885 

3803_B_3 3803 Chesapeake 3 Annual SO2 0.895 

3803_B_4 3803 Chesapeake 4 Annual SO2 0.939 

2378_B_1 2378 B L England 1 Annual SO2 Controls achieve 93% removal 

2240_B_8 2240 Lon Wright 8 Annual SO2 0.651 

2277_B_1 2277 Sheldon 1 Annual SO2 0.590 

2277_B_2 2277 Sheldon 2 Annual SO2 0.567 

2291_B_1 2291 North Omaha 1 Annual SO2 0.754 

2291_B_5 2291 North Omaha 5 Annual SO2 0.721 

59_B_1 59 Platte 1 Annual SO2 0.745 

60_B_1 60 Whelan Energy Center 1 Annual SO2 0.696 

6077_B_1 6077 Gerald Gentleman 1 Annual SO2 0.615 

6077_B_2 6077 Gerald Gentleman 2 Annual SO2 0.601 

6096_B_1 6096 Nebraska City 1 Annual SO2 0.727 

8048_B_1 8048 Anclote 1 Annual NOX 0.183 

8048_B_2 8048 Anclote 2 Annual NOX 0.136 

619_B_PRV3 619 Riviera PRV3 Annual NOX 0.208 

619_B_PRV4 619 Riviera PRV4 Annual NOX 0.307 

136_B_1 136 Seminole 1 Annual NOX Controls achieve 90% removal 

136_B_2 136 Seminole 2 Annual NOX Controls achieve 90% removal 

Still other controls were hardwired in all 3.02 EISA modeling, both base and policy 

cases, to account for additional controls not present in NEEDS 3.02 EISA but nonetheless 

known to be in operation no later than 2012. These are listed in Table 17 below. 
23

Table 17. Additional Unit-specific Controls in All Transport Rule Runs 

NEEDS ID ORIS 

Code 

Plant Name Unit ID Control 

6002_B_2 6002 James H Miller Jr 2 Wet Scrubber 

6705_B_1 6705 Warrick 1 Wet Scrubber 

6705_B_2 6705 Warrick 2 Wet Scrubber 

6705_B_3 6705 Warrick 3 Wet Scrubber 

6705_B_4 6705 Warrick 4 Wet Scrubber 

113_B_3 113 Cholla 3 Wet Scrubber 

113_B_4 113 Cholla 4 Wet Scrubber 

2850_B_1 2850 J M Stuart 1 Wet Scrubber 

2850_B_2 2850 J M Stuart 2 Wet Scrubber 

2850_B_3 2850 J M Stuart 3 Wet Scrubber 

2850_B_4 2850 J M Stuart 4 Wet Scrubber 

983_B_1 983 Clifty Creek 1 Wet Scrubber 

983_B_2 983 Clifty Creek 2 Wet Scrubber 

983_B_3 983 Clifty Creek 3 Wet Scrubber 

983_B_4 983 Clifty Creek 4 Wet Scrubber 

983_B_5 983 Clifty Creek 5 Wet Scrubber 

983_B_6 983 Clifty Creek 6 Wet Scrubber 

994_B_1 994 Petersburg 1 Wet Scrubber 

994_B_2 994 Petersburg 2 Wet Scrubber 

1082_B_3 1082 Walter Scott Jr. Energy Center 3 Wet Scrubber 

6664_B_101 6664 Louisa 101 Wet Scrubber 

3788_B_3 3788 Potomac River 3 Wet Scrubber 

3788_B_4 3788 Potomac River 4 Wet Scrubber 

3788_B_5 3788 Potomac River 5 Wet Scrubber 

2823_B_B1 2823 Milton R Young B1 SCR 

2866_B_7 2866 W H Sammis 7 SCR 

8069_B_2 8069 Huntington 2 Wet Scrubber 

525_B_H1 525 Hayden H1 Dry Scrubber 

525_B_H2 525 Hayden H2 Dry Scrubber 

1001_B_1 1001 Cayuga 1 Wet Scrubber 

6113_B_4 6113 Gibson 4 Wet Scrubber 

6177_B_U2B 6177 Coronado U2B SCR 

4941_B_1 4941 Navajo 1 Wet Scrubber 

4941_B_2 4941 Navajo 2 Wet Scrubber 

4941_B_3 4941 Navajo 3 Wet Scrubber 

13. 2012 Feasibility Limits Present in Policy Case Model Runs 

Because the 2012 run year represents years within eighteen months of the present, it is 
24

unrealistic to expect advanced SO2 and NOX post-combustion controls to be operating or 

new units to be planned and constructed in 2012 in response to a policy change. 

Therefore, in all runs other than the proposed Transport Rule base case, new builds of all 

units and retrofits of FGD, SCR, and SNCR are limited to those built in the base case 

(TR_Base_Case). 

Appendix I. Background on the Integrated Planning Model 

(IPM), Its Uses, and Related Peer Review Activities 

EPA uses the Integrated Planning Model (IPM) to analyze the projected impact of 

environmental policies on the electric power sector in the 48 contiguous states and the 

District of Columbia. The model was developed by ICF Resources and IPM® is a 

registered trademark of ICF Resources, Inc. 

IPM is a multi-regional, dynamic, deterministic linear programming model of the U.S. 

electric power sector. The model provides forecasts of least-cost capacity expansion, 

electricity dispatch, and emission control strategies for meeting energy demand and 

environmental, transmission, dispatch, and reliability constraints. IPM provides both a 

broad and detailed analysis of the emission control options available to the power sector 

(e.g., installation of emission controls, power generation adjustments, fuel use changes, 

and national, regional/state, and local air emissions changes) along with the economic 

impacts of these control options in terms of costs, wholesale electricity prices, closures, 

allowance values, etc.. 

EPA’s application of IPM is a very detailed, data intensive representation of the U.S. 

power sector. A great deal of effort is expended to ensure that IPM is populated with 

high quality input data and that its assumptions are based on latest engineering and 

economic experience. The data and assumptions are fully documented and publicly 

available on EPA’s web site. Use of such a bottom-up model imposes scientific and 

technical discipline on EPA that serves to improve the decision making process and 

increase opportunities for broad public & expert review and input. 

EPA sponsors periodic independent formal peer review of IPM, covering the model itself 

and EPA’s key modeling input assumptions. Examples include reviews by separate 

panels of independent experts of the model’s coal supply and transportation assumptions, 

natural gas assumptions, and model formulation. 

In addition to formal peer review, the rulemaking process offers opportunities for expert 

review and comment by operators of the electricity sector that is represented in IPM, 

stakeholders affected by the policies being modeled, and developers of other models of 

the U.S. electricity sector. This feedback provides a highly detailed reality check of input 
25

assumptions, model representation, and model results. EPA is required to respond to 

every significant comment submitted. Comments on IPM have been solicited in most of 

the major air regulations that EPA has promulgated in the last 15 years. Such efforts date 

back to the extensive review by energy and environmental modeling experts from states, 

industry and other groups during the 2 years of the OTAG process in 1997-1998 and 

Science Advisory Board review of IPM as part of the CAAA Section 812 prospective 

study 1997–1999. 

IPM has also been used by states (e.g., for RGGI, WRAP, OTAG), other Federal 

agencies (e.g., FERC, GAO), environmental groups (including the Clean Air Task 

Force), and industry (e.g., TVA, SoCAL), all of whom subject the model to their own 

review procedures. 

Appendix II. Natural Gas Supply Curves 

The supply curves below specify annual price and volume relationships at the Henry 

Hub. For each listed step the price applies for all increments of supply greater than the 

value shown in the preceding step up to and including the supply level indicated in the 

current step. For example, in 2012 a price of $4.60 (2006$) would secure natural gas 

supplies for the electric sector beyond the 2,752 TBtu provided in the preceding step and 

up to a level of 2,932 TBtu. 

Year Price 

(2006$/MMBtu) 

Gas Supply to 

Electric Sector 

(TBtu) 

Non-Electric 

Gas Demand

(TBtu) 

Total Gas 

Supply 

(TBtu) 

2012 4.50 2,752 19,836 22,588 

2012 4.60 2,932 19,685 22,617 

2012 4.70 3,107 19,538 22,645 

2012 4.80 3,278 19,395 22,673 

2012 4.90 3,444 19,256 22,700 

2012 5.01 3,607 19,120 22,727 

2012 5.10 3,765 18,988 22,753 

2012 5.20 3,921 18,859 22,779 

2012 5.30 4,072 18,733 22,804 

2012 5.40 4,220 18,610 22,829 

2012 5.49 4,364 18,489 22,853 

2012 5.60 4,505 18,372 22,877 

2012 5.70 4,643 18,257 22,900 

2012 5.80 4,778 18,145 22,923 

2012 5.90 4,910 18,036 22,946 

2012 6.00 5,040 17,928 22,968 

2012 6.10 5,167 17,823 22,990 

2012 6.20 5,292 17,720 23,012 

2012 6.30 5,413 17,620 23,033 

2012 6.40 5,533 17,521 23,054 

2012 6.50 5,651 17,424 23,075 
26

Year Price 

(2006$/MMBtu) 

Gas Supply to 

Electric Sector 

(TBtu) 

Non-Electric 

Gas Demand

(TBtu) 

Total Gas 

Supply 

(TBtu) 

2012 6.60 5,766 17,329 23,095 

2012 6.70 5,879 17,236 23,115 

2012 6.80 5,990 17,145 23,135 

2012 6.90 6,100 17,055 23,155 

2012 7.00 6,207 16,967 23,174 

2012 7.10 6,312 16,881 23,193 

2012 7.20 6,416 16,796 23,212 

2012 7.31 6,518 16,713 23,231 

2012 7.40 6,618 16,631 23,249 

2012 7.50 6,717 16,550 23,267 

2012 7.60 6,814 16,471 23,285 

2012 7.70 6,910 16,393 23,303 

2012 7.80 7,003 16,317 23,320 

2012 7.90 7,096 16,241 23,337 

2012 8.00 7,187 16,167 23,354 

2012 8.10 7,277 16,094 23,371 

2012 8.20 7,365 16,023 23,388 

2012 8.30 7,452 15,952 23,404 

2012 8.40 7,537 15,883 23,420 

2012 8.50 7,622 15,814 23,436 

2012 8.60 7,705 15,747 23,452 

2012 8.70 7,788 15,680 23,468 

2012 8.80 7,869 15,615 23,484 

2012 8.90 7,949 15,550 23,499 

2012 9.00 8,027 15,487 23,514 

2012 9.10 8,105 15,424 23,529 

2012 9.20 10,752 35,202 45,954 

2015 4.50 2,374 20,321 22,695 

2015 4.60 2,559 20,165 22,724 

2015 4.70 2,741 20,012 22,753 

2015 4.80 2,917 19,864 22,781 

2015 4.90 3,089 19,720 22,808 

2015 5.01 3,256 19,579 22,835 

2015 5.10 3,420 19,442 22,861 

2015 5.20 3,579 19,308 22,887 

2015 5.30 3,735 19,177 22,912 

2015 5.40 3,887 19,050 22,937 

2015 5.49 4,037 18,925 22,962 

2015 5.60 4,183 18,804 22,986 

2015 5.70 4,325 18,685 23,010 

2015 5.80 4,465 18,568 23,033 

2015 5.90 4,601 18,455 23,056 

2015 6.00 4,736 18,343 23,079 

2015 6.10 4,867 18,234 23,101 

2015 6.20 4,995 18,128 23,123 

2015 6.30 5,122 18,023 23,145 

2015 6.40 5,245 17,921 23,166 

2015 6.50 5,367 17,820 23,187 
27

Year Price 

(2006$/MMBtu) 

Gas Supply to 

Electric Sector 

(TBtu) 

Non-Electric 

Gas Demand

(TBtu) 

Total Gas 

Supply 

(TBtu) 

2015 6.60 5,486 17,722 23,208 

2015 6.70 5,603 17,626 23,228 

2015 6.80 5,717 17,531 23,248 

2015 6.90 5,830 17,438 23,268 

2015 7.00 5,941 17,347 23,288 

2015 7.10 6,050 17,257 23,307 

2015 7.20 6,157 17,169 23,326 

2015 7.31 6,262 17,083 23,345 

2015 7.40 6,366 16,998 23,364 

2015 7.50 6,468 16,914 23,382 

2015 7.60 6,568 16,832 23,400 

2015 7.70 6,666 16,752 23,418 

2015 7.80 6,764 16,672 23,436 

2015 7.90 6,859 16,594 23,453 

2015 8.00 6,952 16,518 23,470 

2015 8.10 7,045 16,442 23,487 

2015 8.20 7,136 16,368 23,504 

2015 8.30 7,227 16,295 23,521 

2015 8.40 7,316 16,222 23,538 

2015 8.50 7,403 16,151 23,554 

2015 8.60 7,489 16,082 23,570 

2015 8.70 7,573 16,013 23,586 

2015 8.80 7,657 15,945 23,602 

2015 8.90 7,740 15,878 23,618 

2015 9.00 7,821 15,812 23,633 

2015 9.10 7,901 15,747 23,648 

2015 9.20 10,007 36,541 46,547 

2020 4.50 1,393 21,191 22,584 

2020 4.60 1,586 21,027 22,613 

2020 4.70 1,775 20,868 22,642 

2020 4.80 1,958 20,713 22,670 

2020 4.90 2,137 20,562 22,698 

2020 5.01 2,311 20,414 22,725 

2020 5.10 2,481 20,271 22,752 

2020 5.20 2,647 20,131 22,778 

2020 5.30 2,809 19,995 22,804 

2020 5.40 2,968 19,862 22,829 

2020 5.49 3,123 19,731 22,854 

2020 5.60 3,274 19,604 22,878 

2020 5.70 3,422 19,480 22,902 

2020 5.80 3,567 19,359 22,926 

2020 5.90 3,709 19,240 22,949 

2020 6.00 3,849 19,124 22,972 

2020 6.10 3,984 19,010 22,994 

2020 6.20 4,118 18,898 23,016 

2020 6.30 4,249 18,789 23,038 

2020 6.40 4,377 18,682 23,059 

2020 6.50 4,503 18,577 23,080 
28

Year Price 

(2006$/MMBtu) 

Gas Supply to 

Electric Sector 

(TBtu) 

Non-Electric 

Gas Demand

(TBtu) 

Total Gas 

Supply 

(TBtu) 

2020 6.60 4,627 18,474 23,101 

2020 6.70 4,749 18,373 23,122 

2020 6.80 4,868 18,274 23,142 

2020 6.90 4,985 18,177 23,162 

2020 7.00 5,100 18,082 23,182 

2020 7.10 5,213 17,988 23,201 

2020 7.20 5,324 17,897 23,220 

2020 7.31 5,433 17,806 23,239 

2020 7.40 5,541 17,718 23,258 

2020 7.50 5,646 17,630 23,276 

2020 7.60 5,749 17,545 23,294 

2020 7.70 5,852 17,460 23,312 

2020 7.80 5,953 17,377 23,330 

2020 7.90 6,052 17,296 23,348 

2020 8.00 6,149 17,216 23,365 

2020 8.10 6,245 17,137 23,382 

2020 8.20 6,340 17,059 23,399 

2020 8.30 6,433 16,983 23,416 

2020 8.40 6,526 16,907 23,433 

2020 8.50 6,616 16,833 23,449 

2020 8.60 6,705 16,760 23,465 

2020 8.70 6,793 16,688 23,481 

2020 8.80 6,880 16,617 23,497 

2020 8.90 6,966 16,547 23,513 

2020 9.00 7,051 16,478 23,529 

2020 9.10 7,134 16,410 23,544 

2020 9.20 9,557 36,896 46,453 

2025 4.50 2,585 20,764 23,349 

2025 4.60 2,780 20,600 23,380 

2025 4.70 2,969 20,441 23,410 

2025 4.80 3,153 20,286 23,439 

2025 4.90 3,333 20,135 23,468 

2025 5.01 3,509 19,987 23,496 

2025 5.10 3,680 19,844 23,524 

2025 5.20 3,847 19,704 23,551 

2025 5.30 4,010 19,568 23,578 

2025 5.40 4,170 19,434 23,604 

2025 5.49 4,326 19,304 23,630 

2025 5.60 4,478 19,177 23,655 

2025 5.70 4,627 19,053 23,680 

2025 5.80 4,774 18,931 23,705 

2025 5.90 4,917 18,812 23,729 

2025 6.00 5,057 18,696 23,753 

2025 6.10 5,194 18,582 23,776 

2025 6.20 5,329 18,471 23,799 

2025 6.30 5,461 18,361 23,822 

2025 6.40 5,590 18,254 23,844 

2025 6.50 5,717 18,149 23,866 
29

Year Price 

(2006$/MMBtu) 

Gas Supply to 

Electric Sector 

(TBtu) 

Non-Electric 

Gas Demand

(TBtu) 

Total Gas 

Supply 

(TBtu) 

2025 6.60 5,842 18,046 23,888 

2025 6.70 5,964 17,945 23,909 

2025 6.80 6,084 17,846 23,930 

2025 6.90 6,202 17,749 23,951 

2025 7.00 6,318 17,654 23,972 

2025 7.10 6,432 17,560 23,992 

2025 7.20 6,544 17,468 24,012 

2025 7.31 6,654 17,378 24,032 

2025 7.40 6,763 17,289 24,052 

2025 7.50 6,869 17,202 24,071 

2025 7.60 6,974 17,116 24,090 

2025 7.70 7,077 17,032 24,109 

2025 7.80 7,179 16,949 24,128 

2025 7.90 7,279 16,867 24,146 

2025 8.00 7,377 16,787 24,164 

2025 8.10 7,474 16,708 24,182 

2025 8.20 7,570 16,630 24,200 

2025 8.30 7,664 16,554 24,218 

2025 8.40 7,757 16,478 24,235 

2025 8.50 7,848 16,404 24,252 

2025 8.60 7,938 16,331 24,269 

2025 8.70 8,027 16,259 24,286 

2025 8.80 8,115 16,188 24,303 

2025 8.90 8,201 16,118 24,319 

2025 9.00 8,286 16,049 24,335 

2025 9.10 8,370 15,981 24,351 

2025 9.20 10,759 37,013 47,772 
30

Appendix III. New Source Review Settlements: Incremental Changes from EPA Base C

Company 

and Plant State Unit 

SETTLEMENT ACTIONS Allow

Retir

Retire/Repower SO2 Control Nox Control PM or Mercury Control 

Action Effective Date Equipme nt Percent Removal or Rate Effective Date Equipme nt Rate Effective Date Equipme nt Rat e Effective Date Retir

Kentucky Utilities Company 

EW Brown 

Generating 

Station 

Kentucky Unit 3 Install FGD 97% or 0.100 12/31/10 

Install and 

continuou

sly 

operate 

SCR by 

12/31/201

2, 

continuou

sly 

operate 

low NOX

boiler and 

OFA. 

0.07 12/31/12 

Continuou

sly 

operate 

ESP 

0.03 12/31/10 

KU must surrendeSO2 allo2008 or vintage b1, 2009. surplus Nallowancbe surrethrough 

American Electric Power 

Eastern System-Wide 

Annual Cap (tons) Year 

Annual 

Cap 

(tons) 

Year 

NOX and allowancwould hamade avemission reductionpursuant Consent must be surrende

450,000 2010 96,000 2009 450,000 2011 92,500 2010 420,000 2012 92,500 2011 350,000 2013 85,000 2012 340,000 2014 85,000 2013 275,000 2015 85,000 2014 260,000 2016 75,000 2015 235,000 2017 72,000 2016 and thereafter 184,000 2018 174,000 2019 and 

thereafter 
31

Company 

and Plant State Unit 

SETTLEMENT ACTIONS Allow

Retir

Retire/Repower SO2 Control Nox Control PM or Mercury Control 

Action Effective Date Equipme nt Percent Removal or Rate Effective Date Equipme nt Rate Effective Date Equipme nt Rat e Effective Date Retir

At least 

600MW 

from 

various 

units 

West 

Virginia 

Sporn 

1 – 4 

Retire, 

retrofit, or 

re-power 

12/31/18 

Virginia 

Clinch 

River 

1 – 3 

Indiana 

Tanner

s 

Creek 

1 – 3 

West 

Virginia 

Kamm

er 

1 – 3 

Amos West Virginia 

Unit 1 

Install 

and 

continuou

sly 

operate 

FGD 

12/31/09 

Install and 

continuou

sly 

operate 

SCR 

01/01/08 

Unit 2 12/31/10 01/01/09 Unit 3 12/31/09 01/01/08 

Big Sandy Kentucky 

Unit 1 

Burn only coal with no more than 1.75 lb/MMBtu annual average 

Date of 

entry 

Continuously operate low NOXburners 

Date of 

entry 

Unit 2 

Install and continuously operate FGD 

12/31/15 

Install and continuously operate SCR 

01/01/09 

Cardinal Ohio 

Units 1, 

2 

Install 

and 

continuou

sly 

operate 

FGD 

12/31/08 

Install and 

continuou

sly 

operate 

SCR 

01/01/09 

Continuou

sly 

operate 

ESP 

0.03 12/31/09 

Unit 3 12/31/12 

Clinch 

River Virginia Units 1 – 3 

Annual Cap (tons) Year 

Continuou

sly 

operate 

low NOX

burners 

Date of 

entry 

21,700 2010 21,700 2011 21,700 2012 21,700 2013 21,700 2014 16,300 2015 onwards 
32

Company 

and Plant State Unit 

SETTLEMENT ACTIONS Allow

Retir

Retire/Repower SO2 Control Nox Control PM or Mercury Control 

Action Effective Date Equipme nt Percent Removal or Rate Effective Date Equipme nt Rate Effective Date Equipme nt Rat e Effective Date Retir

Conesville Ohio 

Units 1, 

2 

Retire, 

retrofit, or 

re-power 

Date of 

entry 

Unit 3 12/31/12 Unit 4 

Install and continuously operate FGD 

12/31/10 

Install and continuously operate SCR 

12/31/10 

Units 5, 

6 

Upgrade 

existing 

FGD 

95% 12/31/09 

Continuou

sly 

operate 

low NOX

burners 

Date of 

entry 

Gavin Ohio Units 1, 2 

Install 

and 

continuou

sly 

operate 

FGD 

Date of 

entry 

Install and 

continuou

sly 

operate 

SCR 

01/01/09 

Glen Lyn Virginia Units 5, 6 

Burn only coal with no more than 1.75 lb/MMBtu annual average 

Date of 

entry 

Continuously operate low NOXburners 

Date of 

entry 

Kammer West Virginia Units 1 – 3 Plant-wide annual cap: 35,000 01/01/12 

Continuously operate over-fire air 

Date of 

entry 

Kanawha 

River 

West 

Virginia 

Units 1, 

2 

Burn only coal with no more than 1.75 lb/MMBtu annual average 

Date of 

entry 

Continuously operate low NOXburners 

Date of 

entry 

Mitchell West Virginia Units 1, 2 

Install 

and 

continuou

sly 

operate 

FGD 

12/31/07 

Install and 

continuou

sly 

operate 

SCR 

01/01/09 

Mountainee

r 

West 

Virginia Unit 1 

Install and continuously operate FGD 

12/31/07 

Install and continuously operate SCR 

01/01/08 

Muskingum 

River Ohio 

Units 

1 – 4 

Retire, retrofit, or re-power 

12/31/15 

Unit 5 

Install and continuously operate FGD 

12/31/15 

Install and continuously operate SCR 

01/01/08 

Continuously operate ESP 

0.03 12/31/02 
33

Company 

and Plant State Unit 

SETTLEMENT ACTIONS Allow

Retir

Retire/Repower SO2 Control Nox Control PM or Mercury Control 

Action Effective Date Equipme nt Percent Removal or Rate Effective Date Equipme nt Rate Effective Date Equipme nt Rat e Effective Date Retir

Picway Ohio Unit 9 

Continuously operate low NOXburners 

Date of 

entry 

Rockport Indiana 

Unit 1 

Install 

and 

continuou

sly 

operate 

FGD 

12/31/17 

Install and 

continuou

sly 

operate 

SCR 

12/31/17 

Unit 2 12/31/19 12/31/19 

Sporn West Virginia Unit 5 Retire, retrofit, or re-power 12/31/13 

Tanners 

Creek Indiana 

Units 

1 – 3 

Burn only coal with no more than 1.2 lb/MMBtu annual average 

Date of 

entry 

Continuously operate low NOXburners 

Date of 

entry 

Unit 4 

Burn only coal with no more than 1.2% sulfur content annual average 

Continuously operate over-fire air 

East Kentucky Power Cooperative Inc. 

Dale Plant Kentucky Units 1, 2 

Install and 

continuou

sly 

operate 

low NOX

burners 

by 

10/31/200

7 

0.46 01/01/08 

EKPC msurrendeNOX alloimmediathe ARP3,107 unNOX SIP EKPC msurrendeSO2 allo

System-wide 

Systemwide 12-

month 

rolling 

tonnage 

limits 

apply 

12-month rolling limit 

(tons) 

Start of 12-

month 

cycle 

All units 

must 

operate 

low NOX

boilers 

12-month 

rolling 

limit 

(tons) 

Start of 12-

month 

cycle 

PM 

control 

devices 

must be 

operated 

continuou

sly 

systemwide, 

ESPs 

0.03 1 year from entry date 

All sur

allowan

be sur

each 

beginnin
34

Company 

and Plant State Unit 

SETTLEMENT ACTIONS Allow

Retir

Retire/Repower SO2 Control Nox Control PM or Mercury Control 

Action Effective Date Equipme nt Percent Removal or Rate Effective Date Equipme nt Rate Effective Date Equipme nt Rat e Effective Date Retir

57,000 10/01/08 11,500 01/01/08 

must be 

optimized 

within 270 

days of 

entry 

date, or 

EKPC 

may 

choose to 

submit a 

PM 

Pollution 

Control 

Upgrade 

Analysis. 

40,000 07/01/11 8,500 01/01/13 28,000 01/01/13 8,000 01/01/15 

Spurlock Kentucky 

Unit 1 

Install and continuously operate FGD 

95% or 0.1 6/30/2011 

Continuously operate SCR 

0.12 for 

Unit 1 

until 

01/01/20

13, at 

which 

point the 

unit limit 

drops to 

0.1. 

Prior to 

01/01/20

13, the 

combine

d 

average 

when 

both 

units are 

operating 

must be 

no more 

than 0.1 

60 days 

after entry 

Unit 2 

Install and continuously operate FGD by 10/1/2008 

95% or 0.1 1/1/2009 

Continuously operate SCR and OFA 

0.1 for 

Unit 2, 

0.1 

combine

d 

average 

when 

both 

units are 

operating 
35

Company 

and Plant State Unit 

SETTLEMENT ACTIONS Allow

Retir

Retire/Repower SO2 Control Nox Control PM or Mercury Control 

Action Effective Date Equipme nt Percent Removal or Rate Effective Date Equipme nt Rate Effective Date Equipme nt Rat e Effective Date Retir

Dale Plant Kentucky Units 3, 4 

EKPC may choose to retire Dale 3 and 4 in lieu of installing controls in Cooper 2 

12/31/2012 

Cooper Kentucky Unit 2 

If EKPC opts to install controls rather than retiring Dale, it must install and continuously operate FGD or equiv. technology 

95% or 0.10 12/31/11 

If EKPC elects to install controls, it must continuously operate SCR or install equiv. technology 

0.08 (or 

90% if 

non-SCR 

technolo

gy is 

used) 

12/31/12 

Nevada Power Company 

Clark 

Generating 

Station 

Nevada 

Unit 5 

Units may only fire natural gas 

Increase water injection immediately, then install and operate ultra-low NOXburners (ULNBs) or equivalent technology. In 2009, Units 5 and 8 may not emit more than 180 tons combined 

5ppm 1-

hour 

average 

12/31/08 

(ULNB 

installation)

, 01/30/09 

(1-hour 

average) 

Units 6, 

7 

12/31/09 

(ULNB 

installation)

, 01/30/10 

(1-hour 

average) 

Unit 8 

12/31/08 

(ULNB 

installation)

, 01/30/09 

(1-hour 

average) 

PSEG FOSSIL 

Kearny New Jersey Units 7, 8 Retire units 01/01/07 

Allow

alloc

Kearny

and Me

only be 

the op

needs 

units, 
36

Company 

and Plant State Unit 

SETTLEMENT ACTIONS Allow

Retir

Retire/Repower SO2 Control Nox Control PM or Mercury Control 

Action Effective Date Equipme nt Percent Removal or Rate Effective Date Equipme nt Rate Effective Date Equipme nt Rat e Effective Date Retir

Hudson New Jersey Unit 2 

Install Dry FGD (or approved alt. technology) and continually operate 

0.15 12/31/10 

Install SCR (or approved tech) and continually operate 

0.1 12/31/10 

Install Baghouse (or approved technology) 

0.01

5 12/31/10 

su

allowan

be surr

Within 9

amende

Decree

must s

1,23

Allowa

8,56

Allowa

already 

to or gen

the un

here. 

allowan

be sur

with the 

of thos

Annual Cap (tons) Year 

Annual 

Cap 

(tons) 

Year 

5,547 2007 3,486 2007 5,270 2008 3,486 2008 5,270 2009 3,486 2009 5,270 2010 3,486 2010 

Mercer New Jersey Units 1, 2 

Install Dry FGD (or approved alt. technology) and continually operate 

0.15 12/31/10 

Install SCR (or approved tech) and continually operate 

0.1 01/01/07 

Install Baghouse (or approved technology) 

0.01

5 12/31/10 

Notes: 

1) This summary table describes incremental changes in New Source Review settlement actions as they are represented in EPA 

settlement actions are simplified for representation in the model. This table is not intended to be a comprehensive description 

settlement agreements. 
37

Appendix IV. State Rules and Requirements 

State/Region Bill Emission Type Emission Specifications Implementation Statu

California CA Reclaim Market 

NOX 9.68 MTons annual cap for any source with actual emissions of 4 tons or more in 1990 and thereafter 

1994 

SO2 4.292 MTons annual cap for any source with actual emissions of 4 tons or more in 1990 and thereafter 

Delaware 

Regulation No. 1146: 

Electric Generating Unit 

(EGU) Multi-Pollutant 

Regulation 

NOX 0.125 lbs/MMBtu rate limit of NOX annually for all coal and residual- oil fired units greater than 25 MW 2009 

SO2 0.26 lbs/MMBtu annual rate limit for coal and residual-oil fired units greater than 25 MW 

Georgia 

Multipollutant Control for 

Electric Utility Steam 

Generating Units 

SCR, FGD, and 

Sorbent Injection 

Baghouse controls 

to be installed 

The following plants must install controls: Bowen, Branch, Hammond, McDonough, Scherer, Wansley, and Yates 

Implementation from 20

through 2015, dependi

on plant and control typ

Illinois 

Title 35, Part 225, Subpart 

B: Control of Hg Emissions 

from Coal Fired Electric 

Generation Units 

NOX 0.11 lbs/MMBtu annual rate limit and ozone season rate limit for all Dynergy and Ameren coal steam units greater than 25 MW 2012 

SO2 0.33 lbs/MMBtu annual rate limit for all Dynergy and Ameren coal steam units greater than 25 MW 2013 

Hg 

90% Hg removal (or emission rate of 0.08 lbs/GWh) for all Ameren coal units greater than 25 MW and 90% Hg removal (or 0.08 lbs/GWh) for all Dynergy coal units greater than 25 MW 

2015 

Title 35 Part 225; Subpart 

F: Combined Pollutant 

Standards 

NOX 0.11 lbs/MMBtu annual rate limit and during the ozone season for all Midwest Gen coal steam units 2012 

SO2 0.44 lbs/MMBtu annual rate limit in 2013, decreasing annually to 0.11 lbs/MMBtu in 2019 for all Midwest Gen coal steam units 2013 

Hg 90% Hg removal (or emission rate of 0.08 lbs/GWh) annually for all Midwest Gen coal steam units 2015 

Maine 

Chapter 145 NOX Control 

Program NOX

0.15 lbs/MMBtu annual rate limit for all fossil fuel units greater than 25 MW built before 1995 with a heat input capacity greater than 750 MMBtu/hr and 0.20 lbs/MMBtu annually for all fossil fuel fired indirect heat exchangers, primary boilers, and resource recovery units with heat input capacity greater than 250 MMBtu/hr 

2005 

Statue 585-B Title 38, 

Chapter 4: Protection and 

Improvement of Air 

Hg Cap of 100 lbs of Hg annually for any facility including EGUs gradually lowering to 25 lbs in 2010 2005 

Minnesota Minnesota Hg Emission Reduction Act Hg 90% removal of Hg content of fuel annually for all coal units greater than 250 MW 2008 

New 

Hampshire 

RSA 125-O: 11-18 Hg 80% reduction of aggregated Hg content of the coal burned at the facilities for Merrimack Units 1 & 2 and Schiller Units 4, 5, & 6 2013 

ENV-A2900 Multiple 

pollutant annual budget 

trading and banking 

program 

CO2 REMOVED: CO2 annual cap of 5,426 Mtons for six specific existing steam units owned by PSNH 2007 

Texas Senate Bill 7 Chapter 101 

SO2 273.95 MTons cap of SO2 for all grandfathered units built before 1971 in East Texas Region 2003 

NOX Annual cap for all grandfathered units built before 1971 in MTons: 84.48 in East Texas, 18.10 in West Texas, 1.06 in El Paso Region 
38

State/Region Bill Emission Type Emission Specifications Implementation Statu

Chapter 117 NOX

East and Central Texas annual rate limits in lbs/MMBtu for units that came online before 1996: Gas fired units: 0.14 Coal fired units: 0.165 Stationary gas turbines: 0.14 

2007 

Dallas/Fort Worth Area annual rate limit for utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in an electric power generating system except for CT and CC units online after 1992: 0.033 lbs/MMBtu or 0.50 lbs/MWh output or 0.0033 lbs/MMBtu on system wide heat input weighted average for large utility systems 0.06 lbs/MMBtu for small utility systems Housont/Galveston region annual Cap and Trade (MECT) for all fossil units: 8.46 Mtons Beaumont-Port Arthur region annual rate limits for utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in an electric power generating system: 0.10 lbs/MMBtu 

Wisconsin 

NR 428 Wisconsin 

Administration Code NOX

Annual rate limits in lbs/MMBtu for coal fired boilers greater than 1,000 MMBtu/hr : Wall fired, tangential fired, cyclone fired, and fluidized bed: 2009: 0.15, 2013 onwards: 0.10 Arch fired: 2009 onwards: 0.18 

2009 

Annual rate limits in lbs/MMBtu for coal fired boilers between 500 and 1,000 MMBtu/hr: Wall fired: 2009: 0.20; 2013 onwards: 0.17 in 2013 Tangential fired: 2009 onwards: 0.15 Cyclone fired: 2009: 0.20; 2013 onwards: 0.15 Fluidized bed: 2009: 0.15; 2013 onwards: 0.10 Arch fired: 2009 onwards: 0.18 Annual rate limits for CTs in lbs/MMBtu: Natural gas CTs greater than 50 MW: 0.11 Distillate oil CTs greater than 50 MW: 0.28 Biologically derived fuel CTs greater than 50 MW: 0.15 Natural gas CTs between 25 and 49 MW: 0.19 Distillate oil CTs between 25 and 49 MW: 0.41 Biologically derived fuel CTs between 25 and 49 MW: 0.15 Annual rate limits for CCs in lbs/MMBtu: Natural gas CCs greater than 25 MW: 0.04 Distillate oil CCs greater than 25 MW: 0.18 Biologically derived fuel CCs greater than 25 MWs: 0.15 Natural gas CCs between 10 and 24 MW: 0.19 

WI Hg rule Hg 

75% reduction of Hg emissions to coal fired units belonging to Alliant Energy, WE Energies, Wisconsin Public Service and Dairyland Power Cooperative 

2010