### 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 el ectric 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, inpu ts, 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. Po wer companies provided information on generating resources and emission controls . EPA also obtained input from Regional Planning Organizations, States , and their constituent or ganizations. Key updates
included:

z 

### Coal Supply and Transp ortation Assumptions

z 

### Natural Gas Assumptions

z 

### Federal and State Emission Regulat ions and Enforcement Actions

z 

### Cost and Performance of Generating Technologies and Emission Controls

z 

### Sulfur Dioxide (SO 2 

### ), Nitrogen Oxide (NO X 

### ) 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/progs regs/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 co sts 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 Electri c Energy Data System (NEEDS)

8. Title IV SO 2 

### allowance bank estimate

9. Updated mapping of model run years

10. Updated financial assumptions

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

v3.02 EISA.



## Overview of IPM and EPA Modeling Applications 1



### EPA uses the Integrated Planning Model (IP M) 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 Res ources, Inc., and used to support public and private sector clients, IPM is a multi-regional, dynamic, deterministic linear programming model of the electr ic power sector. It provides forecasts of least-cost capacity expansion, electricity dispatch, a nd emission control strategies for meeting electricity demand, environmental, transmissi on, dispatch, and reliability constraints.
IPM can be used to evaluate the cost and em issions impacts of proposed policies to limit emissions of sulfur dioxide (SO 2 

### ), nitrogen oxides (NO X 

### ), carbon dioxide (CO 2 

### ), and mercury (Hg) from the electric power sector and is used extensively by EPA to support regulatory activities. Updates for this vers ion of the model were primarily focused on allowing strong analysis of regional SO 2 

### and NO X 

### reductions.

Among the factors that make IPM particul arly well suited to model multi-emissions control programs are (1) its ability to capture complex in teractions among the electric power, fuel, and environmental markets; (2) its detail-rich repres entation 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-sp ecific 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 reduc tion options are particularly important for assessing the impact of multi-emissions environmental policies for the
power sector.
IPM is a single sector, linear programming mo del 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 NO X 

### Program, the NO X 

### 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 Ca se v3.02 EISA are shown in Table 1 below.
These values were derived based on the elect ricity sales forecast in the U.S. Energy
Information Administration’s Annual Ener gy Outlook (AEO) 2008 reflecting EISA 2007. The revised growth rate used in the referen ce 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 upda ted 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 genera ting technologies in IPM. Tables 2 and 3 below show the cost and performance characte ristics of the modeled potential (new) build
units.

### 5 

## Table 2. Performance and Unit Co st Assumptions for Potential (New)

Capacity from Conventional Techno logies 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 V inta g e #1 (y ears covered ) 2012 - 2013 2012 - 2013 -- -- -- -- -- -- -- V inta g e #2 (y ears covered ) 2014 - 2017 2014 - 2017 -- 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 V inta g e #3 (y ears covered ) 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 V inta g e #4 (y ears covered ) 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 Availabilit y 87% 92% 90% 80% 80% 80% 80% 85% 85%

Heat Rate ( Btu/kWh ) 6,720 10,200 Ca p ital ( 2006$/kW ) 800 535 Fixed O&M ( 2006$/kW/ y r ) 9.8 11.6 V ariable 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 Ca p ital ( 2006$/kW ) 780 519 1,980 2,310 2,610 3,000 1,800 1,750 Fixed O&M ( 2006$/kW/ y r ) 9.8 11.6 35.3 39.5 43.7 48.6 25.7 25.2 V ariable 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 Ca p ital ( 2006$/kW ) 765 508 3,000 1,936 2,259 2,553 2,934 1,768 1,719 Fixed O&M ( 2006$/kW/ y r ) 9.8 11.6 66.1 35.3 39.5 43.7 48.6 25.7 25.2 V ariable 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 Ca p ital ( 2006$/kW ) 745 490 2,784 1,883 2,197 2,482 2,853 1,739 1,691 Fixed O&M ( 2006$/kW/ y r ) 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 Co st Assumptions for Potential (New)
Renewable and Non-Conventional Tech nology 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 V inta g e #1 (y ears covered ) 2012 - 2013 -- 2012 - 2013 2012 - 2013 2012 - 2013 2012 - 2013 2012 - 2013 2012 - 2013 2012 - 2013 V inta g e #2 (y ears covered ) 2014 - 2017 -- 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 2014 - 2017 V inta g e #3 (y ears covered ) 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 2018 - 2022 V inta g e #4 (y ears covered ) 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 2023 - 2035 Availabilit y 85% 80% 87% 87% 90% 90% 95% Generation Ca p abilit y 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 Ca p ital ( 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/ y r ) 83.0 5.5 147 - 212 111.2 111.2 111.2 11.4 55.2 29.5 V ariable 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 Ca p ital ( 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/ y r ) 83.0 5.5 111.2 111.2 111.2 11.4 55.2 29.5 V ariable 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 Ca p ital ( 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/ y r ) 83.0 47.0 5.5 111.2 111.2 111.2 11.4 55.2 29.5 V ariable 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 Ca p ital ( 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/ y r ) 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
Geothermal Fuel Cells Solar Photovoltaic

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 th e engineering equations that were used to generate the input costs for NO X 

### control retrofits in IPM. Specifically, Table 4 and the accompanying notes provide the coefficients, te rms and scaling factors of the engineering equations that were used to derive the cap ital, FOM (fixed operating and maintenance), and VOM (variable operating and maintena nce) cost rates used in IPM for NO X 

### retrofit

### 6 emission controls. In the notes under Tabl e 4 examples are provide d to illustrate how
these cost rates would be derived for a 275 MW unit from the values shown in the table.



## Table 4. NO X 

## Control Retrofit Cost Assumptions for Existing Coal-fired Units in v3.02 EISA Base Case (2006$)

Post-Combustion Control Technology Coefficients Percent Removal Capital ($/kW) Fixed O&M ($/kW-year) Variable O&M (mills/kWh)
SCR 2 169 0.79 0.71 90% 1

SNCR 3 Term1: 29 Term1: 0.30 0.79 35% Term2: 33 Term2: 0.35
SNCR 4 (Cyclone) 17 0.17 1.55 35%
SNCR 5 (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. “Upd ating Performance and Cost of NO X 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. Th e 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 al so presented in 1999 dollars.



## Table 4.a NO X 

## 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 SO 2 

### emission control retrofit t echnologies represented in th e IPM – Limestone Forced Oxidation (LSFO) scrubbers and Lime Spray Dr yer (LSD) – for a repr esentative range of generating units differentiated by thei r capacities, heat rates, and coals. 3 

### The engineering equations and related assumptions used to de rive the values show n in this table are presented in two papers: James E. Staudt and Sikander R. Khan, “Updating Performance
and Cost of SO 2 

### Control Technologies in the Integr ated Planning Model and the Coal Utility Environmental Cost Model,” The Mega Symposium, August 28–31, 2006, Baltimore, Maryland, and “SO 2 

### Control Technology Performance and Cost Study” by Andover Technology Partners, EPA Cont ract 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 SO 2 

## 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 SO 2 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 SO 2 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 in corporate scaling fact ors to capture cost
increases that have occurred si nce the equations were origina lly developed. In general, capital costs incorporate the mark et conditions reflected in AEO 2008.

### 10 

## Table 6. Post-Combustion NO X 

## 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) SCR 1 49 1.05 0.12 80%

SNCR 2 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. Th e 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 al so presented in 1999 dollars.



## Table 6.a NO X 

## Control Retrofit Cost A ssumptions for Oil/Gas Steam Units in CAIR v2.1.9 Base Case (1999$)

Table 7. Cost (2006$) of NO X 

## 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 NO X Burner without Overfire Air (LNB without OFA) 29 0.31 0.064

Low NO X Burner with Overfire Air (LNB with OFA) 39 0.43 0.085TangentiallyFired Low NO X Coal-and-Air Nozzles with Close-Coupled Overfire Air (LNC1) 15 0.17 0.000

Low NO X Coal-and-Air Nozzles wi th Separated Overfire Air (LNC2) 21 0.22 0.029

Low NO X 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 th e 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 op erating 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 th e same assessment of available gas resource through the U.S. and Canada as used in ICF’ s Gas Market Model (G MM) 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 bu ilt 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, wh ich 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 signifi cant growth in North American liquefied natural gas (LNG) imports, based on projecte d 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 expect ed 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 Re gulatory Environment

The model includes policies affecting the power sector: the Title IV of the Clean Air Act (the Acid Rain Program); the NO X 

### SIP Call; various New Source Review (NSR)
settlements 5 

### ; and several state rules 6 

### affecting emissions of SO 2 

### and NO X 

### that were finalized through February 3, 2009. IPM includes state rules that ha ve 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, Ta mpa 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, Ge orgia, 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 C ourt vacated the CAMR. In June 2005, EPA finalized guidelines for States to use in dete rmining which facilities must install controls and the type of controls the facilities mu st use to satisfy Best Available Retrofit Technology (BART) requirements to address regional haze (also known as the CAVR). Because of uncertainty regarding the preci se measures and requirements States will adopt, the specific CAVR power sector assump tions that were formerly modeled in IPM
have been removed.



# 6. Dispatchable Controls

As detailed in chapter 7 of the proposed Tr ansport Rule Regulatory Impact Analysis, developing the Transport Rule presented a uni que regulatory situati on to represent in IPM: the possibility of an area moving to le ss 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 SO 2 

### and NO X 

### emissions controls. In areas transitioning from a more stringent to le ss stringent regulatory regime (for example, a state affected by CAIR but potentially not affected by th e 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 set tlements, state rules, or other past policies would be required to continue to operate regardless of ch anges to the CAIR program.

In order to represent these decisions accu rately 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 m odel plant receives a special F GD 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 th e 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 de signed 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 SO 2 

### . The rules listed below apply to FGD, SCR, and ACI on coal-fired units.

Note that as in previous IP M modeling, a set of rules applies to all units to determine
their NO X 

### rates. These rules are discussed in de tail in Section 3 of the documentation for

### 14 EPA Base Case 2006 (v3.0): http://w ww.epa.gov/airmarkt/progsregs/epaipm/docs/Section-3.pdf. The model can choose whether to install a dispatchable postcombustion NO X 

### control, but once installed, it is tr eated the same as any other control under the Section 3 rules in determining a unit’s NO X 

### rate.



## Rules for dispatchable scrubbers on coal units

1. If the unit online year is 1990 or later then the scrubber wi ll not be dispatchable. Such units are likely to be new units required to control.

2. If the unit is online before 1990 and if th e 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 sc rubber 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 th en 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 NO X 

### 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) ar e 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. (The y are still subject to Section 3 rules for determining NO X 

### 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, stat e settlement or state-specific rule and the control is online by the end of 2011. b) If the unit is online af ter 2005 (i.e., those treated as committed by NEEDS). c) If the unit is in one of the following stat es with mercury rules: GA; IL; ME; MD; MN; NH; WI.



# 7. Updates to National Electri c Energy Data System (NEEDS)

The National Electric Energy Data System or “NEEDS” database contains the generation
unit records used to constr uct the “model” plants that represent existing and planned/committed units in EPA modeling appl ications of IPM. NEEDS includes basic geographic, operating, air emissions, and othe r 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 Source 1 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 NO X 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 Administra tion (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, SO 2 and NO X controls, and SO 2 , NO X and CO 2 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. utilitie s and RPOs regarding the population
in NEEDS as well as unit characteri stics 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 inst ances 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, su mmer and winter capacity of zero

Status Excluded units on long-term scheduled maint enance or retired (i.e. units with
status codes “OS” or “RE” in EIA Forms) Status of boiler(s) and associated gen erator(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 Da ta Sources for Capacity
in NEEDS v3.02 EISA

Sources Presented in Hierarchy Capacity from Utility/Regional Planning
Or g anization ( 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

SO 2 Pollution
Control NSR Settlement or Utility/RPO
Comments EPA’s Emission Tracking System (ETS) - 2006 2005 EIA 767
See Note 1 No
Control

NO X Pollution
Control NSR Settlement or Utility/RPO
Comments EPA’s Emission Tracking System (ETS) - 2006 2005 EIA 767 See Note 1 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 sour ces listed here, the web sites of generating unit owners and operators were also consulted.



# 8. Title IV SO 2 

# Allowance Bank Estimate

The Title IV SO 2 

### 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, SO 2 

### emissions have instead continued to decline. Even if the Title IV bank does not decline to 1.6 million allowances by 2012, EPA believes th ere 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 Ye ar 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 retrof itting FGD or SCR. In model runs other than the Transport Rule base case, coal-f ired 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 ab sence of that option has little or no effect
on emissions or cost results in the ba se case. A summary of available SO 2 

### control options, based on an approximate extrapola tion 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 SO 2 

## 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 ($/kW) 1,368 934 748 487 396 350Fixed O&M ($/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 resu lts relative to the
emissions rates of the same units in recent da ta. As a result, the rates of 30 units were constrained in subsequent runs to provide mo re accurate emissions results for those units. Additionally, 3 units possessed ex isting 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 char acteristics 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 SO 2 0.131 856_B_1 856 E D Edwards 1 Annual SO 2 0.461 856_B_2 856 E D Edwards 2 Annual SO 2 0.457 856_B_3 856 E D Edwards 3 Annual SO 2 0.429 2516_B_1 2516 Northport 1 Annual SO 2 0.132 2516_B_2 2516 Northport 2 Annual SO 2 0.344 2516_B_3 2516 Northport 3 Annual SO 2 0.299 2516_B_4 2516 Northport 4 Annual SO 2 0.244 2517_B_3 2517 Port Jefferson 3 Annual SO 2 0.294 2517_B_4 2517 Port Jefferson 4 Annual SO 2 0.305 3788_B_1 3788 Potomac River 1 Annual SO 2 0.383 3788_B_2 3788 Potomac River 2 Annual SO 2 0.343 3803_B_1 3803 Chesapeake 1 Annual SO 2 0.891 3803_B_2 3803 Chesapeake 2 Annual SO 2 0.885 3803_B_3 3803 Chesapeake 3 Annual SO 2 0.895 3803_B_4 3803 Chesapeake 4 Annual SO 2 0.939 2378_B_1 2378 B L England 1 Annual SO 2 Controls achieve 93% removal 2240_B_8 2240 Lon Wright 8 Annual SO 2 0.651 2277_B_1 2277 Sheldon 1 Annual SO 2 0.590 2277_B_2 2277 Sheldon 2 Annual SO 2 0.567 2291_B_1 2291 North Omaha 1 Annual SO 2 0.754 2291_B_5 2291 North Omaha 5 Annual SO 2 0.721 59_B_1 59 Platte 1 Annual SO 2 0.745 60_B_1 60 Whelan Energy Center 1 Annual SO 2 0.696 6077_B_1 6077 Gerald Gentleman 1 Annual SO 2 0.615 6077_B_2 6077 Gerald Gentleman 2 Annual SO 2 0.601 6096_B_1 6096 Nebraska City 1 Annual SO 2 0.727 8048_B_1 8048 Anclote 1 Annual NO X 0.183 8048_B_2 8048 Anclote 2 Annual NO X 0.136 619_B_PRV3 619 Riviera PRV3 Annual NO X 0.208 619_B_PRV4 619 Riviera PRV4 Annual NO X 0.307 136_B_1 136 Seminole 1 Annual NO X Controls achieve 90% removal 136_B_2 136 Seminole 2 Annual NO X 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 Presen t in Policy Ca se Model Runs

Because the 2012 run year represen ts years within eighteen mont hs of the present, it is

### 24 unrealistic to expect advanced SO 2 

### and NO X 

### 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 ar e limited to those built in the base case (TR_Base_Case).



# Appendix I. Background on th e Integrated Planning Model (IPM), Its Uses, and Related Peer Review Activities

EPA uses the Integrated Planning Model (IP M) 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 de veloped by ICF Resources and IPM® is a registered trademark of ICF Resources, Inc.

IPM is a multi-regional, dynamic, determinis tic linear programming model of the U.S. electric power sector. The model provides fo recasts of least-cost capacity expansion, electricity dispatch, and emission control strategies for meeting energy demand and environmental, transmission, dispatch, and reli ability constraints. IPM provides both a broad and detailed analysis of the emission co ntrol 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 cha nges) along with the economic impacts of these control options in terms of costs, wholesal e 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 e xpended to ensure that IPM is populated with high quality input data and th at its assumptions are base d on latest engineering and economic experience. The data and assump tions are fully documented and publicly
available on EPA’s web site. Use of such a bottom-up model impos es scientific and technical discipline on EPA that serves to improve the decision making process and increase opportunities for broad publ ic & 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 electri city sector that is represented in IPM, stakeholders affected by the policies being modeled, and deve lopers 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 promulgate d 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 y ears 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), environmenta l 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 pri ce and volume relationships at the Henry Hub. For each listed step the price applies fo r 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 pri ce 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 47,77230Appendix III. New Source ReviewSettlements: Incremental Changes from EPA Base Case v.3.0Companyand PlantStateUnitSETTLEMENT ACTIONSAllowanceRetirementAllowance RestrictionsNotesRetire/RepowerSO2ControlNoxControlPM or Mercury ControlActionEffectiveDateEquipmentPercent Removal orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateKentucky Utilities CompanyEW BrownGeneratingStationKentuckyUnit 3InstallFGD97% or 0.10012/31/10Install andcontinuouslyoperateSCR by12/31/2012,continuouslyoperatelow NOXboiler andOFA.0.0712/31/12ContinuouslyoperateESP0.0312/31/10KU mustsurrender 53,000SO2allowances of2008 or earliervintage by March1, 2009. Allsurplus NOXallowances mustbe surrenderedthrough 2020.SO2and NOXallowancesmay not beused forcompliance,andemissionsdecreases forpurposes ofcomplyingwith theConsentDecree donot earncredits.AnnualSO2capis 31,998tonsthrough2010,then2,300tons eachyearthereafter. AnnualNOXcapis 4,072tons.American Electric PowerEastern System-WideAnnual Cap (tons)YearAnnualCap(tons)YearNOXand SO2allowances thatwould have beenmade available byemissionreductionspursuant to theConsent Decreemust besurrendered.NOXand SO2allowancesmay not beused tocomply withany of thelimitsimposed bythe ConsentDecree. TheConsentDecreeincludes aformula forcalculatingexcess NOXallowancesrelative to theCAIRAllocations,and restrictsthe use ofsome. Seepar. 74-79 fordetails.Reducingemissionsbelow theEasternSystem-WideAnnualTonnageLimitationsfor NOXandSO2earnssupercomplianceallowances.450,000201096,0002009450,000201192,5002010420,000201292,5002011350,000201385,0002012340,000201485,0002013275,000201585,0002014260,000201675,0002015235,000201772,0002016 andthereafter184,0002018174,0002019 andthereafter31Companyand PlantStateUnitSETTLEMENT ACTIONSAllowanceRetirementAllowance RestrictionsNotesRetire/RepowerSO2ControlNoxControlPM or Mercury ControlActionEffectiveDateEquipmentPercent Removal orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateAt least600MWfromvariousunitsWestVirginiaSporn1–4Retire,retrofit, orre-power12/31/18VirginiaClinchRiver1–3IndianaTannersCreek1–3WestVirginiaKammer1–3AmosWestVirginiaUnit 1InstallandcontinuouslyoperateFGD12/31/09Install andcontinuouslyoperateSCR01/01/08Unit 212/31/1001/01/09Unit 312/31/0901/01/08Big SandyKentuckyUnit 1Burn onlycoal withno morethan 1.75lb/MMBtuannualaverageDate ofentryContinuouslyoperatelow NOXburnersDate ofentryUnit 2InstallandcontinuouslyoperateFGD12/31/15Install andcontinuouslyoperateSCR01/01/09CardinalOhioUnits 1,2InstallandcontinuouslyoperateFGD12/31/08Install andcontinuouslyoperateSCR01/01/09ContinuouslyoperateESP0.0312/31/09Unit 312/31/12ClinchRiverVirginiaUnits 1–3Annual Cap (tons)YearContinuouslyoperatelow NOXburnersDate ofentry21,700201021,700201121,700201221,700201321,700201416,3002015onwards32Companyand PlantStateUnitSETTLEMENT ACTIONSAllowanceRetirementAllowance RestrictionsNotesRetire/RepowerSO2ControlNoxControlPM or Mercury ControlActionEffectiveDateEquipmentPercent Removal orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateConesvilleOhioUnits 1,2Retire,retrofit, orre-powerDate ofentryUnit 312/31/12Unit 4InstallandcontinuouslyoperateFGD12/31/10Install andcontinuouslyoperateSCR12/31/10Units 5,6UpgradeexistingFGD95%12/31/09Continuouslyoperatelow NOXburnersDate ofentryGavinOhioUnits 1,2InstallandcontinuouslyoperateFGDDate ofentryInstall andcontinuouslyoperateSCR01/01/09Glen LynVirginiaUnits 5,6Burn onlycoal withno morethan 1.75lb/MMBtuannualaverageDate ofentryContinuouslyoperatelow NOXburnersDate ofentryKammerWestVirginiaUnits1–3Plant-wide annualcap: 35,00001/01/12Continuouslyoperateover-fireairDate ofentryKanawhaRiverWestVirginiaUnits 1,2Burn onlycoal withno morethan 1.75lb/MMBtuannualaverageDate ofentryContinuouslyoperatelow NOXburnersDate ofentryMitchellWestVirginiaUnits 1,2InstallandcontinuouslyoperateFGD12/31/07Install andcontinuouslyoperateSCR01/01/09MountaineerWestVirginiaUnit 1InstallandcontinuouslyoperateFGD12/31/07Install andcontinuouslyoperateSCR01/01/08MuskingumRiverOhioUnits1–4Retire,retrofit, orre-power12/31/15Unit 5InstallandcontinuouslyoperateFGD12/31/15Install andcontinuouslyoperateSCR01/01/08ContinuouslyoperateESP0.0312/31/0233Companyand PlantStateUnitSETTLEMENT ACTIONSAllowanceRetirementAllowance RestrictionsNotesRetire/RepowerSO2ControlNoxControlPM or Mercury ControlActionEffectiveDateEquipmentPercent Removal orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDatePicwayOhioUnit 9Continuouslyoperatelow NOXburnersDate ofentryRockportIndianaUnit 1InstallandcontinuouslyoperateFGD12/31/17Install andcontinuouslyoperateSCR12/31/17Unit 212/31/1912/31/19SpornWestVirginiaUnit 5Retire,retrofit, orre-power12/31/13TannersCreekIndianaUnits1–3Burn onlycoal withno morethan 1.2lb/MMBtuannualaverageDate ofentryContinuouslyoperatelow NOXburnersDate ofentryUnit 4Burn onlycoal withno morethan1.2%sulfurcontentannualaverageContinuouslyoperateover-fireairEast Kentucky Power Cooperative Inc.Dale PlantKentuckyUnits 1,2Install andcontinuouslyoperatelow NOXburnersby10/31/20070.4601/01/08EKPC mustsurrender 1,000NOXallowancesimmediately underthe ARP, and3,107 under theNOXSIP Call.EKPC must alsosurrender 15,311SO2allowances.Date ofentrySystem-wideSystemwide 12-monthrollingtonnagelimitsapply12-month rolling limit(tons)Start of 12-monthcycleAll unitsmustoperatelow NOXboilers12-monthrollinglimit(tons)Start of 12-monthcyclePMcontroldevicesmust beoperatedcontinuouslysystemwide,ESPs0.031 year fromentry dateAll surplus SO2allowances mustbe surrenderedeach year,beginning in 2008.SO2and NOXallowancesmay not beused tocomply withthe ConsentDecree. NOXallowancesthat wouldbecomeBy12/31/2009, EKPCshallchoosewhetherto: 1)installandcontinuou34Companyand PlantStateUnitSETTLEMENT ACTIONSAllowanceRetirementAllowance RestrictionsNotesRetire/RepowerSO2ControlNoxControlPM or Mercury ControlActionEffectiveDateEquipmentPercent Removal orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDate57,00010/01/0811,50001/01/08must beoptimizedwithin 270days ofentrydate, orEKPCmaychoose tosubmit aPMPollutionControlUpgradeAnalysis.available asa result ofcompliancewith theConsentDecree maynot be sold ortraded. SO2and NOXallowancesallocated toEKPC mustbe usedwithin theEKPCsystem.Allowancesmadeavailable duetosupercompliance may besold ortraded.slyoperateNOXcontrolsat Cooper2 by12/31/2012 andSO2controlsby6/30/2012or 2)retireDale 3and Dale4 by12/31/2012.40,00007/01/118,50001/01/1328,00001/01/138,00001/01/15SpurlockKentuckyUnit 1InstallandcontinuouslyoperateFGD95% or 0.16/30/2011ContinuouslyoperateSCR0.12 forUnit 1until01/01/2013, atwhichpoint theunit limitdrops to0.1.Prior to01/01/2013, thecombinedaveragewhenbothunits areoperatingmust beno morethan 0.160 daysafter entryUnit 2InstallandcontinuouslyoperateFGD by10/1/200895% or 0.11/1/2009ContinuouslyoperateSCR andOFA0.1 forUnit 2,0.1combinedaveragewhenbothunits areoperating35Companyand PlantStateUnitSETTLEMENT ACTIONSAllowanceRetirementAllowance RestrictionsNotesRetire/RepowerSO2ControlNoxControlPM or Mercury ControlActionEffectiveDateEquipmentPercent Removal orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateDale PlantKentuckyUnits 3,4EKPC maychoose toretire Dale 3and 4 in lieuof installingcontrols inCooper 212/31/2012CooperKentuckyUnit 2If EKPCopts toinstallcontrolsratherthanretiringDale, itmustinstallandcontinuouslyoperateFGD orequiv.technology95% or 0.1012/31/11If EKPCelects toinstallcontrols, itmustcontinuouslyoperateSCR orinstallequiv.technology0.08 (or90% ifnon-SCRtechnology isused)12/31/12Nevada Power CompanyClarkGeneratingStationNevadaUnit 5Units mayonly firenatural gasIncreasewaterinjectionimmediately, theninstall andoperateultra-lowNOXburners(ULNBs)orequivalenttechnology. In2009,Units 5and 8may notemit morethan 180tonscombined5ppm 1-houraverage12/31/08(ULNBinstallation), 01/30/09(1-houraverage)Allowancesmay not beused tocomply withthe ConsentDecree, andnoallowancesmadeavailable duetocompliancewith theConsentDecree maybe traded orsold.Beginning1/1/2010,combinedNOXemissionsfromUnits5,6,7, and8 must beno morethan 360tons peryear.Units 6,712/31/09(ULNBinstallation), 01/30/10(1-houraverage)Unit 812/31/08(ULNBinstallation), 01/30/09(1-houraverage)PSEG FOSSILKearnyNewJerseyUnits 7,8Retire units01/01/07Allowancesallocated toKearny, Hudson,and Mercer mayonly be used forthe operationalneeds of thoseunits, and all36Companyand PlantStateUnitSETTLEMENT ACTIONSAllowanceRetirementAllowance RestrictionsNotesRetire/RepowerSO2ControlNoxControlPM or Mercury ControlActionEffectiveDateEquipmentPercent Removal orRateEffectiveDateEquipmentRateEffectiveDateEquipmentRateEffectiveDateRetirementRestrictionEffectiveDateHudsonNewJerseyUnit 2Install DryFGD (orapprovedalt.technology) andcontinually operate0.1512/31/10InstallSCR (orapprovedtech) andcontinually operate0.112/31/10InstallBaghouse(orapprovedtechnology)0.01512/31/10surplusallowances mustbe surrendered.Within 90 days ofamended ConsentDecree, PSEGmust surrender1,230 NOXAllowances and8,568 SO2Allowances notalready allocatedto or generated bythe units listedhere. Kearnyallowances mustbe surrenderedwith the shutdownof those units.Annual Cap (tons)YearAnnualCap(tons)Year5,54720073,48620075,27020083,48620085,27020093,48620095,27020103,4862010MercerNewJerseyUnits 1,2Install DryFGD (orapprovedalt.technology) andcontinually operate0.1512/31/10InstallSCR (orapprovedtech) andcontinually operate0.101/01/07InstallBaghouse(orapprovedtechnology)0.01512/31/10Notes:1) This summary table describesincremental changes in New SourceReview settlement actions asthey are represented in EPA BaseCase 3.0 to 3.02 EISA. Thesettlement actions are simplified for representation in the model. This table is not intended to be a comprehensive description of all elements of the actualsettlement agreements.37Appendix IV. State Rules and RequirementsState/RegionBillEmission TypeEmission SpecificationsImplementation StatusNotesCaliforniaCA Reclaim MarketNOX9.68 MTons annual cap for any source with actual emissions of 4tons or more in 1990 and thereafter1994Since the Reclaim Trading Credits areapplicable to entities besides powerplants, we approximate by hardwiringthe NOXand SO2allowance prices forthe calendar year 2006.SO24.292 MTons annual cap for any sourcewith actual emissions of 4tons or more in 1990 and thereafterDelawareRegulation No. 1146:Electric Generating Unit(EGU) Multi-PollutantRegulationNOX0.125 lbs/MMBtu rate limit of NOXannually for all coal and residual-oil fired units greater than 25 MW2009SO20.26 lbs/MMBtu annual rate limit forcoal and residual-oil fired unitsgreater than 25 MWGeorgiaMultipollutant Control forElectric Utility SteamGenerating UnitsSCR, FGD, andSorbent InjectionBaghouse controlsto be installedThe following plants must install controls: Bowen, Branch,Hammond, McDonough, Scherer, Wansley, and YatesImplementation from 2008through 2015, dependingon plant and control typeIllinoisTitle 35, Part 225, SubpartB: Control of Hg Emissionsfrom Coal Fired ElectricGeneration UnitsNOX0.11 lbs/MMBtu annual rate limit and ozone season rate limit for allDynergy and Ameren coal steam units greater than 25 MW2012SO20.33 lbs/MMBtu annual rate limit for all Dynergy and Ameren coalsteam units greater than 25 MW2013Hg90% Hg removal (or emission rate of 0.08 lbs/GWh) for all Amerencoal units greater than 25 MW and 90% Hg removal (or 0.08lbs/GWh) for all Dynergy coal units greater than 25 MW2015Title 35 Part 225; SubpartF: Combined PollutantStandardsNOX0.11 lbs/MMBtu annual rate limit and during the ozone season for allMidwest Gen coal steam units2012SO20.44 lbs/MMBtu annual rate limit in 2013, decreasing annually to0.11 lbs/MMBtu in 2019 for all Midwest Gen coal steam units2013Hg90% Hg removal (or emission rate of 0.08 lbs/GWh) annually for allMidwest Gen coal steam units2015Will County unit has a uniquerestriction of 90% (or 0.08 lbs/GWh)starting in 2016MaineChapter 145 NOXControlProgramNOX0.15 lbs/MMBtu annual rate limit for all fossil fuel units greater than25 MW built before 1995 with a heat input capacity greater than 750MMBtu/hr and 0.20 lbs/MMBtu annually for all fossil fuel fired indirectheat exchangers, primary boilers, and resource recovery units withheat input capacity greater than 250 MMBtu/hr2005Statue 585-B Title 38,Chapter 4: Protection andImprovement of AirHgCap of 100 lbs of Hg annually for any facility including EGUsgradually lowering to 25 lbs in 20102005MinnesotaMinnesota Hg EmissionReduction ActHg90% removal of Hg content of fuel annually for all coal units greaterthan 250 MW2008NewHampshireRSA 125-O: 11-18Hg80% reduction of aggregated Hg content of the coal burned at thefacilities for Merrimack Units 1 & 2 and Schiller Units 4, 5, & 62013Scrubbers must also be installed at theMerrimack Station unitsENV-A2900 Multiplepollutant annual budgettrading and bankingprogramCO2REMOVED: CO2annual cap of 5,426 Mtons for six specific existingsteam units owned by PSNH2007This constraint was removed as thecap was no longer in effect givenRGGI.TexasSenate Bill 7 Chapter 101SO2273.95 MTons cap of SO2for all grandfathered units built before1971 in East Texas Region2003NOXAnnual 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 Region38State/RegionBillEmission TypeEmission SpecificationsImplementation StatusNotesChapter 117NOXEast and Central Texas annual rate limits in lbs/MMBtu for units thatcame online before 1996:Gas fired units: 0.14Coal fired units: 0.165Stationary gas turbines: 0.142007Dallas/Fort Worth Area annual rate limit for utility boilers, auxiliarysteam boilers, stationary gas turbines, and duct burners used in anelectric power generating systemexcept for CT and CC units onlineafter 1992:0.033 lbs/MMBtu or 0.50 lbs/MWh output or 0.0033 lbs/MMBtu onsystem wide heat input weighted average for large utility systems0.06 lbs/MMBtu for small utility systemsHousont/Galveston region annual Cap and Trade (MECT) for allfossil units:8.46 MtonsBeaumont-Port Arthur region annual rate limits for utility boilers,auxiliary steam boilers, stationary gas turbines, and duct burnersused in an electric power generating system: 0.10 lbs/MMBtuWisconsinNR 428 WisconsinAdministration CodeNOXAnnual rate limits in lbs/MMBtu for coal fired boilers greater than1,000 MMBtu/hr :Wall fired, tangential fired, cyclone fired, and fluidized bed: 2009:0.15, 2013 onwards: 0.10Arch fired: 2009 onwards: 0.182009Annual rate limits in lbs/MMBtu for coal fired boilers between 500and 1,000 MMBtu/hr:Wall fired: 2009: 0.20; 2013 onwards: 0.17 in 2013Tangential fired: 2009 onwards: 0.15Cyclone fired: 2009: 0.20; 2013 onwards: 0.15Fluidized bed: 2009: 0.15; 2013 onwards: 0.10Arch fired: 2009 onwards: 0.18Annual rate limits for CTs in lbs/MMBtu:Natural gas CTs greater than 50 MW: 0.11Distillate oil CTs greater than 50 MW: 0.28Biologically derived fuelCTs greater than 50 MW: 0.15Natural gas CTs between 25 and 49 MW: 0.19Distillate oil CTs between 25 and 49 MW: 0.41Biologically derived fuel CTs between 25 and 49 MW: 0.15Annual rate limits for CCs in lbs/MMBtu:Natural gas CCs greater than 25 MW: 0.04Distillate oil CCs greater than 25 MW: 0.18Biologically derived fuel CCsgreater than 25 MWs: 0.15Natural gas CCs between 10 and 24 MW: 0.19WI Hg ruleHg75% reduction of Hg emissions to coal fired units belonging to AlliantEnergy, WE Energies, Wisconsin Public Service and DairylandPower Cooperative2010