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TABLE OF CONTENTS

SECTION PAGE

EXECUTIVE SUMMARY ...................................................................................................... ES-1 

1.0 INTRODUCTION/BACKGROUND..............................................................................1-1 

2.0 PLANT DESCRIPTIONS – BART AFFECTED UNITS...............................................2-1 

2.1 Boiler Type ..........................................................................................................2-1 

2.2 Emissions .............................................................................................................2-1 

2.3 Potentially Impacted Class I Areas......................................................................2-3 

3.0 BART METHODOLOGY OVERVIEW ........................................................................3-1 

4.0 BART ANALYSES.........................................................................................................4-1 

4.1 Approach.............................................................................................................. 4-1 

4.1.1 Particulate Matter...........................................................................................4-3 

4.1.2 Sulfur Dioxide................................................................................................4-5 

4.1.3 Nitrogen Oxides.............................................................................................4-6 

4.1.4 Pollutant Emissions from Corette ..................................................................4-8 

4.2 Evaluated Retrofit Technologies for J.E. Corette ................................................4-9 

4.2.1 Particulate Matter Controls..........................................................................4-10 

4.2.1.1 Summary of PM Control Technology Analyses for Corette ...........4-10 

4.2.1.2 Costs of Controls .............................................................................4-10 

4.2.1.3 Energy..............................................................................................4-13 

4.2.1.4 Non-Air Quality Environmental Impacts.........................................4-14 

4.2.1.5 Remaining Useful Life.....................................................................4-14 

4.2.1.6 Visibility Modeling..........................................................................4-15 

4.2.2 Sulfur Dioxide Controls...............................................................................4-15 

4.2.2.1 Controls and Emission Rates Evaluated ..........................................4-15 

4.2.2.2 Cost of SO2 Controls........................................................................4-17 

4.2.2.3 Energy Impacts of SO2 Controls......................................................4-18 

4.2.2.4 Non-Air Quality Impacts of SO2 Controls.......................................4-18 

4.2.2.5 Remaining Useful Life.....................................................................4-18 

4.2.2.6 Visibility Modeling..........................................................................4-19 

4.2.3 NOx Controls................................................................................................4-19 

4.2.3.1 NOx Controls and Emission Rates Evaluated ..................................4-19 

4.2.3.2 Cost of NOx Controls.......................................................................4-21 

4.2.3.3 Energy Impacts of NOx Controls .....................................................4-22 

4.2.3.4 Non-Air Quality Environmental Impacts of NOx Controls ............4-22 

4.2.3.5 Remaining Useful Life.....................................................................4-22 

4.2.3.6 Visibility Modeling..........................................................................4-22 

4.3 Visibility Modeling............................................................................................ 4-23 

4.3.1 General Modeling Procedures......................................................................4-23 

4.3.2 Summary of Modeling Results ....................................................................4-24 

5.0 SUMMARY AND CONCLUSIONS ..............................................................................5-1 

6.0 REFERENCES ................................................................................................................6-1 
ii 

TABLE OF CONTENTS

(Continued) 

LIST OF TABLES

Table ES-1: Allowable / Current / NSPS / Emission Limits Control Equipment Cost 

Summary.............................................................................................................. ES-6 

Table ES-2: Modeled Visibility and Visibility Improvements................................................ ES-6 

Table 2-1: Corette: Particle Speciation – Base Case ...............................................................2-2 

Table 2-2: Present (Base Case) SO2 and NOx Emissions .........................................................2-3 

Table 4-1: Allowable / Current/ NSPS/ Presumptive Emission Limits....................................4-2 

Table 4-2: Corette Emissions Summary ................................................................................... 4-8 

Table 4-3: PM Control Alternatives Evaluated ......................................................................4-11 

Table 4-4: Particulate Cost Analysis Summary......................................................................4-12 

Table 4-5: Representative Control Equipment Pressure Drops ..............................................4-14 

Table 4-6: Summary of Modeling Results for Particulate......................................................4-15 

Table 4-7: SO2 Control Alternatives Evaluated ......................................................................4-16 

Table 4-8: SO2 Control Cost Summary .................................................................................. 4-18 

Table 4-9: Summary of Modeling Results for SO2.................................................................4-19 

Table 4-10: NOx Control Alternatives Evaluated .....................................................................4-20 

Table 4-11: NOx Costing Analysis Summary...........................................................................4-21 

Table 4-12: Summary of Modeling Results for NOx ................................................................4-23 

Table 4-13: Summary of Modeling Results..............................................................................4-25 

Table 5-1: Summary of Cost Evaluation Results Based on Emissions ....................................5-3 

Table 5-2: Modeled Visibility and Visibility Improvements.................................................... 5-3 

LIST OF FIGURES

FIGURE ES-1: CORETTE LOCATION AND CLASS I AREAS EVALUATED................ ES-2 

FIGURE 4-1: COST ANALYSIS OF ESP CONTROL.........................................................4-12 

APPENDICES

APPENDIX A: COST ANALYSIS TABLES 

APPENDIX B: CALPUFF APPLICATION FOR BART ASSESSMENTS AT PPL CORETTE 
ES-1 

EXECUTIVE SUMMARY 

The Best Available Retrofit Technology (BART) program was established under the 

federal Regional Haze Rule to evaluate possible retrofit emissions control technology for 

visibility impairing pollutants emitted from certain combustion units constructed between 1962 

and 1977 that could potentially cause or contribute to degradation of visibility at Prevention of 

Significant Deterioration (PSD) mandatory Class I Areas. 

The coal fired generating unit at the PPL Montana, LLC J.E. Corette generating station 

(Corette) was determined to be BART-eligible under the Federal Regional Haze Rule by the U.S. 

Environmental Protection Agency Region 8. The Class I areas within 300 km of Corette are the 

North Absaroka Wilderness Area (137 km to the southwest), Yellowstone National Park (145 km 

to the southwest), the Washakie Wilderness Area (171 km to the southwest), the UL Bend 

National Wildlife Refuge (192 km to the north), the Teton Wilderness Area (199 km to the 

southwest), the Gates of the Mountains Wilderness Area (276 km to the west) and Red Rock 

Lakes (277 km to the southwest). These Class I areas are shown in relation to the Corette plant 

in Figure ES-1. 

The CALPUFF model was used to evaluate the visibility impacts of present emissions 

from the Corette boiler and BART control alternatives. The model setup and input 

meteorological and emissions data were obtained from EPA/WRAP files. The modeling 

conducted by TRC for PPL used those data files with a few modifications. The particulate 

emissions were revised based on PPL stack test data and a few adjustments were made to the 

modeling as described in Appendix B. The highest modeled annual 98th percentile daily 

visibility impact of emissions from the unit at present maximum actual emissions is predicted to 

occur in the UL Bend National Wildlife Refuge (NWR) Class I area and is 0.645 deciviews, only 

slightly above the BART threshold of 0.5 deciviews. EPA notes that 0.5 deciview corresponds 

to “a just noticeable change” in most landscapes and was therefore selected by EPA as the 

recommended threshold for inclusion of a source in the BART program. Note that the maximum 

modeled 98th percentile visibility impact from Corette is well below the 1.0 deciview value EPA 

employs as a metric to indicate that a source causes a visibility impact. A summary of the 

visibility modeling results appears in Table ES-2. 

The U.S. Environmental Protection Agency’s (EPA’s) BART Guideline approach has 

been applied to Corette to identify the “best system of continuous emission reduction” applicable 

to the plant for filterable particulate, sulfur dioxide (SO2) and nitrogen oxides (NOx) control in 
ES-2 

Figure ES-1: Corette Location and Class I Areas Evaluated 
ES-3 

order to comply with Region 8’s BART program. Corette already has relatively low emissions 

due to the use of an electrostatic precipitator, low sulfur Powder River Basin coal and good 

combustion control. A range of demonstrated control alternatives for sub-bituminous coal-fired 

boilers was evaluated considering costs, energy and environmental impacts, remaining useful life 

of the units and modeled visibility improvements. 

For filterable particulate matter, electrostatic precipitators (ESP), fabric filters 

(baghouses), mechanical collectors and wet scrubbers were considered. However, mechanical 

collectors were not further evaluated because these are used as pre-filters and do not perform 

well as a retrofit option. All cost estimates are based on EPA Control Cost Manual information 

and techniques whenever possible, and all cost estimates are scaled to 2007 dollars. 

The Corette boiler already has ESP controls and therefore either an upgrade of the current 

technology, or the addition of fabric filter controls, would be necessary to attain an emission rate 

equivalent to the best demonstrated technology (BDT) filterable emission rate of 0.015 

lbs/MMBtu. For installation of a fabric filter, this would cost approximately $16,300 per ton of 

particulate emissions controlled. Although upgrades to the current ESP controls would only 

make sense if one of the available dry scrubbing techniques for SO2 were chosen, a cost estimate 

for installation of a new modern ESP was performed. This showed that a cost of approximately 

$21,000 per ton of additional control would be necessary to attain the 0.015 lb/MMBtu BDT 

emission rate. The retrofit installation of a wet scrubber (venturi scrubber) to attain the same 

filterable particulate matter emission reduction and visibility improvement would also only be 

considered in conjunction with SO2 control upgrades and are discussed below in that context. 

From a visibility improvement basis with respect to filterable particulate matter, only a 

0.03 deciview improvement, which is not visually discernable, would result from installation of 

either ESPs or fabric filters. Consequently, implementation of additional filterable particulate 

control at Corette is not warranted. 

For SO2 and NOx, the cost effectiveness analysis was based on emission rates typical of 

30-day average emissions. These rates for the present, cost effectiveness (base case) emissions 

are 0.46 lb/MMBtu for SO2 and 0.26 lb/MMBtu for NOx. However, consistent with the 

modeling guidance, the modeling analysis was conducted at maximum actual daily emission 

rates. For modeling the present (base case) emissions the maximum actual daily rates during the 

modeling years are 0.6 lb/MMBtu for SO2 and 0.31 lb/MMBtu for NOx based on Part 60 CEM 

data. This distinction was also made for the evaluation of control alternatives for which the cost 
ES-4 

analysis was based on expected typical emission rates and the modeling was based on expected 

maximum actual daily emission rates. For filterable particulate, continuous emissions data 

(CEM data) are not available and a distinction between maximum actual and typical emission 

rates was not made. 

 For SO2, the available control technologies include the use of low sulfur fuels, dry gas 

scrubbing techniques and wet scrubbing (flue gas desulfurization, FGD) techniques. Based on 

experience at other PPL facilities and EPA data that summarize the effectiveness of SO2 removal 

technologies, PPL evaluated the cost effectiveness of lime or limestone injection at Corette using 

the current ESP equipment. Corette already burns low-sulfur (approximately 0.3 weight percent) 

Powder River Basin (PRB) coal with uncontrolled daily SO2 emissions during the modeling 

years that were a maximum of 0.6 lb/MMBtu and typically averaged closer to 0.46 lb/MMBtu. 

The cost effectiveness of dry injection of lime or limestone to attain a 25% emissions reduction 

is $8,138/ton of SO2 controlled. Emission reductions were also evaluated to meet the 

presumptive BART level of 0.015 lb/MMBtu. This presumptive BART level does not apply to 

the Corette boiler which is below the size threshold for which this presumptive level is intended. 

Nevertheless, the cost of achieving this level was evaluated. To attain the 0.015 lb/MMBtu level 

by dry injection, the combined cost of the more reactive sorbents and an upgraded ESP would be 

an estimated $37,429/ton of SO2. 

 Conversion of the Corette boiler to a wet scrubbing control technique is a technically 

feasible alternative which PPL has considered. PPL has substantial experience with this 

technology as it is used to control SO2 at the Colstrip facility operated by PPL. The cost 

effectiveness of installing this alternate technology at Corette is estimated to be $25,480/ton of 

SO2 based on EPA costing factors. A wet scrubbing FGD system has penalties for plume 

reheating which would require a reduction in generation output from 154 MW to approximately 

124 MW. The loss in electrical energy generation from plume reheating is included in the cost 

of adding a wet scrubber. Modeling shows only a 0.08 deciview visibility improvement with 

lime/limestone addition used to achieve a 25 percent SO2 emissions reduction. The incremental 

visibility improvements by reducing emissions to a 0.15 lb/MMBtu emission rate through either 

dry injection or wet scrubbing are 0.15 deciviews or less. Such improvements are not visually 

discernable and implementation of these control technologies is, therefore, not warranted. 

 NOx controls in-place at Corette include the tangential firing design of the boilers and 

existing low-NOx burners with close coupled over fire air. The present maximum actual daily 
ES-5 

emission rate modeled is 0.31 lb/MMBtu and the typical emissions rate used for the cost analysis 

is 0.26 lb/MMBtu. By adding separated over-fire air (SOFA) and redistribution of combustion 

air to the multiple injection ports to the current NOx controls, it is likely that emissions can be 

reduced to 0.18 lb/MMBtu. Selective non-catalytic reduction (SNCR) by injection of urea into 

the same zone within the boiler could reduce emissions to 0.16 lb/MMBtu. The cost of SNCR 

technology has been estimated, however, its tendency to form secondary particulate emissions 

from combination with sulfur oxides, and its creation of ammonia slip in the exhaust, makes this 

technique undesirable. A hot-side selective catalytic reduction system (SCR) to further reduce 

emissions to 0.15 lb/MMBtu was also reviewed, however its incremental cost over the addition 

of SOFA makes SCR economically unacceptable. This level (0.15 lb/MMBtu) was evaluated as 

a minimum emissions level because it is the presumptive BART emissions level, although the 

Corette boiler is below the size threshold for which this presumptive level is intended. Only a 

0.04 deciview modeled visibility improvement results from implementation of SOFA, which is 

not discernable, and the incremental visibility improvements of further controls are 0.06 

deciviews or less. Implementation of these control technologies is, therefore, not warranted. 

A summary of the results of the cost evaluations based on typical emissions 

representative of a 30-day average is provided in Table ES-2, both relative to the present 

emissions and incrementally from one level of control to the next. A summary of the modeled 

visibility impacts of the present emissions and the control alternatives based on maximum 

emissions is provided in Table ES-2, both relative to the present emissions and incrementally. 

The indicated visibility improvements in Table ES-2 are based on the differences between the 

maximum 98th percentile predicted daily visibility impacts at each Class I Area for each level of 

control, regardless of the meteorological year modeled for each prediction. Because Corette’s 

highest 98th percentile visibility impacts are only slightly above the 0.5 deciview threshold for 

inclusion in the BART program and the predicted reductions of visibility impacts are small 

(Table ES-2), implementation of retrofit pollution controls at Corette is not justified. 
ES-6 

Table ES-1: 

Allowable / Current / NSPS / Emission Limits Control Equipment Cost Summary 

CONTROL EQUIPMENT COST SUMMARY FOR THE PPL MONTANA, LLC, J.E. CORETTE POWER PLANT 

Particulate Matter Sulfur Dioxide Nitrogen Oxides

Evaluated

Rate Units

Evaluated

Rate Units

Evaluated

Rate Units

Current

Emission rate 0.082 lb/MMBtu 0.46 lb/MMBtu 0.26 lb/MMBtu (CEMS)

(2001 to 2005 average)

BDT(1) from

2006 NSPS for 0.015 lb/MMBtu 1.4 lbs SO2/MW out 1.0 lb/MW out

New Sources (0.15 lb/MM Btu in) (0.11 lb/MM Btu in)

Cost Effeciveness Calcs Cost Effeciveness Calcs

Option Evaluated $/ton Option Evaluated CE Inc CE Option Evaluated $/ton(5) Inc CE

Rate Rate Rate

lb/MMBtu lb/MMBtu $/ton $/ton lb/MMBtu $/ton

Control New ESP(2) 0.015 $21,149 Present 0.46 $0 Present(4) 0.26 $0

Options Added FF 0.015 $16,339 DGS(2) 0.35 $8,138 Tuning 0.23 $147

DGS(2) 0.15 $37,429 $53,538 SOFA 0.18 $914 $1,375

WS-FGD(3) 0.15 $25,480 $35,017 SNCR 0.16 $1,723 $4,966

SCR 0.15 $4,354 $30,518

Notes 1) BDT = "Best Demonstrated Technology" - From FR Vol. 71, No. 38, Monday, February 27,2007

 Final Rule (NSPS for EUSGUs) - the 2006 revised standards were revised to a gross megawatt

 output basis (equivalent in lb/MMBtu input values listed in paren)

2) Adding lime or limestone injection makes flyash unsalable - Includes added waste disposal cost

 (two options of 23% and 67% control may be possible - precip upgrade required for 67%)

 The CE for the ESP is the cost of a new technology ESP to reduce PM from 0.082 to 0.015 lb/MMBtu

3) If a wet scrubber is added, the low sulfur PRB coal could be replaced with 

 higher sulfur coal. (30 MW penalty for plume reheating) Includes lost revenue from ash sales.

4) It is assumed that boiler tuning and proper operation can improve the current 0.26 lb/MMBtu to 0.23 lb/MMBtu at minimal cost

5) Each technique applied individually; incremental cost effectiveness is that from previous option cost

Table ES-2: Modeled Visibility and Visibility Improvements 

Modeled Modeled Modeled

Rate (1) Prediction (3) from Rate Prediction from Rate Prediction from

Option (lb/MMBtu) (deciviews) Present Inc (6) Option (lb/MMBtu) (deciviews) Present Inc (6) Option (lb/MMBtu)(deciviews) Present Inc (6)

Present 0.082 0.645 n/a n/a Present 0.6 0.645 n/a n/a Present 0.31 0.645 n/a n/a

New ESP 0.015 0.633 0.032(5) 0.032(5) DGS(2) 0.46 0.568 0.077 0.077 Tuning(4) 0.27 0.616 0.043 0.043

Added FF 0.015 0.633 0.032(5) 0.032(5) EDGS(2) 0.2 0.446 0.199 0.147 SOFA 0.21 0.573 0.098 0.055

WS-FGD 0.15 0.407 0.238 0.049 SNCR 0.17 0.544 0.125 0.055

SCR 0.15 0.53 0.138 0.054

Notes: (1) The modeled emission rate is the rate corresponding to the maximum daily emissions during the modeling years (2001-2003).

 (2) See corresponding footnote in Table ES-1

 (3) Prediction is from all three pollutants at present emissions except the one being controlled

 (4) See corresponding footnote in Table ES-1.

 (5) The maximum improvement occurs at a different Class I area than the maximum prediction.

 (6) Inc = Incremental improvement from the immediately preceeding control alternative in terms of level of emissions reduction attained.

Improvement Improvement Improvement

Filterable PM10 Sulfur Dioxide Nitrogen Oxides
1-1 

1.0 INTRODUCTION/BACKGROUND 

The U.S. Environmental Protection Agency (EPA) Region 8 identified PPL Montana’s 

(PPL) J.E. Corette station coal-fired boiler as a Best Available Retrofit Technology (BART) 

eligible unit. This determination was made under the federal Regional Haze Rule (FR, Vol. 64, 

No. 126) that requires the States to submit State Implementation Plans to address haze and 

visibility issues in mandatory Prevention of Significant Deterioration (PSD) Class I Areas. On 

June 19, 2006 the State of Montana withdrew its effort to adopt the provisions of the Regional 

Haze Rule. Region 8 has assumed responsibility for the Rule and intends to prepare a Federal 

Implementation Plan (FIP) for Montana sources. Regional haze is caused by naturally occurring 

atmospheric particles and humidity as well as by anthropogenic emissions of primary particulate 

matter (PM) and of secondary emissions resulting from atmospheric gas to particle conversions 

of sulfur dioxide (SO2) and nitrogen oxides (NOx). The BART regulations identify large 

stationary source emission units put into operation between 1962 and 1977, such as Corette, as 

BART-eligible. The pollutants subject to BART requirements are SO2, NOx, PM and volatile 

organic compounds (VOC). To address the visibility impacts of these facilities, EPA issued the 

“Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations” including “Appendix Y to Part 51 - Guidelines for BART Determinations 

Under the Regional Haze Rule” (FR, Vol. 70, No. 128). 

BART is an emission source specific regulatory program under the Regional Haze 

Regulations designed to improve visibility in PSD Class I Areas through control of SO2, NOx, 

PM and VOC emissions. Corette has a nominal net generating capacity of 154 megawatts 

(MW), and has an electrostatic precipitator for PM emission control, low SO2 emissions due to 

the use of low sulfur coal and a low NOx emission burner system. A BART analysis has been 

conducted for SO2, NOx and particulate. Although Corette is below the 750 MW size cutoff for 

which BART presumptive SO2 and NOx limits of 0.15 lb/MMBtu are intended, this emissions 

level was used as the minimum SO2 and NOx control level evaluated. The BART guideline 

spells out an approach to use dispersion modeling to identify potentially subject emissions 

sources that may contribute to regional haze impacts in Class I areas, to evaluate case-by-case 

emission limitations based on the “best system of continuous emission reduction of each 

pollutant,” and to predict the degree of visibility improvement that results from the proposed 

emissions limit. The best system of continuous emission reduction is identified based on: 
1-2 

• The available retrofit control options 

• Pollution control equipment already in use or planned to be in use 

• The cost of the systems 

• The remaining use-life of the facility 

• The energy and non-air quality environmental impacts of the systems 

• The visibility impact analysis. 

This report details these steps for Corette. 
2-1 

2.0 PLANT DESCRIPTIONS – BART AFFECTED UNITS

2.1 Boiler Type

The PPL Montana J.E. Corette Power Plant (Corette) operates one electric utility steam 

generating unit with a nominal net capacity of about 154 megawatts. The single boiler is a 

tangentially fired pulverized coal boiler that burns sub-bituminous (Powder River Basin (PRB)) 

coal as its exclusive fuel. The unit began commercial operation in 1968. PPL Montana LLC 

operates the Corette Plant under Air Quality Operating Permit OP2953-02. 

2.2 Emissions 

The present (base case) particulate matter emissions for Corette are summarized in Table 

2-1. Emissions in these tables are based on PRB sub-bituminous coal combustion. The heat 

input rate (and associated emissions) for the Corette boiler, 1941.1 MMBtu/hr, is the highest 

daily average heat input rate during the modeling period (2001-2003). The particulate emissions 

used for base case modeling correspond to this heat input rate. 

The particulate matter emission rates (total filterable and condensable fractions) are based 

on stack tests conducted during the modeling years. The two stack tests conducted per year were 

averaged and the highest filterable and condensable emission rates from among the average for 

each of the three years were selected. These values are 0.082 lb/MMBtu for filterable particulate 

and 0.014 lb/MMBtu for condensable particulate. The particulate mass emissions used for 

modeling the present base case were based on these emission rates and the maximum daily 

average heat input during the modeling years (1941.1 MMBtu/hr). The speciation of the 

filterable particulate into elemental carbon, fine soil and coarse soil and size fractions were based 

on guidance provided by the National Park Service (NPS). Similarly, the speciation of 

condensable particulate into organic and inorganic particulate was based on guidance provided 

by the NPS (20% organic and 80% inorganic). 

These particulate emissions used for PPL's BART modeling are different than those used 

by EPA in the preliminary BART modeling provided to PPL. PPL believes that the values we 

are using are more accurate because they are based on stack test data. The most significant 

difference is the condensables emission rate. The 0.014 lb/MMBtu condensables emission rate 

used here is similar to the EPA's AP-42 level of 0.01 lb/MMBtu presented for pulverized coalfired boilers burning coal with a sulfur content less than 0.4 percent. In terms of mass emissions, 
2-2 

Table 2-1: Corette: Particle Speciation – Base Case 

Stack ID # Particle speciation Condensable Filterable

Organic 

condensable (OC) H2SO4 Coarse Soil 

Filterable PM10 Condensable PM10 M1=0.48, SD1=2.0 μm M1=0.48, SD1=2.0 μ

% % lb/hr lb/hr lb/hr lb/hr 

Unit 1 85.4 14.6 5.44 21.74 88.43 68.12 

1 M and SD stand for Geometric Mass Mean Diameter and Geometric Standard Deviation. These are the parameters used to calculate the particle size distribu
2-3 

the modeling presented here used filterable and condensable emissions of 159.2 lb/hr and 27.2 

lb/hr respectively, compared to values used by EPA of 29.0 lb/hr and 111.2 lb/hr respectively. 

The SO2 and NOx present (base case) emissions used for modeling are the same as those 

used in EPA's BART modeling that was provided to PPL. These are the highest 24-hour average 

emissions over the modeling years as determined from Part 60 Continuous Emission Monitoring 

Systems (CEMS) data. 

For the cost analysis, SO2 and NOx present emission rates were based on typical emission 

rates representative of a 30-day rolling average actual emission rate for the Corette boiler. The 

maximum daily emission rates for modeling and typical/average emission rates for the control 

technology analyses have been used in accordance with BART guidance in the Final Rule. For 

PM, for which continuous CEM data are not available, a distinction between maximum and 

typical emission rates was not made. 

The particulate matter present (base case) emissions are summarized in Table 2-1 and the 

SO2 and NOx present emissions are summarized in Table 2-2. 

2.3 Potentially Impacted Class I Areas

The federal mandatory Class I Areas within 300 km of Corette are the North Absaroka 

Wilderness (137 km to the southwest), Yellowstone National Park (145 km to the southwest), the 

Washakie Wilderness (171 km to the southwest), the UL Bend National Wildlife Refuge (192 

km to the north), the Teton Wilderness (199 km to the southwest), the Gates of the Mountains 

Wilderness Area (276 km to the west) and Red Rock Lakes (277 km to the southwest). These 

Class I areas are shown in Figure ES-1.

Table 2-2: Present (Base Case) SO2 and NOx Emissions 

Pollutant Typical/Average 

Emission Rate (1) 

(lb/MMBtu) 

Maximum 

Emission Rate(2) 

(lb/MMBtu) 

Maximum 

Mass Emissions(2)

(lb/hr) 

SO2 0.46 0.60 1135.0 

NOx 0.26 0.31 604.0 

NOTES: (1) Typical/average emission rates were used for the control technology and 

 cost analyses. 

 (2) Maximum emission rates are the highest daily average emissions during the 

 modeling years (2001-2003). These emissions were used for the modeling 

 analyses. 
3-1 

3.0 BART METHODOLOGY OVERVIEW 

EPA Region 8 identified the BART-eligible sources in Montana as being in one of the 

Clean Air Act “26 named source categories” which include steam electric plants, having 

potential SO2, NOx, VOC or PM emissions of 250 tons per year (tpy) or more, and having 

construction dates between 1962 and 1977. These eligibility criteria include Corette as a BARTeligible source. 

As recommended by EPA, the CALPUFF model was used to predict visibility impacts 

for maximum daily actual operating conditions during the modeling period (2001-2003) and for 

each emission reduction alternative evaluated for the retrofit control options. For SO2 and NOx, 

the cost effectiveness analysis was based on emission rates typical of 30-day average emissions. 

For filterable particulate, CEM data are not available and a distinction between maximum actual 

and typical emission rates was not made. 

 Potentially applicable retrofit filterable PM, SO2, and NOx control technologies which 

represent the full range of demonstrated alternatives for large coal-fired boilers were identified 

from the technical literature. The identified control options were reviewed to determine whether 

or not they are technically feasible for use with the emission units (i.e., the control technologies 

have been successfully installed and operated on similar sources or the technology could be 

applied to the source). Those control options were then compared to determine their relative 

performance levels using consistent metrics. 

 In addition to determining the performance metric, other aspects of each technically 

feasible retrofit control technology were evaluated based on the technical literature and plant 

specific information. These aspects included: 

• The capital and operating cost 

• The energy impacts 

• The environmental impacts 

• The remaining use-life of the emission units 

• The visibility impacts 

Based on the information compiled for each of the steps above, evaluations were 

conducted regarding retrofit controls applicable to the Corette boiler. 
3-2 

Capital and Operating Cost

To estimate the capital and operating cost of control technologies, information from the 

U.S. Environmental Protection Agency, Control Cost Manual (EPA, Air Pollution Control Cost 

Manual, Sixth ed., EPA-452-02-001, January 2002) was utilized where such data were available. 

The BART Final Rule states: 

“In order to maintain and improve consistency, cost estimates should be based on the 

OAQPS Control Cost Manual where possible. The Control Cost Manual addresses most 

control technologies in sufficient detail for a BART analysis.” 

Other EPA information to supplement the Control Cost Manual included a fact sheet on 

SO2 scrubbing using wet and dry technologies that was not available for inclusion in the OAQPS 

Manual in 2002. This and other sources of information for the BART costing are referenced 

where appropriate in the text. The application of EPA recommended factors to the capital cost to 

itemize direct and indirect installation costs is also used in the analyses. 

For the capitalization of the total cost of a technology, PPL uses 11 years as its standard 

depreciation schedule, consistent with the tax code applicable to the facility. Therefore this 

capitalization period with an interest rate of 7 percent per annum was used throughout. Costs 

were corrected to 2007 dollars using the U.S. Department of Commerce, Implicit Price Deflator 

cost index. 

Energy Impacts

The inherent energy consumption to operate air pollution control equipment is 

appropriate for inclusion in the annual operating cost analysis. The cost of energy consumption 

for plume reheating was included as a potential implementation cost for the wet scrubbing 

control option based on PPL's experience at the Colstrip plant where wet scrubbing technology is 

used. 

Environmental Impacts 

 In some technology applications, a new waste stream is generated or an existing waste 

stream increases. As examples of this, an enhanced removal of PM accordingly increases the 

solids collected. The addition of scrubbing solids to react with SO2 may change the character of 

the ash residue and alter its salability. In the case of some NOx reduction technologies, ammonia 
3-3 

used in the catalytic reduction equipment is an additional pollutant that can increase PM 

formation. 

Remaining Useful Life

The life of the Corette boiler is expected to exceed the study period and is projected to 

have no effect on the costing analyses for this facility. 

Visibility Impacts

 The modeled results for visibility impact, in units of deciviews, of application of the 

selected BART options were determined as a result of this study.
4-1 

4.0 BART ANALYSES

4.1 Approach

For this BART analysis retrofit emission control technologies applicable to Corette were 

evaluated with respect to particulate emissions (PM-filterable portion only), sulfur dioxide (SO2) 

and nitrogen oxides (NOx). The analysis included review of the technologies listed in: 

• EPA’s Clean Air Technology Center (the RACT/BACT/LAER Clearinghouse) 

• State and Local Best Available Control Technology Guidelines 

• Control Technology Vendors 

• Federal/State/Local permits and associated inspection/performance test reports 

• EPA’s NSR Bulletin Board 

• Department of Energy’s Clean Coal Program Technical Reports 

The first step in the five step case-by-case BART analysis was identification of “all” 

retrofit options. These include those with a potential for application to the emissions unit and 

pollutant under consideration for the nominal gross capacity of about 162 megawatt (MW) steam 

electric plant boiler emissions unit located at Corette. 

The Corette boiler fires sub-bituminous coal having a sulfur content typically under 1 

percent by weight. The single boiler has an electrostatic precipitator for PM control, no SO2

controls, and low-NOx burners to reduce NOx. In accordance with the Final Rule BART 

Guidelines (FR, Vol. 70, No. 128), a case-by-case BART analysis must identify the most 

stringent control option and a reasonable set of options for analysis that reflects a comprehensive 

list of available technologies for each pollutant. The list is considered complete if the list 

includes the maximum level of control that each technology is capable of achieving. 

 The New Source Performance Standards (NSPS) for Electric Utility Steam Generating 

Units (EUSGUs) are based on EPA's recent review of the state-of-the-art controls for PM, SO2, 

and NOx for electric utility boilers. The first such standards (Subpart D), which applied to fossil 

fuel-fired steam electric generators, were promulgated on December 23, 1971. Standards 

specific to EUSGUs (Subpart Da) were promulgated on June 11, 1979. On February 27, 2006 

(see FR, Vol. 71, No. 38) the PM, SO2, and NOx Subpart Da standards were revised to reflect 

improvements in emissions control since the promulgation of the previous NSPS standards. The 

discussions provided in proposing the rule indicated that revisions to emissions standards of 

Subpart Da are appropriate in light of the control technology developments since the previous 

version of the standards in 1979 and recent technological improvements in control technology. 

Although the new emission standards apply to units constructed after February 27, 2005, they 
4-2 

represent the most stringent level of emissions control for new EUSGUs. These present NSPS 

standards are presented in Table 4-1. 

A summary of the Corette allowable emission rates (as listed in the Title V permit for the 

facility), actual emission rates, the presumptive BART levels and the NSPS for PM, SO2, and 

NOx is provided in Table 4-1 The NSPS applies to new or modified sources and may be more 

stringent than a best available retrofit technology emission level. The development of the new 

emission standards for PM, SO2, and NOx by EPA are discussed in the following sections. 

Table 4-1: Allowable / Current/ NSPS/ Presumptive Emission Limits 

for the PPL Montana, LLC, 162 Gross MW J.E. Corette Power Plant 

 

Filterable Particulate Matter Sulfur Dioxide Nitrogen Oxides 

Limit Units Limit Units Limit Units 

Permitted 

Allowable(1) 0.26 lb/MMBtu 1 lb/MMBtu 0.4 lb/MMBtu 

Emission 

Rate (as S) 

 

Typical 

Current 0.082 lb/MMBtu 0.46 lb/MMBtu 0.26 lb/MMBtu 

Emission 

rate (2001 to 2005 average) (from CEMS)) (from CEMS)) 

 

BDT(3) from 

2006 NSPS 0.015 lb/MMBtu 1.4 lbs SO2/MW out 1.0 lb/MW out 

New 

Sources (0.15 lb/MM Btu in) (0.11 lb/MM Btu in) 

 

Presumptive 

(4) 

BART for 0.15 lb SO2/MMBtu(5) 0.15 lb/MMBtu(6)

Large 

EUSGUs 95 % control (tang fired sub-bituminous) 

 

Notes 1) From current Title V Operating Permit 

 2) EPA Reference Method 5 for PM and from coal analysis for SO2 

 3) BDT = "Best Demonstrated Technology" - From FR Vol. 71, No. 38, Monday, 

 From FR Vol. 71, No. 38, Monday February 27, 2007, Final Rule (NSPS for EUSGUs) 

 February 27, 2006, Final Rule (NSPS for EUSGUs) - the 2006 standards 

 were revised to a gross MW output basis (equivalent in lb/MMBtu input values listed in paren)

 4) Applicable to EGU's > 200 MW at plants with output > 750 MW in size and without 

 pre-existing pollutant-specific controls 

 5) Not applicable to either Colstrip or Corette under the BART Guidelines 

 6) Not applicable to Corette under BART Guidelines 
4-3 

EPA’s Regulatory Approach to the NSPS Revisions

 The publication of the Proposed Rule in 2005 in which new standards were proposed for 

EUSGUs included the following statement: 

“We have reviewed emissions data and control technology information applicable to 

criteria pollutants and have concluded that regulation of NOx, PM, and SO2 emissions 

from these sources under the NSPS is appropriate. The proposed amendments to the 

NSPS reflect the BDT (Best Demonstrated Technology) for these sources based on the 

performance and cost of the emission technologies discussed above.”

In the BART Final Rule, EPA does not limit BART analysis to NSPS standards (see FR 

Vol. 70, No. 128/Wednesday, July 6, 2005, p. 39164, bottom center) where EPA notes: 

In EPAs 1980 BART Guidelines for reasonably attributable visibility impairment, we 

concluded that NSPS standards generally, at that time, represented the best level sources 

could install as BART. In the 20-year period since this guidance was developed, there 

have been advances in SO2 control technologies, as well as technologies for the control 

of other pollutants, confirmed by a number of recent retrofits at Western power plants. 

Accordingly, EPA no longer concludes that the NSPS level of controls automatically 

represents “the best these sources can install”. Analysis of the BART factors could result 

in the selection of an NSPS level of control, but you should reach this conclusion only 

after considering the full range of control options.” 

Certainly to use the original Subpart Da NSPS emission standards (circa (1979) as 

proposed BART controls would fall under this BART Final Rule admonition. However, the very 

recently updated NSPS limits for PM, SO2, and NOx in the 2006 Final Rule, which EPA 

determined to be the best demonstrated technology for new sources, could be concluded to be as 

stringent or more stringent than BART for the PPL Corette coal fired boiler. The present NSPS 

levels for PM and SO2 were considered as well as the SO2 and NOx presumptive BART levels 

and other control levels in the BART evaluation. The presumptive BART levels were used as 

the lowest level evaluated although they actually do not apply to Corette because Corette is 

below the size cutoff of the presumptive levels. The new NOx NSPS level is below the 

presumptive BART level and was not evaluated. 

4.1.1 Particulate Matter 

In the proposed rule, EPA discussed the following available particulate matter control 

technologies: 
4-4 

• Electrostatic Precipitators 

• Fabric Filters (Baghouses) 

• Mechanical Collectors 

• Wet Scrubbers 

Electrostatic Precipitators

Electrostatic precipitators, commonly known as ESPs, utilize an electric field to ionize 

fine particulate matter in a flowing gas using high voltage electrodes. The ionized particles are 

then attracted to an oppositely charged tube or plate upon which layers of particles build over 

time. The ESP is typically composed of a large box-type structure with several sections of 

electrified parallel plates or tubes and rappers to periodically remove accumulated particulate. 

The collected material falls into a hopper and is disposed properly. ESP technology is capable of 

high removal efficiencies of 99 percent or higher even on very fine particulate. Wet ESPs are 

sometimes used where the plates are cleaned with water sprays, however, they can emit visible 

plumes. 

Fabric Filters (Baghouses)

Fabric filter baghouses contain numerous woven cylindrical bags with particle laden 

gases passing through the cloth material where the solid particles deposit on the bag surface. 

With time, the filter cake that develops must be removed by one of three common methods 

which include blasts of reverse flow air injected into the bag, a mechanical shaking system, or a 

blast of sonic energy. Fabric filters are highly efficient on very small particles and are capable of 

achieving high efficiencies of 99 percent or higher similar to ESP technology. 

Mechanical Collectors 

Mechanical collectors use inertial energy to separate particles by physical means only. 

The devices are cylindrical with a tangential gas inlet that induces a spinning motion to a particle 

laden gas stream with particles driven to the sides of the cylinder and gas with a reduced particle 

concentration exiting the top of the cyclone. For large gas flows, numerous parallel cyclones are 

typical and are called multiple cyclones. These devices are mostly used as pre-filtration devices 

to remove the largest particles and can remove up to 80 percent of only the largest particles. 
4-5 

Wet Scrubbers

 If water is injected into a cyclone, impaction of particles on water droplets enhances 

removal and effectively scrubs the gas. The most common type of scrubber is a venturi scrubber 

where water is injected into the exhaust at the throat of a converging section of duct. The 

converging section of duct increases particle velocity and decreases water droplet size such that 

high removal efficiencies can be attained. Scrubbers have the advantage of being capable of 

reacting with SO2 under conditions that allow reaction of this pollutant to form water soluble 

sulfite and sulfate compounds. 

4.1.2 Sulfur Dioxide 

 In their discussion of the available SO2 control technologies in the Proposed Rule that led 

to revision of the NSPS for SO2 in February 2006, EPA lists the following available control 

technologies: 

• Coal Pre-Treatment 

• Alkali Wet Scrubbing 

• Limestone Scrubbing with Forced Oxidation 

• Spray Dryer Absorption 

• Dry Injection 

Coal Pre-Treatment

There are two basic coal pre-treatments that can reduce SO2 emissions: physical coal 

cleaning and gasification. Physical cleaning can remove 20 to 90 percent of pyritic sulfur in coal 

but cannot remove organic sulfur. Gasification processing can reduce sulfur content by over 99 

percent. 

 

Alkali Wet Scrubbing

 Wet scrubbing using a solution of water and lime or limestone, otherwise known as fluegas desulfurization (FGD), creates intimate contact of flue-gas with the reactive solution in a 

contact device. Each application of FGD scrubbing is dependent on the fuel sulfur content, and 

the scrubber design parameters, however, up to 98 percent removal of SO2 has been 

demonstrated. 
4-6 

Limestone Scrubbing with Forced Oxidation (LSFO)

 This is a variation on alkali wet scrubbing where compressed air is used to oxidize 

sulfites in the absorption solution of sulfates. Oxidation creates gypsum which is a salable 

byproduct for wallboard manufacturers. Oxidation makes the solids easier to remove from 

solution and facilitates waste disposal. 

Spray Dryer Absorption

 An alkali containing slurry is used in spray form to contact the SO2 laden flue gas prior to 

the particulate collection device. Removal of SO2 depends on the stoichiometric ratio of reactant 

to sulfur and the degree of saturation attained in the spray-dryer vessel. Solids from the PM 

collection device may be recycled to the absorber to attain optimal absorption and utilization of 

the reactant. Such systems generally attain greater than 90 percent control. 

Dry Injection

 Dry solid absorbent is injected directly into the ductwork upstream of the PM collection 

device. SO2 removal occurs by adsorption of the pollutant on the particle surface and collection 

of the resulting solids with the fly ash in the PM control device. Lime or limestone based dry 

injection systems typically do not perform as well as FGD systems and attain 40 to 60 percent 

removal, but may achieve up to 90 percent removal if another sorbent such as sodium 

bicarbonate is used. 

4.1.3 Nitrogen Oxides

There are both primary and secondary categories of NOx controls in EUSGUs. 

Primary NOx Combustion Controls 

• Low-NOx Burners (LNBs) 

• OFA (Over-Fire Air) also known as air staging 

• LNBs with OFA 

• Rotating Opposed Fire Air (ROFA) 

• Combustion Improvement Techniques 

Secondary Control Techniques 

• Reburning 

• Selective Catalytic Reduction (SCR) 

• Selective Non-Catalytic Reduction (SNCR) 
4-7 

Low-NOx Burners (LNBs)

This technique requires control of the combustion stoichiometric air/fuel ratio and the 

boiler temperature profile. NOx formation is dependent on peak flame temperature and the 

availability of excess air in and around the combustion zone. Reduction of the oxygen content in 

the primary reaction zone and the attendant reduction in peak flame temperature limit NOx

formation. Also, limitation in peak flame temperature residence time also will lower NOx

emissions. By introducing combustion air in stages, and thoroughly mixing gases in the 

combustion chamber to reduce hot zones, significant reductions of 35 to 55 percent can be 

realized (Srivastava, Ravi K., et al., Nitrogen oxides Emission Control Options for Coal-Fired 

Electric Utility Boilers, Journal of the Air and Waste Management Association, Volume 55, 

September 2005). 

LNBs can have undesirable side-effects that include an increase in the amount of 

unburned carbon (UBC). This can be an increase in UBC of up to 2 percent, however, the 

largest impacts are on small units where UBC is already high. In Powder River Basin (PRB) 

coal-fired boilers it is possible to limit the increase in UBC to less than 0.5 percent.

Over-Fire Air (OFA) or Air Staging 

 In air staging, 5 to 20 percent of the combustion air is not injected into the main burner 

and is instead introduced above the main burner location. Adding OFA to LNB technology can 

reduce LNB NOx levels by an additional 10 to 25 percent. Particularly significant NOx

reductions can result from the application of these techniques to tangentially-fired boilers 

resulting in a 50 percent decrease in NOx reductions with only a 25 to 35 percent increase in 

UBC. Increases in CO emissions can be limited to 50 ppm @ 3% O2.

Rotating Opposed Fire Air (ROFA) or Separated Overfire Air (SOFA)

The addition of a combustion air fan to inject high velocity air that breaks up the fireball 

within the firebox smoothes out temperature profiles and oxygen levels and typically does not 

result in increases in UBC or CO emissions. An improvement in boiler heat rate may actually 

occur. 
4-8 

Combustion Improvement Techniques

 Site and boiler specific controls that monitor the fuel and air flow to each burner are 

available. Through computational fluid dynamic modeling, boiler operation can be fine-tuned 

with optimization of the locations of OFA injection to obtain optimum results. 

Selective Catalytic Reduction (SCR)

 The SCR process utilizes a honeycomb bed of active metal catalyst impregnated zeolite 

to reduce NOx to its molecular nitrogen starting form. Ammonia or an ammonia-like substance 

such as urea is injected upstream of the catalyst bed and by using the proper injection ratio of 

ammonia to NOx, the “reduction” of NOx to N2 and H20 occurs. The process is temperature 

dependent and coal-fired boilers typically locate the catalyst bed in the boiler between the 

economizer outlet and the air preheater where the necessary reaction temperature of 450 to 750 

degrees F is found. This technology is capable of 90 percent or greater NOx control. 

Selective Non-Catalytic Reduction (SNCR)

 In this control technique, ammonia or an ammonia-like reagent is injected into the 

combustion chamber where the flue gas is in the range of 1,600 to 2,000 degrees F. The same 

reactions that reduce NOx to nitrogen and water occur with SNCR, but without the catalyst bed. 

The technique only attains 30 to 50 percent NOx control. 

4.1.4 Pollutant Emissions from Corette

The Gross 162 MW coal fired unit at the J. E. Corette power plant shows the following 

maximum daily actual PM, SO2 and NOx emission rates in Table 4-2: 

Table 4-2: Corette Emissions Summary 

Fuel Control Heat Input Pollutant Filt Cond Total Filterable Condensable Total 

 Equip MMBtu/hr lbs/hr lbs/hr lbs/hr lb/MMBtu lb/MMBtu lb/MMBtu 

 

Coal ESP 1941.1 PM 159.17 27.18 186.4 0.082 0.014 0.096 

Coal None 1894.5 SO2 N/A N/A 1135 N/A N/A 0.60 

Coal LNB 1930.4 NOx N/A N/A 604 N/A N/A 0.31 

 
4-9 

The heat input rate shown above for PM is the highest daily average heat input rate 

during the modeling years (2001-2003). The total PM emission rate applied to this heat input 

rate is 0.096 lb/MMBtu based on stack test data. For SO2 and NOx, the heat input rate shown is 

the daily average rate for the day of highest daily SO2 and NOx emissions during the modeling 

years. The speciation of the PM emissions is described in Section 2.3. The above data show that 

emission rates from Corette are already low due to the ESP control technology for PM, low 

sulfur coal (0.3 wt % S), and low-NOx burners. The 0.082 lbs/MMBtu filterable PM emission 

rate and 0.014 lb/MMBtu condensables emission rate are based on stack emission tests 

conducted during the modeling years. The current ESP technology is an old design and new 

designs are capable of meeting the BDT limit from the revised NSPS. 

4.2 Evaluated Retrofit Technologies for J.E. Corette

It is necessary, as part of the BART analysis, to identify the most stringent control option 

and a reasonable set of options for each pollutant. The following list of potential control 

technologies has been evaluated for J.E. Corette: 

Filterable Particulate Matter (Section 4.2.1) 

• PM Control Alternatives Summary (Table 4-3) 

• Electrostatic Precipitators (Table A4-4(a)) 

• Fabric Filters (Baghouses) (Table A4-4(b)) 

• Mechanical Collectors 

• Wet Scrubbers 

Sulfur Dioxide (Section 4.2.2) 

• SO2 Control Alternatives Evaluated (Table 4-7) 

• Clean Fuel 

• Dry Gas Scrubbing (Tables A4-7 and A4-8) 

• Flue Gas Desulfurization (Wet Scrubbing) (Table A4-9) 

Nitrogen Oxides (Section 4.2.3) 

• NOx Control Alternatives Evaluated (Table 4-10) 

• Upgrade of Low NOx Burners (Baseline) (Table A4-11) 

• LNBs with SOFA (Table A4-12) 

• Selective Non-Catalytic Reduction (SNCR) (Table A4-13) 

• Selective Catalytic Reduction (SCR) (Table A4-14) 

A technology is considered as a BART option if it is considered an “available” and 

“applicable” technology. A technology is considered available if it has reached the licensing and 
4-10 

commercial demonstration phase. EPA feels that this may change during the BART review 

process up to and including the public comment phase. 

In addition to a control technology being available, it must also be applicable. Generally, 

a technology that has been applied to the source type under consideration indicates that the 

control technology is applicable. This is not always true, and site specific factors could preclude 

the technology from being applied at a particular source due to space constraints, reliability 

factors, or adverse effects on the rest of the facility. 

4.2.1 Particulate Matter Controls 

4.2.1.1 Summary of PM Control Technology Analyses for Corette

Table 4-3 shows a comparison of the maximum 24-hr emission rate used as a modeling 

baseline and the control alternative emission rate modeled. The “NSPS case” of 0.015 

lb/MMBtu is attained by either fabric filtration (FF) or electrostatic precipitator technology 

(ESP) as described in this section. Mechanical collectors are not capable of attaining the high 

efficiencies of removal required and were ruled out from consideration. Wet scrubbers, in use at 

the PPL Colstrip facility, are an available control option, however, this alternate technology was 

evaluated as primarily an SO2 removal control option and is discussed in Section 4.2.2. 

Table 4-3 is presented to show the technology cases evaluated for the BART analysis. 

While the modeled emission rates must represent the maximum 24-hr emission rate during the 

study period, BART guidance requires use of anticipated actual emission rates for the cost 

analysis. In the case of the pollutant PM, both FF and ESP control are assumed to be capable of 

attaining the BDT emission rate of 0.015 lb/MMBtu and were evaluated accordingly. 

In summary, only ESP and fabric filtration were further evaluated as filterable particulate 

control technologies for the sub-bituminous coal-fired boiler at Corette. 

4.2.1.2 Costs of Controls

The costs of modern ESP and fabric filter particulate controls for application to the 

Corette boiler were evaluated. The cost of control makes the assumption that adequate land 

acreage is available to locate the new devices. 
4-11 

Table 4-3: PM Control Alternatives Evaluated

Pollutant Control Option 

Typical/Average 

Emission Rate for 

Cost Analysis 

(lb/MMBtu) 

Maximum 

Emission Rate for 

Modeling 

(lb/MMBtu) 

PM (1) Base Case 0.082 (f) 

0.014 (c) 

0.082 (f) 

0.014 (c) 

 

NSPS Case 0.015 (f) 

0.014 (c) 

0.015 (f) 

0.014 (c) 

Note: (1) "f" refers to filterable and "c" refers to condensable particulate. 

The cost of ESP control is based on a base cost in 1986 dollars of $60/kW as shown in 

Figure 4-1 from AWMA (AWMA, Air Pollution Engineering Manual, Air & Waste 

Management Association, Anthony J. Buonicore and Wayne T. Davis, eds., Van Nostrand 

Reinhold, 1992) for 99 percent control. Table A4-4(a) shows the costing calculations for an 82 

percent reduction from present emissions levels, which would reduce filterable particulate 

emissions to 0.015 lb/MMBtu. The table presented illustrates the costs for an ESP designed to 

control filterable PM to the NSPS level for new sources of 0.015 lbs/MMBtu from the current 

level. This is a fair and reasonable calculation of cost effectiveness (CE) to attain the NSPS 

level. 

The summary analysis of the cost of ESP control presented in Table 4-4 (see Appendix 

A, Table A4-4(a) for details) was prepared using the standard cost estimation techniques from 

EPA (EPA 2002). The approach uses percentage factors applied to the purchased capital 

equipment cost to estimate a total installed capital cost for installation of an ESP. EPA factors 

specifically developed for ESP technology were used. An annualized capital cost of the 

equipment was determined using a capital recovery factor based on an equipment life of 11 

years, and assumed that money is available at an annual interest rate of 7 percent. 

All equipment cost data are corrected to 2007 dollars. The cost estimates have been 

prepared for the Corette boiler using an annual capacity factor of 89%. The electrification of the 

fields and rapper costs are based on the specific collection area estimated for the Corette boiler in 
4-12 

Figure 4-1: Cost Analysis of ESP Control 

Table 4-4: Particulate Cost Analysis Summary 

Option Description Total Annual

Tons 

controlled Cost 

 Cost ($) Effectiveness 

 $/ton 

 

Added ESP Control $10,721,795 507 $21,149 

Added Fabric Filtration $8,283,582 507 $16,339 

accordance with EPA recommendations. The annualized cost is an incremental cost to reduce 

the current PM emissions from the present 0.082 lb/MMBtu filterable emission rate to the 

present NSPS BDT level of 0.015 lb/MMBtu. Equipment maintenance, administrative annual 

costs, and all calculations use the standardized OAQPS control costing methods. 

The estimated cost calculated for a modern technology ESP to obtain the NSPS BDT for 

new sources of 0.015 lb/MMBtu is $21,149 per ton assuming that the unit operated at the 
4-13 

average annual capacity factor from among the three modeling years (2003-2005). This cost per 

year assumes an annual capacity factor of 89 percent. These estimates are based on OAQPS cost 

factors and engineering judgment and include a 1.4 multiplier on equipment cost as 

recommended by EPA in the Control Cost Manual. 

The cost estimate of a fabric filter added to the existing PM control to reduce emissions 

from 0.082 lb/MMBtu to the BDT level of 0.015 lb/MMBtu is presented in Appendix A, Table 

A4-4(b). A capital cost, adjusted to 2007 dollars was estimated at $50/kW. After application of 

the OAQPS cost factors to this capital cost and adding the annual material and maintenance costs 

for fabric filters, a CE value of $16,339 was determined. This is for an add-on fabric filter in 

series with the existing ESP controls. 

The cost of venturi scrubber installation is presented in Section 4.2.2. The control of PM 

with wet scrubbing is evaluated in conjunction with flue gas desulfurization (FGD) technology. 

A change to wet scrubbing controls would not be considered separately from the FGD aspect of 

such a device and is therefore discussed in the SO2 technology section. 

4.2.1.3 Energy

In addition to the costing data developed for each potential PM control option, energy 

consumption, in terms of the fan power to drive the exhaust gas through the control devices is a 

parameter that can be readily estimated for ESP, fabric filter, and venturi scrubber control. The 

energy cost of the control options is included in the cost effectiveness Tables A4-4(a) and A4-

4(b) in Appendix A. This motive power is directly related to the pressure drop of the particular 

control option and the following equation is offered by EPA as being representative of the 

required fan power for control devices throughout its Control Cost Manual: 

Power (kw-hrs/year) = 1.81 x 10-4 x ACFM x Δp x annual operating hours 

Where : 1.81 x 10-4 is a proportionality constant 

ACFM = the actual cubic feet per minute exhaust treated 

 Δp is the equipment pressure drop in inches of water column (w.c.) 

The following Table 4-5 is presented to illustrate the pressure drop/power consumption 

requirements of the four common types of PM control devices. Each technique has predictable 

energy consumption in terms of the pressure drop associated with the control option. For 

example, an ESP has numerous parallel flat plates with electrode wires to charge the particulate 
4-14 

Table 4-5: Representative Control Equipment Pressure Drops 

Control Option Typical Δp Reference Table or Page No. 

 (inches w.c.) 

ESP 0.09 to 0.38 EPA, 2002 Pg. 3-34 Section 6 

FF 6 to 7 EPA, 2002 Pg. 1-47 Section 6 

MC 4 Vendor Estimate 

VS < 100 AWMA Table 5.4-5 

 

passing into the collector. The pressure drop within the device is very low. Fabric filter 

baghouses expectedly have a higher pressure drop due to the fabric filter passages which are 

much smaller than the widely spaced plates in an ESP. The spinning motion of the multiple 

cyclone (MC) leads to the loss of considerable energy in a typical 4” w.c. drop, and the venturi 

scrubber (VS), attains its relatively high collection efficiency at the expense of up to a 100” 

pressure drop required for fine PM collection. 

 

4.2.1.4 Non-Air Quality Environmental Impacts

All PM controls for Corette, whether upgraded or new, generate a PM waste stream. The 

current ash collected by the ESP is sold as a product to the cement industry. Operation of PM 

controls to collect an additional 82 percent of current PM emissions at Corette would generate 

approximately 507 tons per year of additional fly ash waste based on 2003 to 2005 annual 

operation of the units. 

For the venturi scrubber control option, reheating would be mandatory and would reduce 

the available electrical generation due to the energy required to heat the exhaust. Reheating 

would be required to satisfy plume buoyancy permit requirements for the Corette plant. Based 

on the Colstrip boiler reheating experience, a 30 MW loss in power output from the plant would 

result to eliminate a highly visible steam plume. 

4.2.1.5 Remaining Useful Life

The PPL Corette boiler is expected to remain in operation for the foreseeable future and 

therefore an 11-year control equipment life, consistent with the financial approach of Corette 

amortization has been assumed for the control cost analyses. 
4-15 

4.2.1.6 Visibility Modeling

 The predicted visibility impacts from the present (base case) Corette particulate, SO2 and 

NOx emissions and for the alternative filterable particulate control level evaluated (0.015 

lb/MMBtu) are summarized in Table 4-6. Shown in the table are the highest of the annual 98th 

percentiles of daily modeled visibility impacts among the three years modeled (2001-2003) and 

the seven Class I areas modeled. The highest of those visibility impacts among the Class I areas 

modeled are presented. For the modeled control alternative, the emissions of filterable 

particulate were at its controlled level (0.015 lb/MMBtu) and the emissions of the other 

pollutants were at their base case levels. Also presented in the table are the largest differences 

between the 98th percentile values for the base case and the evaluated particulate control 

alternative at any of the Class I areas. This difference is shown relative to the base case. 

 

Table 4-6: Summary of Modeling Results for Particulate 

Emissions (1) Deciview Difference (2) 

Control Option 

lb/MMBtu lb/hr 

Max 98th 

Percentile 

Prediction(2) 

(deciviews) 

Relative to 

Base Case 

Incremental 

Base Case 0.082 (f) 

0.014 (c) 

159.2 (f) 

27.2 (c) 

0.645 --- --- 

NSPS Case 0.015 (f)) 

0.014 (c) 

29.11 (f) 

27.2 (c) 

0.633 0.032 (2) 0.032 

NOTES: (1) "f" refers to filterable and "c" refers to condensable particulate. 

 (2) The maximum (98th percentile) deciview impact occurs at the UL Bend Class I 

area and the maximum difference of the 98th percentiles between the base case and 

control alternative evaluated occurs at the Washakie Class I area. 

The visibility modeling results are described and presented in more detail in Section 4.3 

and Appendix B. 

4.2.2 Sulfur Dioxide Controls

4.2.2.1 Controls and Emission Rates Evaluated

Table 4-7 presents the modeled emission rates and the typical/average emission rates used 

in the costing analysis for the control alternatives selected. For the PRB coal burned at Corette, 

the installation of controls is expected to result in 25 to 70 percent reduction 
4-16 

Table 4-7: SO2 Control Alternatives Evaluated

Pollutant Control Option 

Typical/Average 

Emission Rate for 

Cost Analysis 

(lb/MMBtu) 

Maximum 

Emission Rate for 

Modeling 

(lb/MMBtu) 

SO2 Base Case 0.46 0.60 

Dry Injection 

(25% Reduction) 0.35 0.46 

Dry Injection 

(70% Reduction) 0.15 0.20 

Wet Scrubber 0.15 0.15 

 

over current emission rates. Two dry gas scrubbing emission rates and installation of a wet 

scrubber were evaluated for the costs of control and other associated impacts. 

The sub-bituminous coal fired boiler at Corette utilizes low-sulfur (0.3 weight percent 

sulfur) Powder River Basin coal. With long term contracts for the use of such coal, the baseline 

emissions for the Corette boiler are already low at 0.6 lb/MMBtu of SO2, corresponding to the 

maximum 24-hr average emissions during the modeling years, and are actually lower with a 

typical emission rate of 0.46 lb/MMBtu when the actual sulfur content of the fuel is considered. 

The Corette boiler is equipped with CEMS for SO2 which were used to determine the maximum 

24-hr average SO2 emissions. 

Coal cleaning to reduce SO2 emissions in addition to that performed prior to delivery to 

Corette would have no substantial effect on SO2 emissions. PRB coal already has maximum 

sulfur levels of 0.3 weight percent, and any further reduction in this fuel sulfur content by any 

mechanical means is not expected. The option to gasify the coal for sulfur removal is a complete 

change in the method of operation for Corette which was given no consideration. 

 The controls evaluated to improve SO2 emission rates to below the levels attained by 

using the low-sulfur content coal included dry scrubbing techniques and wet scrubbing (FGD) 

technology. With emissions already at very low levels, the dry techniques are limited in their 

ability to attain very high SO2 removals without impacting the PM emissions with the existing 

ESP controls. In view of the alkaline nature of PRB coal, some inherent reaction between SO2

and flyash likely accounts for a typical SO2 emission rate (from CEMS data) of 0.46 lb/MMBtu. 

PPL estimates that about a 25 percent increase in SO2 removal can be attained by chemical 

addition using dry injection technologies (injection of lime or limestone) before impacting the 
4-17 

PM emission rate. If, however, a new ESP were to be installed, additional SO2 removal could be 

attained without impacting PM compliance. 

 Installation of a wet scrubber (FGD) has been evaluated for Corette. As discussed above, 

the alkaline nature of the PRB coal burned at Corette is conducive to SO2 removal which is more 

evident with water scrubbing. Based on the PPL facility at Colstrip, wet scrubbing using venturi 

scrubbers produces approximately 75 percent SO2 removal without the addition of lime in Units 

1 and 2 at Colstrip. Based on the PPL experience at Colstrip and EPA cost estimations for wet 

scrubbers, an analysis of wet scrubbing is included herein. An emission rate of 0.15 lbs/MMBtu 

was used as the control level. This level was used because it is the presumptive BART emissions 

level, although the Corette boiler is below the size threshold for which this presumptive level is 

intended. 

4.2.2.2 Cost of SO2 Controls 

 PPL used EPA cost estimation techniques to evaluate the cost implications of wet and dry 

technology applications for SO2 to the Corette boiler (EPA-CIAC Fact Sheet, EPA-452/F-03-

034, Air Pollution Control Technology Fact Sheet, Flue Gas Desulfurization (FGD) – Wet, Spray 

dry, and Dry Scrubbers, 2003). The EPA fact sheet is a summary of the costs and capabilities of 

various FDG techniques to coal fired boilers. A large variation in the capital cost of such 

systems in units of $/MW is observed. While EPA lists a range of cost effectiveness (CE) values 

in $/ton of SO2 controlled that ranges from $500 to $4,000, the low sulfur PRB coal makes the 

CE for Corette more expensive. 

The EPA data show a capital cost for spray dry controls that ranges from 150 to 1500 

$/KW and an operations and maintenance (O&M) cost of $10 to $300 per KW. Using the low 

end of the range for the nominal case of dry chemical addition to boiler exhaust and utilization of 

the existing ESP, Table 4-8 is a summary of the cost analysis of the SO2 control options. Details 

of each analysis are presented in Appendix A, Tables A4-7 and A4-8. 

 A change to wet scrubbing at Corette was evaluated for CE by use of the average capital 

cost of such systems as indicated by EPA on their fact sheet. The estimated cost of a wet 

scrubber to control emissions to 0.15 lb/MMBtu, presented in Table A4-9 in Appendix A, is 

$25,480 including the loss in revenue due to plume reheating. 
4-18 

Table 4-8: SO2 Control Cost Summary 

Option Description Total Annual

Tons 

controlled Cost Incremental 

 Cost ($) Effectiveness CE $/ton 

 (CE) $/ton 

 

Dry Gas Scrubber Option 

1 $6,773,630 832.3 $8,138 

Dry Gas Scrubber Option 

2 $87,797,502 2345.7 $37,429 $53,538 

Wet Scrubber (FGD) $59,768,829 2345.7 $25,480 $35,017 

4.2.2.3 Energy Impacts of SO2 Controls

 The most significant impact of SO2 controls at Corette would occur with a change to wet 

scrubbing controls for SO2. The operation of wet venturi scrubbers has an energy cost in terms 

of additional fan power to overcome higher pressure drops (see Table 4-5). Additionally, based 

on experience at PPL Colstrip, reheating of the plume to meet permit requirements for plume 

buoyancy would reduce the available power output from Corette by approximately 30 MW or 

18.5 percent. 

4.2.2.4 Non-Air Quality Impacts of SO2 Controls

 Corette currently generates revenue from the sale of 30,000 tons of PM to the cement 

industry at $4/ton. Contamination of the PM ash with dry scrubbing wastes would render the 

solids unacceptable for use as a cement additive. This, coupled with the added PM due to sulfite 

and sulfate and excess scrubbing reagent, and the waste disposal cost of $40/ton are strong 

disincentives for application of the additional SO2 controls. 

The use of limestone contributes to greenhouse gas emissions by release of the CO2

portion of the limestone reaction with SO2. Full implementation of dry gas scrubbing at Corette 

would release almost 1700 tons of CO2 in the process from calcinations of limestone. 

4.2.2.5 Remaining Useful Life

The life of the Corette boiler is expected to exceed the study period and is projected to 

have no effect on the costing analyses for this facility. 
4-19 

4.2.2.6 Visibility Modeling

 The predicted visibility impacts from the present (base case) Corette SO2, NOx and 

particulate emissions and for the alternative SO2 control levels evaluated are summarized in 

Table 4-9. Shown in the table are the highest of the annual 98th percentiles of daily modeled 

visibility impacts among the three years modeled (2001-2003) and the seven Class I areas 

modeled. For the modeled control alternatives, the emissions of SO2 were at its controlled level 

and the emissions of the other pollutants were at their base case levels. Also presented in the 

table are the largest differences between the 98th percentile values for the base case and the 

evaluated control alternatives at any of the Class I areas. These differences are shown relative to 

the base case and also incrementally relative to the immediately preceding control alternative in 

terms of the level of emissions reduction attained. 

Table 4-9: Summary of Modeling Results for SO2

Emissions Deciview Difference 

Control Option 

lb/MMBtu lb/hr 

Max 98th 

Percentile 

Prediction 

(deciviews) 

Relative to 

Base Case 

Incremental 

Base Case(1) 0.60 

 

1135.0 0.645 --- --- 

Dry Injection 

(25% Reduction) 0.46 892.9 0.568 0.077 0.077 

Dry Injection 

(70% Reduction) 0.20 388.2 0.446 0.199 0.147 

Wet Scrubber 0.15 291.2 0.407 0.238 0.049 

NOTE: The maximum 98th percentile base case deciview impact of 0.645 deciviews occurs 

 at the UL Bend Class I area. Maximums (98th percentiles) and maximum changes 

 from them for the control alternatives occur at the UL Bend, Washakie or North 

 Absaroka Class I Areas. 

 

The visibility modeling results are described and presented in more detail in Section 4.3 

and Appendix B. 

4.2.3 NOx Controls

4.2.3.1 NOx Controls and Emission Rates Evaluated 

At Corette, four control options were evaluated as presented in Table 4-10. The 

maximum and the typical/average emission rates are those determined from review of CEMS 
4-20 

data and estimates of how the indicated controls will perform if applied at Corette. The Corette 

boiler is a tangentially fired unit equipped with low-NOx burners. A review of CEMS data 

revealed that the maximum daily NOx emissions during the 2001 to 2003 evaluation period 

corresponded to a NOx emission rate of 0.31 lb/MMBtu. While this value was used for BART 

modeling, a baseline value of 0.26 lb/MMBtu was used as a typical average NOx emissions rate 

for the BART cost analysis. This is maintained by operation of the low-NOx burners and close 

coupled over-fire air presently in operation at Corette. 

Table 4-10: NOx Control Alternatives Evaluated

Pollutant Control Option 

Typical/Average 

Emission Rate for 

Cost Analysis 

(lb/MMBtu) 

Maximum 

Emission Rate for 

Modeling 

(lb/MMBtu) 

NOx Base Case 0.26 0.31 

 Boiler Tuning 0.23 0.27 

 SOFA 0.18 0.21 

 SNCR 0.16 0.17 

 SCR 0.15 0.15 

PPL evaluated four control options for NOx reduction at Corette that included boiler 

tuning, SOFA, SNCR, and SCR add-on controls. Tuning or adjustment of the current 

configuration is predicted to reduce emissions to 0.23 lbs/MMBtu with a small, one time cost of 

$250,000. Adding SOFA and readjustment of the entire air distribution to the firebox is 

predicted to reduce NOx to 0.18 lb/MMBtu. The addition of SNCR is predicted to produce 

almost no additional NOx reduction (to 0.16 lb/MMBtu) over that obtained by SOFA at 

significant additional cost. A hot-side SCR to reduce NOx to the presumptive level for 

tangentially fired sub-bituminous coal-fired boilers of 0.15 lb/MMBtu was analyzed. This level 

(0.15 lb/MMBtu) was evaluated as a minimum emissions level because it is the presumptive 

BART emissions level, although the Corette boiler is below the size threshold for which this 

presumptive level is intended. 

 Reburning technology for application to Corette was not evaluated. This technology 

option is considered as the equivalent of SOFA. Both technologies produce fuel-rich zones in 

the combustion chamber which can reduce NOx emissions by significant amounts. Therefore, 

PPL limited the control evaluation to SOFA with an anticipated reduction to 0.18 lb/MMBtu. 
4-21 

4.2.3.2 Cost of NOx Controls

A summary of the costing analysis of the various control options for NOx are presented in 

Table 4-11. The detailed costing of the various options for NOx reduction is presented in 

Appendix A, Tables A4-11 through A4-14. Table A4-11 presents the annualized cost of 

implementation of a one-time tuning of the present LNB configuration. Table A4-11 utilizes 

information from a 2004 World Bank article (World Bank Low NOx Burner Costing, 

http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/aqnolow.stm, August 2004) on cost 

estimation for LNB technology and LNBs with over-fire air injection. The cost estimate for 

adding SOFA to the LNB technology, see Table A4-12, already present was estimated using the 

lower limit of the range of $10/kW because a baseline LNB is already installed and operating at 

Corette. Reduction from the present emission rate of 0.26 lb/MMBtu to 0.18 lb/MMBtu results 

in a CE of $914/ton (in 2007 dollars) of NOx controlled and an incremental cost of $1,375/ton 

over tuning alone. 

Table 4-11: NOx Costing Analysis Summary 

Option Description Total Annual

Tons 

controlled Cost Incremental 

 Cost ($) Effectiveness CE $/ton 

 $/ton 

 

Boiler Tuning $33,339 227.0 $147 

Separated Over-Fire Air $553,554 605.4 $914 $1,375 

SNCR $1,303,471 756.4 $1,723 $4,966 

SCR $3,624,027 832.4 $4,354 $30,518 

Conventional SNCR and SCR technologies were estimated using the EPA Control Cost 

Manual (U.S. Environmental Protection Agency, EPA Air Pollution Control Cost Manual, 6th

ed., EPA-452-02-001, January 2002). The cost analysis for application of SNCR is presented in 

Table A4-13 and the cost analysis for application of SCR is presented in Table A4-14. For 

SNCR, an emissions reduction from the present level of 0.26 lb/MMBtu to 0.16 lb/MMBtu 

results in a CE of $1,723/ton (in 2007 dollars) of NOx controlled and an incremental cost of 

$4,966/ton over SOFA. For SCR, a reduction from the present level of 0.26 lb/MMBtu to 0.15 

lb/MMBtu results in a CE of $4,354/ton (in 2007 dollars) of NOx controlled and an incremental 

cost of $30,518/ton over SNCR. 
4-22 

4.2.3.3 Energy Impacts of NOx Controls

Energy Impacts which accompany NOx controls are relatively few. The installation of 

SOFA can result in slight improvements in heat rate. This potential benefit has not been taken 

into account in this costing analysis. The power consumption of the fans and pumps and added 

pressure drop energy consumption of the add-on controls has been factored into the cost analysis. 

4.2.3.4 Non-Air Quality Environmental Impacts of NOx Controls

In addition to the increase in ash accompanying dry gas control of SO2 using the present 

or a new ESP, SO2 and NOx controls would contribute to rendering the current ash unsalable. 

While minimal as compared to the ash changes resulting from dry scrubbing techniques, some 

increase in carbon due to impacts to the combustion process could render the ash unsalable if a 

NOx option is implemented independent of an SO2 control option. 

4.2.3.5 Remaining Useful Life

The life of the Corette boiler is expected to exceed the study period and is projected to 

have no effect on the costing analyses for this facility. 

4.2.3.6 Visibility Modeling

 The predicted visibility impacts from the present (base case) Corette NOx, SO2 and 

particulate emissions and for the alternative NOx control levels evaluated are summarized in 

Table 4-12. Shown in the table are the highest of the annual 98th percentiles of daily modeled 

visibility impacts among the three years modeled (2001-2003) and the seven Class I areas 

modeled. For the modeled control alternatives, the emissions of NOx were at its controlled level 

and the emissions of the other pollutants were at their base case levels. Also presented in the 

table are the largest differences between the 98th percentile values for the base case and the 

evaluated control alternatives at any of the Class I areas. These differences are shown relative to 

the base case and also incrementally relative to the immediately preceding control alternative in 

terms of the level of emissions reduction attained. The visibility modeling results are described 

and presented in more detail in Section 4.3 and Appendix B. 

 
4-23 

Table 4-12: Summary of Modeling Results for NOx

Emissions Deciview Difference(2) 

Control Option 

lb/MMBtu lb/hr 

Max 98th 

Percentile 

Prediction(2) 

(deciviews) 

Relative to 

Base Case 

Incremental 

Base Case 0.31 604.0 0.645 --- --- 

Boiler Tuning 0.27 524.1 0.616 0.043 (2) 0.043 

SOFA 0.21 407.6 0.573 0.098 0.055 

SNCR (1) 0.17 330.0 0.544 0.125 0.055 

SCR 0.15 291.2 0.530 0.138(2) 0.054 

NOTES: (1) The deciview impacts for the SNCR case were interpolated between the SCR and 

 SOFA modeling results. All other cases were modeled. 

 (2) The maximum 98th percentile base case deciview impact of 0.645 deciviews occurs 

 at the UL Bend Class I area. Maximums (98th percentiles) and maximum changes 

 from them for the control alternatives occur at the UL Bend, Washakie or North 

 Absaroka Class I Areas. 

4.3 Visibility Modeling

Section 4.3.1 describes the general visibility modeling procedures and Section 4.3.2 

summarizes the results. The modeling procedures and results are is described in more detail in 

Appendix A. 

4.3.1 General Modeling Procedures

The CALPUFF model was used to assess the impact of emissions from Corette on 

visibility in the federal mandatory Class I areas within 300 km of the plant, as identified in 

Section 2.3 and shown in Figure ES-1. CALPUFF (Scire et al., 2000) is EPA's guideline model 

for long range transport and their recommended model for BART analyses. Modeling was 

conducted with three years of hourly meteorological data for the years 2001, 2002 and 2003. 

 The CALPUFF and CALMET model setup and input meteorological and emissions data 

were obtained from the WRAP website (http://pah.cert.ucr.edu/aqm/308/bart.shtml) provided by 

EPA Region 8 in a February 28, 2007 letter to PPL identifying the Corette boiler as subject to 
4-24 

BART and providing preliminary modeling results. The modeling conducted by TRC for PPL is 

based on those data files with the following exceptions: 

• Speciation of filterable and condensable particulate emissions was revised by PPL based 

on stack test data available during the modeling years (2001-2003). 

• There were a few modifications to the modeling as described in Appendix B. 

The present (base case) emissions modeled are presented in Table 2-1 and Table 2-2. 

The particulate emissions presented include a breakdown of the particulate emissions by species 

and size fraction. Table 4-13 presents the emissions (and a summary of the modeling results as 

described below) for each of the control scenarios evaluated. These modeled emissions are 

based on the maximum actual daily operation of the Corette boiler during the three-year 

modeling period as described in Section 2.2. 

The present base case visibility impact of the Corette boiler in each Class I area in terms 

of the deciview haze index was determined by comparing the combined visibility impact of the 

boiler's present emissions and the annual average background visibility level provided in the 

WRAP files against the background level alone. The similarly modeled visibility impacts of 

each of the control alternatives were then compared against the base case and each other to 

determine the degree of visibility improvement for each control alternative. 

4.3.2 Summary of Modeling Results

The highest of the annual 98th percentiles of daily modeled visibility impacts under the 

present base case emissions and the emissions control scenarios evaluated are presented and 

compared for each pollutant in Table 4-13. The 98th percentile comparison level, using the 

highest 98th percentile prediction from among the years modeled, is recommended by EPA as a 

visibility metric. The values presented are the highest of those visibility impacts among the 

seven Class I areas evaluated. A summary of the results for each Class I area is presented in 

Appendix A. 

 Under the present emissions case, the maximum 98th percentile Corette visibility impact 

as is 0.645 deciviews at the UL Bend Class I area. The deciview impact for each of the control 

alternatives is also provided in the table. For each control alternative modeled, the emissions of 

the controlled pollutant were at its controlled level and the emissions of the non-controlled 

pollutants were at their base case levels. Also provided in the table are the net changes in 
4-25 

Table 4-13: Summary of Modeling Results 

Emissions (4) Deciview Difference (2) 

Pollutant Control Option 

lb/MMBtu lb/hr 

Max 98th 

Percentile 

Prediction(2) 

(deciviews) 

Relative to 

Base Case 

Incremental 

SO2 Base Case(1) 0.60 

 

1135.0 0.645 --- --- 

Dry Injection 

(25% Reduction) 0.46 892.9 0.568 0.077 0.077 

Dry Injection 

(70% Reduction) 0.20 388.2 0.446 0.199 0.147 

Wet Scrubber 0.15 291.2 0.407 0.238 0.049 

 

NOx Base Case(1) 0.31 604.0 0.645 --- --- 

 

Boiler Tuning 0.27 524.1 0.616 0.043 0.043 

 

SOFA 0.21 407.6 0.573 0.098 0.055 

 

SNCR (3) 0.17 330.0 0.544 0.125 0.055 

 

SCR 0.15 291.2 0.530 0.138 0.054 

 

PM Base Case(1) 0.082 (f) 

0.014 (c) 

159.2 (f) 

27.2 (c) 

0.645 --- --- 

 

NSPS Case 0.015 (f)) 

0.014 (c) 

29.11 (f) 

27.2 (c) 

0.633 0.032 0.032 

NOTES: (1) The base case is the same for all three pollutants. 

 (2) The maximum 98th percentile base case deciview impact of 0.645 deciviews occurs at the 

 UL Bend Class I area. Maximums (98th percentiles) and maximum changes from them for the 

 control alternatives occur at the UL Bend, Washakie or North Absaroka Class I Areas. 

 (3) The deciview impacts for the SNCR case were interpolated between the SCR and SOFA 

 modeling results. All other cases were modeled. 

 (4) "f" refers to filterable and "c" refers to condensable particulate. 

 

deciview impacts from the plant for each control alternative. These are provided relative to the 

base case and also incrementally relative to the immediately preceding control alternative in 

terms of the level of emissions reduction attained. The net changes presented are the maximum 

changes of the 98th percentile impacts at any of the Class I areas. 
5-1 

5.0 SUMMARY AND CONCLUSIONS 

The Best Available Retrofit Technology (BART) program was established under the 

federal Regional Haze Rule to evaluate possible retrofit emissions control technology for 

visibility impairing pollutants emitted from certain combustion units constructed between 1962 

and 1977 that could potentially cause or contribute to a degradation of visibility at Prevention of 

Significant Deterioration (PSD) mandatory Class I Areas. 

Corette was determined to be BART-eligible under the Federal Regional Haze Rule by 

EPA Region 8. Region 8 further found that the Corette boiler is subject to possible particulate 

matter, SO2, and NOx retrofit controls for BART analysis. 

EPA’s BART Guideline approach has been applied to Corette to identify the “best system 

of continuous emission reduction” applicable to the plant for filterable particulate control, SO2

reduction and the control of NOx. A range of demonstrated control alternatives for large 

tangentially-fired coal boilers was evaluated considering costs, energy and environmental 

impacts, remaining useful life of the units and modeled visibility improvements. Electrostatic 

precipitators (ESP), fabric filters (baghouses), mechanical collectors and wet scrubbers were 

considered for PM. Dry and wet scrubbing techniques were considered for SO2, and separated 

over-fire air, selective non-catalytic reduction and selective catalytic reduction were evaluated 

for NOx control. 

 The CALPUFF model was used to evaluate the visibility impacts of present emissions 

from the Corette boiler and the BART control alternatives. The model setup and input 

meteorological and emissions data were obtained from EPA/WRAP files. The modeling was 

based on those data files with a few modifications. The particulate emissions were revised based 

on PPL stack test data and a few adjustments were made to the modeling as described in 

Appendix B. Modeling was conducted to determine visibility impacts in the seven mandatory 

Class I areas within 300 km of Corette. The cost analyses and modeling were based on actual 

emissions. For the cost analyses typical emission rates representative of average 30-day 

emissions were used. For the modeling analyses maximum daily emissions during the modeling 

years (2001-2003) were used. 

A summary of the results of the cost evaluations is provided in Table 5-1, both relative to 

the present emissions and incrementally from one level of control to the next. A summary of the 

modeled visibility impacts of the present emissions and the control alternatives is provided in 

Table 5-2, both relative to the present emissions and incrementally. The indicated visibility 
5-2 

improvements in Table 5-2 are based on the differences between the maximum annual 98th

percentile daily predicted visibility impacts at each site for each level of control, regardless of the 

meteorological year modeled for each prediction. The highest of these differences among the 

seven Class I areas modeled is presented. 

 The highest modeled annual 98th percentile daily visibility impact of emissions from the 

Corette boiler at maximum actual load is predicted to occur in the UL Bend National Wildlife 

Refuge (NWR) Class I area and is 0.645 deciviews. This is only slightly above the 0.5 deciview 

level that EPA has proposed as a level at which a source may contribute to a visibility impact but 

well below the 1.0 deciview level EPA employs as a level to indicate that a source causes a 

visibility impact. 

 From a visibility improvement basis with respect to filterable particulate matter, only a 

0.03 deciview improvement, which is not visually discernable, would result from installation of 

either ESPs or fabric filters. Consequently, implementation of additional particulate control at 

Corette is not warranted. 

 With respect to sulfur dioxide only a 0.08 deciview reduction is achieved with 

lime/limestone addition to either the boiler or fuel. The incremental improvements by reducing 

emissions to a 0.15 lb/MMBtu emission rate through either dry injection or wet scrubbing are 

0.15 deciviews or less. Such improvements are not discernable to the human eye and 

implementation of these control technologies are, therefore, not warranted. 

 Finally, with respect to nitrogen oxides only a 0.04 deciview improvement results from 

implementation of SOFA, which is not discernable, and the incremental improvements of further 

controls are 0.06 deciviews or less. 

 As a result of the studies and analysis, we are proposing that the existing permit limits for 

particulate, SO2 and NOx are BART. 
5-3 

Table 5-1: Summary of Cost Evaluation Results Based on Emissions 

CONTROL EQUIPMENT COST SUMMARY FOR THE PPL MONTANA, LLC, J.E. CORETTE POWER PLANT 

Particulate Matter Sulfur Dioxide Nitrogen Oxides

Evaluated

Rate Units

Evaluated

Rate Units

Evaluated

Rate Units

Current

Emission rate 0.082 lb/MMBtu 0.46 lb/MMBtu 0.26 lb/MMBtu (CEMS)

(2001 to 2005 average)

BDT(1) from

2006 NSPS for 0.015 lb/MMBtu 1.4 lbs SO2/MW out 1.0 lb/MW out

New Sources (0.15 lb/MM Btu in) (0.11 lb/MM Btu in)

Cost Effeciveness Calcs Cost Effeciveness Calcs

Option Evaluated $/ton Option Evaluated CE Inc CE Option Evaluated $/ton(5) Inc CE

Rate Rate Rate

lb/MMBtu lb/MMBtu $/ton $/ton lb/MMBtu $/ton

Control New ESP(2) 0.015 $21,149 Present 0.46 $0 Present(4) 0.26 $0

Options Added FF 0.015 $16,339 DGS(2) 0.35 $8,138 Tuning 0.23 $147

DGS(2) 0.15 $37,429 $53,538 SOFA 0.18 $914 $1,375

WS-FGD(3) 0.15 $25,480 $35,017 SNCR 0.16 $1,723 $4,966

SCR 0.15 $4,354 $30,518

Notes 1) BDT = "Best Demonstrated Technology" - From FR Vol. 71, No. 38, Monday, February 27,2007

 Final Rule (NSPS for EUSGUs) - the 2006 revised standards were revised to a gross megawatt

 output basis (equivalent in lb/MMBtu input values listed in paren)

2) Adding lime or limestone injection makes flyash unsalable - Includes added waste disposal cost

 (two options of 23% and 67% control may be possible - precip upgrade required for 67%)

 The CE for the ESP is the cost of a new technology ESP to reduce PM from 0.082 to 0.015 lb/MMBtu

3) If a wet scrubber is added, the low sulfur PRB coal could be replaced with 

 higher sulfur coal. (30 MW penalty for plume reheating) Includes lost revenue from ash sales.

4) It is assumed that boiler tuning and proper operation can improve the current 0.26 lb/MMBtu to 0.23 lb/MMBtu at minimal cost

5) Each technique applied individually; incremental cost effectiveness is that from previous option cost

Table 5-2: Modeled Visibility and Visibility Improvements 

Modeled Modeled Modeled

Rate (1) Prediction (3) from Rate Prediction from Rate Prediction from

Option (lb/MMBtu) (deciviews) Present Inc (6) Option (lb/MMBtu) (deciviews) Present Inc (6) Option (lb/MMBtu)(deciviews) Present Inc (6)

Present 0.082 0.645 n/a n/a Present 0.6 0.645 n/a n/a Present 0.31 0.645 n/a n/a

New ESP 0.015 0.633 0.032(5) 0.032(5) DGS(2) 0.46 0.568 0.077 0.077 Tuning(4) 0.27 0.616 0.043 0.043

Added FF 0.015 0.633 0.032(5) 0.032(5) EDGS(2) 0.2 0.446 0.199 0.147 SOFA 0.21 0.573 0.098 0.055

WS-FGD 0.15 0.407 0.238 0.049 SNCR 0.17 0.544 0.125 0.055

SCR 0.15 0.53 0.138 0.054

Notes: (1) The modeled emission rate is the rate corresponding to the maximum daily emissions during the modeling years (2001-2003).

 (2) See corresponding footnote in Table ES-1

 (3) Prediction is from all three pollutants at present emissions except the one being controlled

 (4) See corresponding footnote in Table ES-1.

 (5) The maximum improvement occurs at a different Class I area than the maximum prediction.

 (6) Inc = Incremental improvement from the immediately preceeding control alternative in terms of level of emissions reduction attained.

Improvement Improvement Improvement

Filterable PM10 Sulfur Dioxide Nitrogen Oxides
6-1 

6.0 REFERENCES

AWMA, Air Pollution Engineering Manual, Air & Waste Management Association, Anthony J. 

Buonicore and Wayne T. Davis, eds., Van Nostrand Reinhold, 1992. 

EC/R, Stationary Source Control Techniques Document for Fine Particulate Matter, EPA 

Contract No. 68-D-98-026, Work Assignment No. 0-08, EC/R Incorporated, October 1998. 

EPA 2002, Air Pollution Control Cost Manual, U.S. EPA, Volume 2, Sixth Ed., EPA-452-02-

001, January 2002. 

EPA, 2003, Guidance for Estimating Natural Visibility Conditions Under the Regional Haze 

Rule, http://www.epa.gov/ttn/oarpg/t1/memoranda/rh_envcurhr_gd.pdf

EPA 2004, Supplemental Air Quality Modeling Technical Support Document (TSD) for the 

Clean Air Interstate Rule, http://www.epa.gov/cair/pdfs/saqmtsd.pdf

Federal Register, Vol. 64, No. 126, July 1, 1999, pgs 35713-35774. 

Federal Register, Vol. 70, No. 38, February 28, 2005, pgs 9706-9735. 

Federal Register, Vol. 70, No. 128, July 6, 2005, pgs 39104-39172. 

Federal Register, Vol. 71, No. 38, February 27, 2006, pgs 9866-9873. 

NPS, http://www2.nature.nps.gov/air/permits/ect/ectOilFiredBoiler.cfm

Scire, J, et al. 2000, A User’s Guide for the CALPUFF Dispersion Model, Earth Tech, Inc. 

January 2000. 
APPENDIX A: 

COST ANALYSIS TABLES 
A-1 

Table A4-4(a): PPL BART Cost Analysis 

Electrostatic Precipitator Particulate Control 
A-2 

Table A4-4(a): PPL BART Cost Analysis continued 
A-3 

Table A4-4(b): PPL BART Cost Analysis 

Pulse Jet Fabric Filter for Additional Particulate Control 
A-4 

Table A4-4(b): PPL BART Cost Analysis continued 
A-5 

Table A4-7: PPL BART Cost Analysis 

Dry Injection (with Low Sulfur Coal) Sulfur Dioxide Control (25% Reduction)
A-6 

Table A4-8: PPL BART Cost Analysis 

Dry Injection (with Low Sulfur Coal) Sulfur Dioxide Control (70% Reduction) 
A-7 

Table A4-9: PPL BART Cost Analysis 

Wet Scrubbing (with Low Sulfur Coal) Sulfur Dioxide Control 
A-8 

Table A4-11: PPL BART Cost Analysis 

Upgrade of Current LNB Technology 
A-9 

Table A4-12: PPL BART Cost Analysis 

SOFA Addition to LNB Technology 
A-10 

Table A4-13: SNCR Cost Analysis for Corette 
A-11 

Table A4-14: SCR Cost Analysis for Corette 
APPENDIX B: 

CALPUFF APPLICATION FOR BART 

ASSESSMENTS AT PPL CORETTE 
CALPUFF Application for BART Assessments 

at PPL Facility Corette in Montana for the 

North Absaroka, Yellowstone, Washakie, 

UL Bend, Teton, Gates of the Mountains and 

Red Rock Lakes Class I Areas 

Prepared For: 

PPL Montana, LLC 

Billings, Montana 

Submitted By: 

TRC Environmental Corporation 

650 Suffolk Street, Wannalancit Mills 

Lowell, Massachusetts 01854 

(978) 970-5600 

August 2007 
i

TABLE OF CONTENTS 

Page

1.0 INTRODUCTION .............................................................................................................. 1

2.0 SOURCE DESCRIPTION.................................................................................................. 3

3.0 GEOPHYSICAL AND METEOROLOGICAL DATA ..................................................... 7

3.1 Terrain..................................................................................................................... 7 

3.2 Land Use ................................................................................................................. 9 

3.3 Meteorological Data Base....................................................................................... 9 

3.4 Air Quality Monitoring Data ................................................................................ 14 

4.0 AIR QUALITY MODELING METHODOLOGY .......................................................... 17

4.1 Model Selection .................................................................................................... 17 

4.2 Modeling Domain Configuration.......................................................................... 17 

4.3 Meteorological Modeling Options........................................................................ 17 

4.4 CALPUFF Computational Domain and Receptors............................................... 18 

4.5 Dispersion Modeling Options............................................................................... 18 

4.6 Visibility Calculations .......................................................................................... 20 

5.0 RESULTS ......................................................................................................................... 23

6.0 REFERENCES ................................................................................................................. 27
ii

LIST OF FIGURES 

Page

Figure 2-1. Aerial photo of the PPL Corette facility 4 

Figure 3-1. Terrain contours (m MSL) at 2 km resolution for the 782 km by 572 km 

CALMET and CALPUFF computational domains. The Class I areas and 

the Corette facility are also shown. 8 

Figure 3-2. Dominant land use categories at 2 km resolution on the CALMET and 

CALPUFF modeling domains. Class I areas and the location of Corette 

PPL are also shown. 10 

Figure 3-3. Surface stations. The stations included in the SURF.DAT files are plotted 

in purple. For reference in orange are shown the stations included in the 

original SURF.DAT files. As the figure shows better coverage of the 

domain is achieved by using the ISHWO data base. 13 

Figure 3-4. Locations of ozone monitoring stations used in the CALPUFF modeling. 15 

Figure 4-1. Locations of receptors at North Absaroka, Yellowstone, Washakie, Teton, 

Red Rock Lakes, Gates of the Mountains and UL Bend Class I areas. 19 
iii

LIST OF TABLES 

Page

Table 2-1. Corette: Source Parameters and Emission Rates – Base Case 5 

Table 2-2. Corette: Particle Speciation – Base Case 2-2 

Table 2-3. Corette: Emissions for Base Case and Control Alternatives 6 

Table 3-3. Meteorological Data Sources and Parameters Available 11 

Table 3-4. NWS Hourly Surface Stations 12 

Table 3-5. Ozone Stations 16 

Table 4-1. Summary of Background Natural Visibility Conditions 22 

Table 4-2. Monthly f(RH) values based on the Representative IMPROVE Site 

Location, for Visibility Method 6 applications 22 

Table 5-1. Summary of Visibility Results for Base Case 24 

Table 5-2. Summary of Visibility Results for Alternative 1 (SO2 Reduced 25% by 

Limestone Injection) 24 

Table 5-3. Summary of Visibility Results for Alternative 2 (SO2 Reduced 70% with a 

Dry Scrubber) 24 

Table 5-4. Summary of Visibility Results for Alternative 3 (SO2 Reduced to 0.15 

lb/MMBtu with a Wet Scrubber) 25 

Table 5-5. Summary of Visibility Results for Alternative 4 (NOx Reduced through 

Boiler Tuning) 25 

Table 5-6. Summary of Visibility Results for Alternative 5 (NOx Reduced with 

SOFA) 25 

Table 5-7. Summary of Visibility Results for Alternative 6 (NOx Reduced to 

0.15 lb/MMBtu with SCR) 26 

Table 5-8. Summary of Visibility Results for Alternative 7 (Filterable PM Reduced to 

0.015 lb/MMBtu) 26 
1 Introduction

1.0 INTRODUCTION

TRC Environmental Corporation has conducted a Best Available Retrofit Technology (BART) 

analysis for the coal-fired boiler at PPL Montana's Corette power plant. This analysis followed 

the “Draft CALPUFF BART Modeling Protocol For Federal Mandatory Class I Areas” prepared 

by the Montana Department of Environmental Quality (MDEQ), dated September 2006, called 

‘Montana Protocol’ hereafter. A few deviations from the Montana Protocol were made in the 

analysis and detailed in this report. The Montana Protocol, as well as the CALPUFF and 

CALMET model setup and input meteorological and emissions data described in the Montana 

Protocol were obtained from the WRAP website (http://pah.cert.ucr.edu/aqm/308/bart.shtml) 

provided by EPA Region 8 in a February 28, 2007 letter to PPL identifying the Corette unit as 

subject to BART and providing preliminary modeling results. The Corette PPL plant is located 

along the Yellowstone River on the outskirts of Billings, Montana. 

On July 6, 2005 the US Environment Protection Agency amended the Federal Register document, 

40 CFR Part 51 in order to introduce new National Regional Haze Regulations for Best Available 

Retrofit Technology. The regional haze rule requires States to submit implementation plans 

(SIPs) to address regional haze visibility impairment in 156 Federally-protected parks and 

Wilderness Areas (WA), commonly referred to as “Class I Areas”. The final rule included a 

requirement for BART for certain large stationary sources that were put in place between 1962 

and 1977. The regional haze rule uses the term “BART-eligible source” to describe those sources 

which have the potential to emit 250 tons or more of a visibility-impairing air pollutant, were put 

in place between August 7, 1962 and August 7, 1977 and whose operations fall within one or 

more of 26 specifically listed source categories, of which fossil-fuel fired steam electric plants of 

more than 250 million British thermal units (BTU) per hour heat input is one. 

BART review is required when the source emits any air pollutant which may reasonably be 

anticipated to cause or contribute to any impairment of visibility in any Class I area. In 

identifying a level of control of BART, States are required by section 169A(g) of the CAA to 

consider; (a) the costs of compliance, (b) the energy and non-air quality environmental impacts of 

compliance, (c) any existing pollution control technology in use at the source, (d) the remaining 

useful life of the source and (e) the degree of visibility improvement which may reasonably be 

anticipated from the use of BART. 

The purpose of the modeling was to assess the visibility impacts of sulfur dioxide (SO2), nitrogen 

oxides (NOx) and primary particulate matter (PM) emissions (including primary sulfuric acid, 

H2SO4, emissions), at those Class I areas that are located within 300 km from the plant. A total of 

seven Class I areas are located within this radius: North Absaroka WA, Yellowstone National Park 

(NP), Washakie WA, UL Bend WA, Teton WA, Gates of the Mountains WA and Red Rock 

Lakes WA. 
2 Introduction

The topography of the modeling domain includes areas of complex terrain. There is the potential 

for terrain effects, both on the meteorological fields and in terms of plume-terrain interaction 

effects. The CALMET and CALPUFF non-steady-state models (Scire et al., 2000a,b) were used 

for the modeling analysis. The U.S. Environmental Protection Agency (EPA) has recommended 

CALPUFF as the preferred model for BART analyses (U.S. EPA, 2005). The CALPUFF 

modeling system is the regulatory Guideline Model for Class I impact assessments and other long 

range transport applications and on a case-by-case basis for near-field applications involving 

complex flows (U.S. EPA, 2003a). CALPUFF is also recommended by both the Federal Land 

Managers Air Quality Workgroup (FLAG, 2000) and the Interagency Workgroup on Air Quality 

Modeling (U.S. EPA, 1998). 

CALMET is a diagnostic meteorological model that produces three-dimensional wind fields 

based on parameterized treatments of terrain effects such as slope flows, terrain blocking effects, 

and kinematic effects. Meteorological observations were used to determine the wind field in areas 

where the observations are representative. The hourly meteorological datasets developed from the 

fifth generation Penn State/NCAR (National Center For Atmospheric Research, Boulder, CO) 

three-dimensional mesoscale weather prediction model MM5 for 2001-2003 were used to help 

define the initial estimate of the wind fields. The horizontal resolution of data is 36 km for all 

three years. 

CALPUFF is a non-steady-state puff dispersion model. It accounts for spatial changes in the 

CALMET-produced meteorological fields, variability in surface conditions (elevation, surface 

roughness, vegetation type, etc.), chemical transformation, wet removal due to rain and snow, dry 

deposition, and terrain influences on plume interaction with the surface. CALPUFF contains a 

module to compute visibility effects, based on a humidity-dependent relationship between 

particulate matter concentrations and light extinction, as well as wet and dry acid deposition 

fluxes. The refined meteorological and dispersion modeling simulations have been conducted for 

a three-year period (2001-2003). Visibility impacts have been predicted by the model at receptors 

in the Class I areas. 

In the Montana Protocol, Table 3.0 lists the versions of the CALMET, CALPUFF, POSTUTIL 

and CALPOST codes to be used in the modeling. The Protocol also states that “if new and 

improved versions become available, the MDEQ will apply those versions and document the 

changes”. In June 2007, EPA has approved the new version of CALPUFF modeling system, 

Version 5.8. This new, EPA-approved version was used in the modeling. 

This report outlines the techniques and data used in the BART analyses. Section 2 describes the 

study area and the source configuration. The site characteristics and the data bases 

(meteorological, geophysical, and aerometric) used in the analysis are provided in Section 3. 

Section 4 includes an overview of the CALMET and CALPUFF models, and the importance of 

evaluating non-steady-state effects. The results of the modeling analysis are described in 

Section 5. 
 3 Source Description

2.0 SOURCE DESCRIPTION

The Corette Power Plant is located near Billings, Montana. There is one coal-fired boiler at the 

plant that is a BART-eligible source. Figure 2-1 shows the aerial photo of the Corette plant. 

The emissions for the conditions during the modeling years (2001 – 2003) from each BARTeligible unit were based on the maximum daily emissions recorded over the three-year modeling 

period. 

PM10 emissions were split into filterable and condensable portions, with the condensable portion 

further split into organics and inorganics and the filterable portion split into fine particulate 

matter, elemental carbon and coarse particulate matter parts based on available stack test data and 

current guidance of the National Park Service. The particulate matter was modeled using the 

geometric mass mean diameter of 0.4 micrometers (μm) and geometric standard deviation of 

2 μm. 

Stack parameters for modeling were based on full load operation. Table 2-1 summarizes the stack 

parameters and emissions, while Table 2-2 summarizes the particulate speciation for the present 

emissions case. 

Table 2-3 summarizes the emissions and particulate speciation for the base case and seven control 

alternatives evaluated. Each control alternative is related to a single pollutant emission reduction. 
 4 Source Description

Figure 2-1. Aerial photo of the PPL Corette facility 
 5 

Table 2-1...........................................Corette: Source Parameters and Emission Rates – Base Case 

Lambert Conformal 

Coordinates1 Stack 

ID # LCC East LCC North 

Stack 

Height 

Base 

Elevation Diameter Gas Exit Velocity Stack Gas Exit Temp. SO2 Emissions 

H2SO4

Emissions2

NO

Emiss

 km km m m m m/s K lb/hr lb/hr lb/h

Unit 1 678.999 170.084 106.7 947.3 3.51 36.58 389.0 1135.0 21.74 604

1 The LCC projection is based on standard parallels of 45.0 N and 49.0 N, an origin latitude and longitude of 44.25 N and 109.5 W, false easting is 600 k2 H2SO4 emissions are entered in CALPUFF as SO4 i.e., weighted by ratio of molecular weights (96/98). 4 PM10 emission rate includes filterable and condensable emissions. The condensable component includes H2SO4 emissions. Table 2-2........................................................................... Corette: Particle Speciation – Base Case 

Stack ID # Particle speciation Condensable Filterable

Organic 

condensable (OC) 

H2SO4 Coarse Soil 

Filterable PM10 Condensable PM10

M1=0.48, SD1=2.0 μm

M1=0.48, SD1=2

% % lb/hr lb/hr lb/hr lb/hr 

Unit 1 85.4 14.6 5.44 21.74 88.43 68.12 

1 M and SD stand for Geometric Mass Mean Diameter and Geometric Standard Deviation. These are the parameters used to calculate the particle size dis
 6 

Table 2-3..............................................Corette: Emissions for Base Case and Control Alternatives 

Stack 

ID # Condensable Filterable

SO2

Emissions 

NOx

Emissions 

PM10

Emissions3

Organic 

condensable 

(OC) 

H2SO4 Coarse Soil

Elemental 

Carbon 

(EC)

lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr 

Unit 1 Base Case 1135.0 604.0 186.35 5.44 21.74 88.43 68.12 2.62 

 Control Alt. 1 892.9 604.0 186.35 5.44 21.74 88.43 68.12 2.62  Control Alt. 2 388.2 604.0 186.35 5.44 21.74 88.43 68.12 2.62  Control Alt. 3 291.2 604.0 186.35 5.44 21.74 88.43 68.12 2.62  Control Alt. 4 1135.0 524.1 186.35 5.44 21.74 88.43 68.12 2.62  Control Alt. 5 1135.0 407.6 186.35 5.44 21.74 88.43 68.12 2.62  Control Alt. 6 1135.0 291.2 186.35 5.44 21.74 88.43 68.12 2.62  Control Alt. 7 1135.0 604.0 56.29 5.44 21.74 16.17 12.46 0.48 

 NOTES: Control Alt 1 = SO2 reduced 25% by limestone injection. 

 Control Alt 2 = SO2 reduced 70% with a dry scrubber.  Control Alt 3 = SO2 reduced to 0.15 lb/MMBtu with a wet scrubber.  Control Alt 4 = NOx reduced through boiler tuning.  Control Alt 5 = NOx reduced with SOFA.  Control Alt 6 = NOx reduced to 0.15 lb/MMBtu with SCR.  Control Alt 7 = Filterable PM reduced to 0.015 lb/MMBtu. 
 7 Geophysical and Meteorological Data 

3.0 GEOPHYSICAL AND METEOROLOGICAL DATA

3.1 Terrain

Gridded terrain elevations for the modeling domain are derived from 3 arc-second digital elevation 

models (DEMs) produced by the United States Geological Survey (USGS). Data are provided in files 

covering 1 degree by 1 degree blocks of latitude and longitude. The 1-degree DEMs are produced by the 

Defense Mapping Agency using cartographic and photographic sources. USGS 1:250,000 scale 

topographic maps are the primary source of 1-degree DEMs. 

One degree DEM data consists of an array of 1201 by 1201 elevations referenced on the geographic 

(latitude/longitude) coordinate system of the World Geodetic System 1972 Datum. Elevations are in 

meters relative to mean sea level, and the spacing of the elevations along each profile is 3 arc-seconds, 

which corresponds to a spacing of approximately 90 meters. 

The CALMET computational domain was designed to cover an area of 782 km by 572 km (Figure 3-1). 

It includes Corette and all Class I areas within 300 km from it. These Class I areas are: Gates of the 

Mountains WA, North Absaroka WA, Red Rock Lakes WA, Teton WA, UL Bend WA, Washakie WA 

and Yellowstone NP. The domain also includes the other PPL Bart-eligible facility in Montana 

(Colstrip) and the Class I areas within 300 km of it. The domain includes an adequate buffer of more 

than 50 km in all directions from each of the two facilities and each of the Class I areas. A horizontal 

resolution of 2 km was used to capture the variations of the terrain elevations in the area. This modeling 

domain is different from the domain proposed in the Montana Protocol for several reasons. In the 

Montana Protocol, a single, large domain was designed to cover the entire state of Montana and parts of 

five neighboring states, since that modeling domain was intended to be used for 10 BART eligible 

Montana sources and all Class I areas within 300 km from those 10 facilities. Since the size of such 

domain was very large, proposed horizontal resolution in the Montana Protocol was 6 km. In the current 

analysis, the modeling domain was redesigned to include only two PPL facilities, Colstrip and Corette, 

and Class I areas within 300 km from these two facilities only. This resulted in a modeling domain 

much smaller in size than originally proposed. Hence, better horizontal resolution of 2 km was possible 

to achieve while still using the reasonable number of grid cells. In addition, the domain was extended to 

the south to include the complete set of receptors in Yellowstone, Washakie and Teton Class I areas. 

Figure 3-1 shows contours of the terrain averaged to 2 km. The USGS elevation records located within 

each grid cell in the computational domain were averaged to produce a mean elevation at each grid 

point. Adequate representation of the important terrain features and valleys associated with the Class I 

areas and the surrounding area are captured by the 391 x 286 grid cells, a workable number of cells. The 

CALPUFF computational domain is the same as the CALMET domain. The domain extends beyond the 

Class I areas in order to provide an adequate buffer zone at the boundaries, and to allow the effects of 

flow curvature and possible small-scale recirculation to be evaluated. Figure 3-1 shows the location of 
 8 Geophysical and Meteorological Data 

Figure 3-1. Terrain contours (m MSL) at 2 km resolution for the 782 km by 572 km CALMET and 

CALPUFF computational domains. The Class I areas and the Corette facility are also shown. 

350 400 450 500 550 600 650 700 750 800 850 900 950 1000 1050 1100

LCCx (km), WGS-84

-100

-50

0

50

100

150

200

250

300

350

400

450

LCCy (km), WGS-84

Yellowstone

Washakie

UL Bend

Theodore Roosevelt - N

Theodore Roosevelt - C

Theodore Roosevelt - S

Teton

Red Rock Lakes North Absaroka

Gates of the Mountains

Corette

Map projection: LCC, WGS-84

Feast = 600 km, Fnorth = 0 km

LATo = 44.25N, LANo = 109.5W

LAT1 = 45 N, LAT2 = 49 N

ID

MT

ND

SD

WY

PPL, Montana

Terrain

(meters)

-1

100

300

500

700

900

1100

1300

1500

1700

1900

2100

2300

2500

2700

2900

3100

3300

3500

3700

3900

4500

300 km circle around facility
 9 Geophysical and Meteorological Data 

Corette and a 300-km radius circle around the facility. North Absaroka, Yellowstone, Washakie, UL 

Bend, Teton, Gates of the Mountains and Red Rock Lakes Class I areas are within 300 km from Corette. 

These seven Class I areas were included in the BART visibility analysis for the Corette facility. 

3.2 Land Use

The USGS Land Use data within the CALMET/CALPUFF computational domain have been used to 

produce a gridded field of dominant Land Use categories. The Land Use data for the analysis were 

obtained in Composite Theme Grid (CTG) format from the USGS, with a resolution of 200 m. 

Land use data were processed to produce a 2 km resolution gridded field of fractional land use 

categories. The 37 USGS Land Use categories were then mapped into 14 CALMET land use categories. 

Surface properties such as albedo, Bowen ratio, roughness length, and leaf area index were computed 

proportionally to the fractional land use. The 14 CALMET land use categories are described in the 

Montana Protocol. Figure 3-2 shows the dominant land use categories used in the modeling. 

3.3 Meteorological Data Base 

The CALMET model requires meteorological information from the surface and upper air as well as 

geophysical information about the land use and terrain heights. Specifically, CALMET requires surface 

observations of wind speed, wind direction, temperature, cloud cover, ceiling height, surface pressure, 

relative humidity, and precipitation type (e.g., snow, rain, etc.). These variables are routinely measured 

at the National Weather Service (NWS) surface stations. The upper air data include twice-daily 

observations of vertical profiles of wind speed, wind direction, temperature, and pressure. 

The CALMET was run using NOOBS=1, which means that upper air were taken from MM5 and not 

from observations. Also, precipitation and relative humidity were also derived from the MM5 data. 

Table 3-3 lists the types of observational and modeled data available that are used in the modeling. A 

total of 60 surface meteorological stations for each year were used in the refined runs (Table 3-4). And 

three-dimensional gridded data from the prognostic numerical model MM5 provided by WRAP were 

also included with a resolution of 36-km for 2001 through 2003. Hourly precipitation data, which are 

required for wet deposition calculations in CALPUFF, were derived from the MM5 data. 

SURF.DAT has been recreated using Integrated Surface Hourly Weather Observations (ISHWO) data 

base. Eight stations in 2001 and five from 2002 and 2003 from the original SURF.DAT file were not 

found in any of ISHWO or METAR databases. The records from theses stations were extracted from the 

original SURF.DAT files and added to the new ones (first eight stations listed in Table 3-4). 
 10 Geophysical and Meteorological Data 

Figure 3-2. Dominant land use categories at 2 km resolution on the CALMET and CALPUFF 

modeling domains. Class I areas and the location of Corette PPL are also shown. 

350 400 450 500 550 600 650 700 750 800 850 900 950 1000 1050 1100

LCCx (km), WGS-84

-100

-50

0

50

100

150

200

250

300

350

400

450

LCCy (km), WGS-84

Yellowstone

Washakie

UL Bend

Theodore Roosevelt - N

Theodore Roosevelt - C

Theodore Roosevelt - S

Teton

Red Rock Lakes North Absaroka

Gates of the Mountains

Corette

Map projection: LCC, WGS-84

Feast = 600 km, Fnorth = 0 km

LATo = 44.25N, LANo = 109.5W

LAT1 = 45 N, LAT2 = 49 N

ID

MT

ND

SD

WY

PPL, Montana

300 km circle around facility

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

Snow/Ice

Tundra

Barren

Wetland

Water

Forest

Range

Agriculture

Urban/Built-Up
 11 Geophysical and Meteorological Data 

Table 3-3...................................................Meteorological Data Sources and Parameters Available 

Type of Dataset Frequency Source Parameters 

Surface observations Hourly NWS Wind speed, wind 

direction, temperature, 

ceiling height, cloud 

cover, relative humidity, 

surface pressure, 

precipitation type 

Modeled Profiles 

MM5 for 2001, 2002 

and 2003 

Hourly WRAP Hourly, gridded fields of 

winds, temperature, 

pressure, and humidity and 

liquid water content on 

36 km grid for 2003, 2004 

and 2005. 
 12 Geophysical and Meteorological Data 

Table 3-4........................................................................................... NWS Hourly Surface Stations

WMO WBAN Station Name State Latitude 

(deg.) 

Longitude 

(deg.) 

CALL ID LCC X1

(km) 

LCC Y1

(km) 

 Colstrip region MT 46.90 -103.40 TH28 824.377 178.618 

 Border of WY & MT close to KSHR MT 45.10 -106.90 SP26 805.708 99.912 

 Colstrip region MT 45.80 -106.60 PE25 269.113 482.966 

 Border of ID & MT close to KSMN ID 45.10 -113.50 SA32 1064.318 312.121 

 Glacier WA area MT 48.50 -114.00 GL27 283.839 99.808 

 Colstrip region 2

 MT 45.70 -106.50 MO39 828.340 159.976 

 Colstrip region 2

 MT 45.60 -106.50 GA38 836.341 154.721 

 Colstrip region 2

 MT 45.70 -106.60 BA37 831.370 162.314 

718620 99999 ESTEVAN AIRPORT SA 49.22 -102.97 CYEN 1075.221 572.157 

725686 99999 DOUGLAS WY 42.80 -105.38 KDGW 937.563 -152.417 

725690 24089 CASPER NATRONA CO INTL A WY 42.90 -106.47 KCPR 847.878 -145.371 

725760 24021 LANDER HUNT FIELD WY 42.82 -108.73 KLND 663.094 -158.761 

725765 99999 RIVERTON MUNICIPL AP WY 43.05 -108.45 KRIW 685.694 -132.898 

725776 99999 JACKSON HOLE (AWOS) WY 43.60 -110.73 KJAC 500.578 -71.501 

725780 24156 POCATELLO REGIONAL AP ID 42.92 -112.57 KPIH 348.939 -143.020 

725785 24145 IDAHO FALLS FANNING FIEL ID 43.52 -112.07 KIDA 392.002 -77.767 

725865 99999 HAILEY/FRIEDMAN MEM ID 43.50 -114.30 KSUN 211.558 -71.499 

725867 24133 BURLEY MUNICIPAL ARPT ID 42.53 -113.77 KBYI 248.522 -181.773 

726514 99999 CUSTER (RAMOS) SD 43.73 -103.62 KCUT 1073.773 -40.031 

726516 99999 PHILIP ARPT SD 44.05 -101.60 KPHP 1232.468 9.686 

726517 99999 PINE RIDGE SD 43.03 -102.52 KIEN 1169.119 -110.323 

726539 99999 FAITH SD 45.03 -102.02 KD07 1188.561 114.823 

726620 24090 RAPID CITY REGIONAL ARPT SD 44.05 -103.05 KRAP 1116.674 -0.951 

726625 99999 ELLSWORTH AFB SD 44.15 -103.10 KRCA 1111.770 9.802 

726627 99999 BUFFALO (AMOS) SD 45.57 -103.52 K2WX 1066.215 164.509 

726650 99999 GILLETTE (AMOS) WY 44.35 -105.53 KGCC 916.548 19.141 

726654 99999 JOHNSON CO ARPT WY 44.38 -106.72 KBYG 821.593 18.385 

726660 24029 SHERIDAN COUNTY ARPT WY 44.77 -106.97 KSHR 800.273 61.038 

726664 94173 YWLLOESTONE LAKE RAMOS WY 44.55 -110.42 P60 526.875 33.779 

726665 24062 WORLAND MUNICIPAL WY 43.97 -107.95 KWRL 724.471 -29.901 

726667 99999 SOUTH BIG HORN CO WY 44.52 -108.08 KGEY 712.923 31.039 

726676 99999 GLENDIVE(AWOS) MT 47.13 -104.80 KGDV 956.165 330.710 

726700 99999 CODY MUNI (AWOS) WY 44.52 -109.02 KCOD 638.174 30.132 

726710 99999 BIG PINEY (AMOS) WY 42.57 -110.10 KBPI 550.622 -186.713 

726770 24033 BILLINGS LOGAN INT'L ARP MT 45.80 -108.55 KBIL 673.824 172.705 

726776 24036 LEWISTOWN MUNICIPAL ARPT MT 47.05 -109.45 KLWT 603.797 311.134 

726777 99999 BAKER MUNI ARPT MT 46.33 -104.25 KBHK 1003.738 244.677 

726785 24135 BUTTE BERT MOONEY ARPT MT 45.95 -112.50 KBTM 367.559 193.375 

726796 99999 DILLON AIRPORT MT 45.25 -112.55 KDLN 360.659 115.807 

726797 24132 BOZEMAN GALLATIN FIELD MT 45.80 -111.15 KBZN 471.785 173.608 

726798 24150 LIVINGSTON MISSION FIELD MT 45.70 -110.45 KLVM 526.041 161.596 

726818 99999 REXBURG ID 43.83 -111.80 KRXE 414.859 -43.982 

726865 99999 SALMON/LEMHI (AWOS) ID 45.12 -113.88 KSMN 255.576 106.332 

727584 99999 HETTINGER ND 46.02 -102.65 KHEI 1129.513 219.869 

727645 24012 DICKINSON MUNICIPAL AP ND 46.80 -102.80 KDIK 1110.543 305.206 

727670 94014 WILLISTON SLOULIN INTL A ND 48.20 -103.65 KISN 1034.294 455.151 

727675 99999 MINOT AFB ND 48.42 -101.35 KMIB 1201.973 494.726 

727676 24013 MINOT FAA AP ND 48.27 -101.28 KMOT 1208.871 478.684 

727677 99999 GARRISON (AMOS) ND 47.65 -101.43 KN60 1204.887 408.989 

727680 94008 GLASGOW INTL ARPT MT 48.22 -106.62 KGGW 813.875 445.081 

727684 99999 JORDAN (RAMOS) MT 47.33 -106.93 KJDN 794.107 345.428 

727686 99999 WOLF POINT INTL MT 48.10 -105.58 KOLF 891.719 435.111 

727687 99999 SIDNEY-RICHLAND MT 47.70 -104.20 KSDY 997.286 396.803 

727720 24144 HELENA REGIONAL AIRPORT MT 46.60 -111.97 KHLN 410.886 264.119 

727730 24153 MISSOULA INTERNATIONAL A MT 46.92 -114.10 KMSO 250.034 306.969 

727750 24143 GREAT FALLS INTL ARPT MT 47.47 -111.38 KGTF 458.369 359.499 

727770 94012 HAVRE CITY-COUNTY AP MT 48.55 -109.77 KHVR 580.071 477.866 

727790 24146 KALISPELL GLACIER PK INT MT 48.32 -114.25 KFCA 248.065 462.938 

727796 24137 CUT BANK MUNI AP MT 48.60 -112.37 KCTB 388.414 487.267 

742300 24037 MILES CITY MUNICIPAL ARP MT 46.43 -105.88 KMLS 877.984 248.676 

 

1 The Lambert Conformal Conic (LCC) projection is based on standard parallels of 45.0 N and 49.0 N, an origin latitude and 

longitude of 44.25 N and 109.5 W, false easting is 600 km, and datum WGS-84. 

2 Available for year 2001 only 
 13 Geophysical and Meteorological Data 

Figure 3-3. Surface stations. The stations included in the SURF.DAT files are plotted in purple. For 

reference in orange are shown the stations included in the original SURF.DAT files. As the figure 

shows better coverage of the domain is achieved by using the ISHWO data base. 

150 200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 1000 1050 1100 1150 1200 1250

LCCx (km), WGS-84

-200

-150

-100

-50

0

50

100

150

200

250

300

350

400

450

500

550

600

LCCy (km), WGS-84

Yellowstone

Washakie

UL Bend

Theodore Roosevelt - N

Theodore Roosevelt - C

Theodore Roosevelt - S

Teton

Red Rock Lakes North Absaroka

Gates of the Mountains

KPIH

KIDA KSUN

KBYI

KSMN

KGDV

KBIL

KLWT

KBHK

KBTM

KDLN

KBZN KLVM

KGGW

KJDN

KOLF

KSDY

KHLN

KMSO

KGTF

KHVR

KFCA

KCTB

KMLS

KHEI

KDIK

KISN

KMIB

KMOT

KN60

CYEN

KCUT

KPHP

KIEN

KD07

KRAP

KRCA

KDGW KCPR

KLND

KRIW

KJAC

KBYG KGCC

KSHR

P60

KWRL

KCOD KGEY

TH28

SP26

PE25

SA32

GL27

MO39 GA38 BA37 K2WX

KBPI

KRXE

MIN2

LAN3

SHE4

BIL5

LEW6

MIL7

CAS8

RAP9

GR11

HE12

KA13

MI14

PO15

GL17 WI18

BO19

BU20

CU21

DI22

HA23

LI24

PE25

SP26

GL27

TH28

YE29

RE31

SA32

DI33

RI34

ES35

BA37 GA38 MO39

Colstrip

Corette

Map projection: LCC, WGS-84

Feast = 600 km, Fnorth = 0 km

LATo = 44.25N, LANo = 109.5W

LAT1 = 45 N, LAT2 = 49 N

MM5 grid points 

Surface met stations

Facility

BC

AL SA

ID

MT

ND

SD

WY

PPL, Montana

MODELING DOMAIN

300 km circles around facility
 14 Geophysical and Meteorological Data 

3.4 Air Quality Monitoring Data

CALPUFF uses hourly ozone concentration measurements in the chemical transformation calculations 

(SO2 to SO4, NOx to HNO3/NO3). The ambient ozone measurements were used in determining SO2 loss 

rates due to chemical transformation to sulfate and in determining NOx loss rates to nitrate. Ambient 

ozone monitoring data from the EPA AIRS and CASTNET networks were used to develop the hourly 

ozone monitoring data file (OZONE.DAT). The original OZONE.DAT files from the WRAP web site 

were not used her since they contained many stations that were very far from the modeling domain and 

in addition, a couple of these stations had wrong coordinates. The ozone stations used in the modeling 

are plotted in Figure 3-4. These stations and their locations are listed in Table 3-5. 

Monthly background ammonia concentrations were calculated from hourly ammonia data collected 

from 2001 to 2002 a site near Beulah, ND. The MDEQ believes this data is representative of Montana 

background ammonia concentrations and the EPA concurs. These ammonia background concentrations, 

shown in Table 4.3.2 of the Montana Protocol were used in the CALPUFF modeling. 
 15 Geophysical and Meteorological Data 

Figure 3-4. Locations of ozone monitoring stations used in the CALPUFF modeling. 

200 250 300 350 400 450 500 550 600 650 700 750 800 850 900 950 1000 1050 1100 1150 1200 1250

LCCx (km), WGS-84

-200

-150

-100

-50

0

50

100

150

200

250

300

350

400

450

500

550

LCCy (km), WGS-84

160230101

300298001

380070002

380130004

380250003

380530002

380570004

380650002

460711001

461030016

560050123

560391011

GLR468

THR422

WNC429

PND165

YEL408

Colstrip

Corette

Map projection: LCC, WGS-84

Feast = 600 km, Fnorth = 0 km

LATo = 44.25N, LANo = 109.5W

LAT1 = 45 N, LAT2 = 49 N

CASTNET

AIRS

ID

MT

ND

SD

WY

PPL, Montana

MODELING DOMAIN
 16 Geophysical and Meteorological Data 

Table 3-5................................................................................................................... Ozone Stations 

Station ID Latitude (deg.) Longitude (deg.) Land use Setting Site name 

160230101 43.46 113.56 Blighted Areas Rural 

300298001 48.51 114.00 Agricultural Rural Glacier National Park 

380070002 46.89 103.37 Agricultural Rural Painted Canyon 

380130004 48.64 102.40 Agricultural Rural Lostwood Nwr 

380250003 47.32 102.53 Agricultural Rural Dunn Center 

380530002 47.60 103.26 Agricultural Rural Trnp-Nu 

380570004 47.30 101.77 Agricultural Rural Beulah North 

380650002 47.19 101.43 Agricultural Rural Hannover 

460711001 43.75 101.94 Agricultural Rural 

461030016 44.06 103.21 Residential Urban Near Robinsdale School 

560050123 44.67 105.29 Desert Rural 

560391011 44.57 110.40 Forest Rural Near the Water Tower of Hwy98 

560358001 42.93 109.79 Forest Rural Freemont Lake South, WV 
17 Air Quality Modeling Methodology 

4.0 AIR QUALITY MODELING METHODOLOGY

4.1 Model Selection

The CALPUFF modeling system (Scire et al., 2000a,b) was used in the Corette BART analysis at North 

Absaroka, Yellowstone, Washakie, UL Bend, Teton, Gates of the Mountains and Red Rock Lakes 

Class I areas. The EPA-approved version of CALPUFF modeling system, Version 5.8 was used in the 

modeling.

4.2 Modeling Domain Configuration

CALMET and CALPUFF use terrain-following coordinates. The modeling domain consists of 391x286 

grid cells, uniform in the horizontal with a spatial resolution of 2 km. This domain covers the Corette 

PPL facility in Montana and eight Class I areas in its vicinity, along with the appropriate buffer zones. 

In the vertical, a stretched grid was used with finer resolution in the lower layers and somewhat coarser 

resolution aloft thus allowing adequate representation of the mixed layer. The ten vertical levels are 

centered at: 10, 30, 60, 120, 230, 450, 800, 1250, 1850 and 2600 meters. 

4.3 Meteorological Modeling Options 

In CALMET, the regulatory option was used (MREG=1), indicating the selection of the mixing height 

method (IMIXH=-1 using the Maul-Carson method over land and the OCD method over water; 

ICOARE=0 using the OCD method for turbulence and fluxes over water; and THRESHL=0.0 using a 

value of zero for the threshold sensible heat flux over land). 

Initial Guess Field 

The MM5 gridded meteorological data were used to define the initial guess field for the CALMET 

simulations. MM5 data were available for years 2001-2003 with a horizontal grid spacing of 36 km and 

34 vertical levels. 

Step 1 Field: Terrain Effects 

In developing the Step 1 wind field, CALMET adjusts the initial guess field to reflect kinematic effects 

of the terrain, slope flows and blocking effects. Slope flows are a function of the local slope and altitude 

of the nearest crest. The crest is defined as the highest peak within a radius TERRAD around each grid 

point. For the domain used to perform the modeling, a value of TERRAD of 15 km was used. This value 

has been recommended by MDEQ in the Montana Protocol and is considered appropriate for this 

modeling domain. The Step 1 field produces a flow field consistent with the fine-scale CALMET terrain 

resolution (2 km). 

Step 2 Field: Objective Analysis 

In Step 2, observations are incorporated into the Step 1 wind field to produce a final wind field. Each 

observation site influences the final wind field within a radius of influence (parameters RMAX1 at the 
18 Air Quality Modeling Methodology 

surface and RMAX2 aloft). Observations and Step 1 field are weighted by means of parameters R1 at 

the surface and R2 aloft: at a distance R1 from an observation site, the Step 1 wind field and the surface 

observations are weighted equally. As recommended in the Montana Protocol, RMAX1 and RMAX2 

were set to 40 km and 100 km, while R1 and R2 were set to 20 km and 50 km, respectively. 

4.4 CALPUFF Computational Domain and Receptors

The CALPUFF computational domain is the same as the CALMET computational domain. The 

modeling domain includes a buffer zone of at least 50 km from the source and beyond the borders of the 

Class I areas. This minimizes the edge effects and allow pollutants involved in flow reversals to be 

brought back into the Class I areas. CALPUFF was run for three years, 2001, 2002 and 2003. 

The receptor locations along with receptor elevations were available from the National Park Service 

(NPS). The distribution of the receptors within North Absaroka, Yellowstone, Washakie, UL Bend, 

Teton, Gates of the Mountains and Red Rock Lakes are shown in Figure 4-1. In the screening modeling, 

the domain did not include the southernmost part of the Yellowstone NP, Teton WA and Washakie WA. 

In this refined run, the complete set of receptors for these Class I areas was included. 

4.5 Dispersion Modeling Options

The CALPUFF simulations were conducted using the following model options: 

 - Gaussian near-field distribution 

 - Transitional plume rise 

 - No building downwash 

 - Pasquill-Gifford (PG) dispersion coefficients (rural areas) and 

McElroy-Pooler coefficients (urban areas) 

 - Transition of σy to time-dependent (Heffter) growth rates 

 - Partial plume path adjustment for terrain 

 - Wet deposition, dry deposition, and chemical transformation using the 

MESOPUFF II scheme. 

 - Regulatory option used 

Two important computational parameters in CALPUFF are XMXLEN (maximum length of an emitted 

puff, in grid units) and XSAMLEN (maximum travel distance of a puff, in grid units, during one time 

step). Both of these variables were set to 1.0 in the CALPUFF simulations in order to allow the strong 

wind channeling effects to be accounted for in the puff trajectory calculations. The first parameter 

ensures that the length of an emitted puff does not become so large so that it cannot respond to changes 

in the wind field on the scale of the meteorological grid. The model automatically increases the 

frequency of puff releases to ensure the length of a single puff is not larger than the grid size. The 

second parameter decreases the internal time step to ensure the travel distance during one time step does 

not exceed the grid size. 
19 Air Quality Modeling Methodology 

Figure 4-1. Locations of receptors at North Absaroka, Yellowstone, Washakie, Teton, Red Rock 

Lakes, Gates of the Mountains and UL Bend Class I areas. 

410 415 420 425 430 435 440

LCCx (km), WGS-84

280

285

290

295

300

305

310

LCCy (km), WGS-84

Gates of the Mountains

705 710 715 720 725 730

LCCx (km), WGS-84

355

360

365

370

375

380

385

LCCy (km), WGS-84

UL Bend

400 420 440 460 480 500 520 540 560 580 600 620 640

LCCx (km), WGS-84

-60

-40

-20

0

20

40

60

80

100

LCCy (km), WGS-84

Yellowstone

Washakie

Teton

Red Rock Lakes

North Absaroka

Map projection: LCC, WGS-84

Feast = 600 km, Fnorth = 0 km

LATo = 44.25N, LANo = 109.5W

LAT1 = 45 N, LAT2 = 49 N
20 Air Quality Modeling Methodology 

The partial plume path adjustment option was used in CALPUFF for this analysis (MCTADJ=3). The 

CALMET wind field incorporates the effect of the terrain on the plume trajectories. The plume path 

coefficient is used to characterize the local effect on ground-level concentrations. The default plume 

path coefficients (PPC) used for this analysis are listed below: 

Stability Class A B C D E F 

PPC 0.5 0.5 0.5 0.5 0.35 0.35 

Deposition was modeled using the default dry deposition model and the scavenging coefficient wet 

removal module. Nine species were modeled with CALPUFF for this analysis: SO2, SO4, NOx, NO3, 

HNO3, and four subcategories of PM10, (PMF, PMC, EC, and SOA). Of these nine species, seven are 

emitted by the Corette sources: SO2, SO4, NOx and four subcategories of PM10. The chemical 

mechanism computes transformation rates of SO2 to SO4 and NOx to NO3/HNO3. Hourly measured 

ozone concentrations are provided in an external OZONE.DAT file for use with the chemical 

transformation module. The ozone concentrations are used as a surrogate for OH radical concentrations 

during the day when the gas phase free radical chemistry is active. 

4.6 Visibility Calculations

Calculations of the impact of the simulated plume particulate matter component concentrations on light 

extinction was carried out in the CALPOST postprocessor. The equation used is the usual 

IMPROVE/EPA equation which is applied to determine the change in light extinction due to changes in 

component concentrations. Using the notations of CALPOST, the formula is the following: 

Bext = 3f(RH)[(NH4)2SO4] + 3f(RH)[NH4NO3] + 

4[OC] + 1[Soil] + 0.6[Coarse Mass] +10[EC] + bray 

The concentrations, in square brackets, are in μg/m3 and bext is in units of Mm-1. The Rayleigh scattering 

term (bray) has a default value of 10 Mm-1, as recommended in EPA Guidance for Estimating Natural 

Visibility Conditions Under the Regional Haze Program (U.S. EPA, 2003b). Note that organic carbon 

(OC), which consists of condensable particulates, was modeled as SOA in CALPUFF runs. Soil is fine 

particulates which is defined as PMF in the CALPUFF runs, while Coarse Mass was labeled PMC. All 

particulate matter including EC, PMF, PMC and OC were modeled in CALPUFF with geometric mass 

mean diameter of 0.4 μm and geometric standard deviation of 2 μm. 

The haze index (HI) is calculated from the extinction coefficient via the following formula: 

HI = 10 ln(bext/10) 

where HI is in units of deciviews (dv) and bext is in Mm-1. The impact of a source is determined by 

comparing HI for estimated natural background conditions with the impact of the source and without the 

impact of the source. 
21 Air Quality Modeling Methodology 

CALPOST Method 6 was used to compute the extinction change in deciviews consistent with the 

procedures outlined in the Montana Protocol. A monthly background concentration must be entered into 

the CALPOST input control file. This background concentration was entered only for SOIL. The way it 

is computed makes it suitable to represent background light extinction for all particulates (hygroscopic + 

non-hygroscopic) at the same time when multiplied by an extinction coefficient of one. 

A monthly background concentration must be entered into the CALPOST input control file for all 

aerosols defining the background. The 20% best days for each of the seven Class I area were used for 

the natural background extinction calculations. The natural background values for the 20% best days as 

provided in the Guidance for Estimating Visibility Conditions Under the Regional Haze Program (U.S. 

EPA, 2003) and Montana Protocol are shown in Table 4-1. Table 4-2 provides the monthly f(RH) values 

based on the representative IMPROVE site location of the Class I areas as required for application of 

Method 6. The monthly f(RH) values for each month are extracted from Appendix A of Guidance for 

Estimating Natural Visibility Conditions Under the Regional Haze Rule (2003). 

In the BART procedures, the 8th highest (98th percentile) predicted change in light extinction expressed 

in deciviews is used as a metric to compare emission scenarios. 
22 Air Quality Modeling Methodology 

Table 4-1....................................................Summary of Background Natural Visibility Conditions 

Class I area 

Average Natural 

Concentration West (μg/m3

) 

Dry Extinction Efficiency 

Coefficient (m3/g) 

Ammonium sulfate 0.12 3 

Ammonium nitrate 0.10 3 

Organic carbon mass 0.47 4 

Elemental carbon 0.02 10 

Soil 0.50 1 

Coarse Mass 3.00 0.6 

Source: Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule (2003), Table 2-1

Table 4-2. Monthly f(RH) values based on the Representative IMPROVE Site Location, for Visibility 

Method 6 applications 

Class I area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

North Absaroka WA 2.4 2.2 2.2 2.1 2.1 1.9 1.6 1.5 1.8 2.0 2.3 2.4 

Yellowstone NP 2.5 2.3 2.2 2.1 2.1 1.9 1.7 1.6 1.8 2.1 2.4 2.5 

Washakie WA 2.4 2.2 2.2 2.1 2.1 1.9 1.6 1.5 1.8 2.0 2.3 2.4 

UL Bend WA 2.6 2.4 2.4 2.3 2.2 2.1 1.9 1.8 1.9 2.2 2.6 2.6 

Teton WA 2.5 2.3 2.2 2.1 2.1 1.9 1.7 1.6 1.8 2.1 2.4 2.5 

Gates of the Mountains WA 2.8 2.5 2.4 2.3 2.3 2.2 2.0 1.9 2.1 2.4 2.7 2.7 

Red Rock Lakes WA 2.5 2.3 2.2 2.1 2.1 1.9 1.7 1.6 1.8 2.1 2.4 2.5 

Source: Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule (2003), Appendix A 
23 Air Quality Modeling Methodology 

5.0 RESULTS 

The change in light extinction relative to the natural background due to SO2, NOx and PM10 from 

Corette was computed based on the base case emissions level during the modeling years (2001-2003), 

described in Section 2, and the emissions levels under the potential BART options being evaluated. The 

emissions levels for the base case and control alternatives are presented in Table 2-3. The CALPUFF 

modeling predicted the effects of emissions from the Corette unit on visibility at the seven Class I areas 

within 300 km of the facility. The BART methodology with CALPOST Method 6 and 98th percentile 

day results was used to determine visibility impacts. The light extinction impacts are presented for each 

modeled year in units of change in deciview (dv) for each of the seven Class I areas, consistent with the 

procedures outlined in the Montana Protocol. 

Tables 5-1 through 5-8 summarize the eight highest (98th percentile) predicted extinction changes for 

2001-2003 for the present emission case (Base Case) and seven control alternatives. For each control 

alternative, the emissions were altered for only the specific pollutant for which the control alternative 

applied, with the other pollutants modeled at their base case emissions. 
24 Air Quality Modeling Methodology 

Table 5-1....................................................................Summary of Visibility Results for Base Case 

Class I Area Minimum 

Distance (km) 2001 2002 2003 

 98th percentile delta-deciview 

North Absaroka WA 137 0.372 0.489 0.500 

Yellowstone NP 145 0.330 0.331 0.213 

Washakie WA 171 0.508 0.548 0.436 

UL Bend WA 192 0.645 0.365 0.572 

Teton WA 199 0.354 0.263 0.157 

Gates of the Mountains WA 276 0.126 0.246 0.098 

Red Rock Lakes WA 277 0.069 0.125 0.031 

Table 5-2.Summary of Visibility Results for Alternative 1 (SO2 Reduced 25% by Limestone Injection) 

Class I Area Minimum 

Distance (km) 2001 2002 2003 

 98th percentile delta-deciview 

North Absaroka WA 137 0.334 0.449 0.455 

Yellowstone NP 145 0.294 0.291 0.195 

Washakie WA 171 0.458 0.520 0.394 

UL Bend WA 192 0.568 0.322 0.539 

Teton WA 199 0.329 0.245 0.135 

Gates of the Mountains WA 276 0.112 0.221 0.081 

Red Rock Lakes WA 277 0.063 0.107 0.028 

Table 5-3.Summary of Visibility Results for Alternative 2 (SO2 Reduced 70% with a Dry Scrubber) 

Class I Area Minimum 

Distance (km) 2001 2002 2003 

 98th percentile delta-deciview 

North Absaroka WA 137 0.286 0.350 0.387 

Yellowstone NP 145 0.229 0.219 0.148 

Washakie WA 171 0.372 0.373 0.318 

UL Bend WA 192 0.427 0.235 0.446 

Teton WA 199 0.269 0.176 0.097 

Gates of the Mountains WA 276 0.085 0.172 0.054 

Red Rock Lakes WA 277 0.053 0.074 0.020 
25 Air Quality Modeling Methodology 

Table 5-4. Summary of Visibility Results for Alternative 3 (SO2 Reduced to 0.15 lb/MMBtu with a 

Wet Scrubber) 

Class I Area Minimum 

Distance (km) 2001 2002 2003 

 98th percentile delta-deciview 

North Absaroka WA 137 0.280 0.338 0.276 

Yellowstone NP 145 0.214 0.205 0.086 

Washakie WA 171 0.355 0.347 0.188 

UL Bend WA 192 0.407 0.219 0.248 

Teton WA 199 0.252 0.160 0.054 

Gates of the Mountains WA 276 0.079 0.163 0.041 

Red Rock Lakes WA 277 0.050 0.067 0.014 

Table 5-5.Summary of Visibility Results for Alternative 4 (NOx Reduced through Boiler Tuning) 

Class I Area Minimum 

Distance (km) 2001 2002 2003 

 98th percentile delta-deciview 

North Absaroka WA 137 0.353 0.460 0.478 

Yellowstone NP 145 0.308 0.313 0.197 

Washakie WA 171 0.485 0.505 0.410 

UL Bend WA 192 0.616 0.346 0.526 

Teton WA 199 0.331 0.244 0.152 

Gates of the Mountains WA 276 0.119 0.235 0.095 

Red Rock Lakes WA 277 0.068 0.120 0.030 

Table 5-6.................. Summary of Visibility Results for Alternative 5 (NOx Reduced with SOFA) 

Class I Area Minimum 

Distance (km) 2001 2002 2003 

 98th percentile delta-deciview 

North Absaroka WA 137 0.325 0.418 0.444 

Yellowstone NP 145 0.276 0.289 0.176 

Washakie WA 171 0.443 0.450 0.371 

UL Bend WA 192 0.573 0.313 0.463 

Teton WA 199 0.297 0.219 0.144 

Gates of the Mountains WA 276 0.112 0.214 0.089 

Red Rock Lakes WA 277 0.065 0.107 0.029 
26 Air Quality Modeling Methodology 

Table 5-7.Summary of Visibility Results for Alternative 6 (NOx Reduced to 0.15 lb/MMBtu with 

SCR) 

Class I Area Minimum 

Distance (km) 2001 2002 2003 

 98th percentile delta-deciview 

North Absaroka WA 137 0.298 0.381 0.390 

Yellowstone NP 145 0.245 0.264 0.161 

Washakie WA 171 0.401 0.410 0.332 

UL Bend WA 192 0.530 0.290 0.443 

Teton WA 199 0.263 0.200 0.136 

Gates of the Mountains WA 276 0.103 0.188 0.084 

Red Rock Lakes WA 277 0.061 0.095 0.029 

Table 5-8..........Summary of Visibility Results for Alternative 7 (Filterable PM Reduced to 0.015 

lb/MMBtu) 

Class I Area Minimum 

Distance (km) 2001 2002 2003 

 98th percentile delta-deciview 

North Absaroka WA 137 0.353 0.467 0.482 

Yellowstone NP 145 0.319 0.322 0.205 

Washakie WA 171 0.495 0.516 0.423 

UL Bend WA 192 0.633 0.356 0.549 

Teton WA 199 0.339 0.251 0.151 

Gates of the Mountains WA 276 0.121 0.241 0.093 

Red Rock Lakes WA 277 0.067 0.123 0.031 
27

6.0 REFERENCES 

FLAG, 2000. Federal Land Manager' Air Quality Related Values Workgroup (FLAG). Phase I 

Report. U.S. Forest Service, National Park Service, U.S. Fish and Wildlife Service. 

Scire, J.S., D.G. Strimaitis, and R.J. Yamartino, 2000a: A User’s Guide for the CALPUFF 

Dispersion Model (Version 5). Earth Tech, Inc., Concord, MA 

Scire, J.S., F.R. Robe, M.E. Fernau, and R.J. Yamartino, 2000b: A User’s Guide for the 

CALMET Meteorological Model (Version 5). Earth Tech, Inc., Concord, MA. 

U.S. Environmental Protection Agency (EPA), 1998: Interagency Workgroup on Air Quality 

Modeling (IWAQM), Phase 2 Report: Summary Report and Recommendation for 

Modeling Long Range Transport and Impacts on Regional Visibility. EPA-454/R-98-

019. 

U.S. Environmental Protection Agency (EPA), 2003a: Revision to the Guideline on Air Quality 

Models: Adoption of a Preferred Long Range Transport Model and Other Revisions; 

Final Rule. 40 CRF 51. Federal Register, April 15, 2003, 68, 72, pp 18440-18482. 

U.S., Environmental Protection Agency (EPA), 2003b: Guidance for Estimating Natural 

Visibility Conditions Under the Regional Haze Program. EPA-454/B-03-005, 

September 2003. 

U.S. Environmental Protection Agency (EPA), 2005: Regional Haze Regulations and 

Guidelines for Best Available Retrofit Technology (BART) Determinations; Final Rule, 

40 CFR 41. Federal Register, July 6, 2006, 70, 128, pp 39104-39172. 
i