BestAvailable Retrofit
 

Teclmology (BART)
 

Assessment
 

Colstrip Generating Station
 

Prepareafor 

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PPL Montana, LLC 

Billings Montana 

Prepared by 

(iTRC 

Windsor, ConnectK:ut 

August 2007 
Best Available Reuofit
 

Technology (BART)
 

AssessInent
 

C~lstrip C-.enerating
 

Station
 

Prepared for 

PPL Montana~ LLC 

BIIIIngs. Montana 

21 Griffin Road North 

Windsor, Connecticut 06095 

Telephone 860-298-9£92 

Facsimile 860·298·6399 

TRC Proj~t No, 114175 OOZQ 00004 

August 2007 
TABLE OF CONTENTS 

SECTION PAGE 

EXECUTIVE SUMMARY ES-I 

1.0 INTRODUCTION/BACKGROUND I-I 

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 2-4
 

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
 

4.2 Evaluated Retrofit Technologies for Colstrip Units I &2 .4-8
 

4.2.1 Particulate Controls 4-8
 

4.2.1.1 Particulate Control Technologies .4-9
 

4.2.1.2 Costs of Controls 4-11
 

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 4-14
 

4.2.2 Sulfur Dioxide Controls 4-15
 

4.2.2.1 Control Technologies 4-15
 

4.2.2.2 Cost of S02 Controls 4-16
 

4.2.2.3 Energy 4-16
 

4.2.2.4 Non-Air Quality Environmental Impacts .4-17
 

4.2.2.5 Remaining Useful Life 4-17
 

4.2.2.6 Visibility Modeling 4-17
 

4.2.3 NOx Controls 4-18
 

4.2.3.1 Control Technologies 4-19
 

4.2.3.2 Cost ofNOx Controls 4-19
 

4.2.3.3 Energy 4-20
 

4.2.3.4 Non-Air Quality Environmental Impacts .4-20
 

4.2.3.5 Remaining Useful Life 4-20
 

4.2.3.6 Visibility Modeling 4-20
 

4.3 Visibility Modeling Procedures and Results 4-21
 

4.3.1 General Modeling Procedures .4-21
 

4.3.2 Summary of Modeling Results 4-22
 

5.0 SUMMARY AND CONCLUSIONS 5-1
 

6.0 REFERENCES 6-4
 
TABLE OF CONTENTS 

(Continued) 

LIST OF TABLES
 

Table ES-I: Current / NSPS / Control Options Cost Summary ES-5
 

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

Table 2-1: Colstrip Particulate Matter Type and Size Speciation 2-2
 

Table 2-2: Present (Base Case) S02 and NOx Emissions 2-3
 

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

Table 4-2: Particulate Emissions Summary for Colstrip 1&2 4-8
 

Table 4-3: PPL BART Particulate Control Cost Summary (Each Unit) .4-12
 

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

Table 4-5: Summary of Modeling Results for Particulate 4-15
 

Table 4-6: PPL BART S02 Control Cost Summary (Each Unit) .4-17
 

Table 4-7: Summary of Modeling Results for S02 4-18
 

Table 4-8: PPL BART NOx Control Cost Summary (Each Unit) .4-19
 

Table 4-9: Summary of Modeling Results for NOx •••••••••••••.•••••••••••••••••••••••••••••••••••••••••••••••••• 4-21
 

Table 4-10: Summary of Modeling Results 4-23
 

Table 5-1: Current / NSPS / Control Options Cost Summary 5-3
 

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

LIST OF FIGURES
 

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

APPENDICES 

APPENDIX A: DETAILED COST CALCULATIONS 

APPENDIX B CALPUFF APPLICAnON FOR BART ASSESSMENTS AT PPL COLSTRIP 

UNITS 1&2 

ii 
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 a degradation of visibility at Prevention of 

Significant Deterioration (PSD) mandatory Class I Areas. 

Coal fired Units I&2 at the Colstrip generating plant located in Colstrip, Montana, jointly 

owned by Puget Sound Energy and PPL Montana, LLC and operated by PPL Montana, LLC 

were 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 Colstrip are the 

UL Bend National Wildlife Refuge (200 km to the northwest), the North Absaroka Wilderness 

Area (254 km to the west), the Theodore Roosevelt National Park (260 km to the northeast), the 

Washakie Wilderness Area (278 km to the southwest) and Yellowstone National Park (281 km to 

the west). These Class I areas are shown in relation to the Colstrip plant in Figure ES-1. 

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

from the Colstrip Units 1&2 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 to the modeling as 

described in Appendix B. The highest modeled annual 98th percentile daily visibility impact of 

emissions from Units 1&2 at present maximum actual emissions as predicted to occur in the UL 

Bend National Wildlife Refuge (NWR) Class I area is 2.233 deciviews. A summary of the 

visibility modeling results is provided in Table ES-2. 

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

been applied to Colstrip Units 1&2 to identify the "best system of continuous emission 

reduction" applicable to the plant for filterable particulate, sulfur dioxide (S02) and nitrogen 

oxides (NOx) control in order to comply with Region 8's BART program. These units already 

have relatively low emissions due to the use of wet scrubbers that remove both particulate and 

sulfur dioxide, low sulfur Powder River Basin coal and good combustion control using low NOx 

burners. A range of demonstrated control alternatives for sub-bituminous coal-fired boilers was 

ES-l 
Figure ES-l: Colstrip Location and Class I Areas Evaluated 

.6. 

Colstrip 

Idaho 

North Absaroka Wilderness 

Nebraska 

..Class I Areas Modeled 

O._-==5liL_=1:i°iO i200E:=====3:i°iO 1llii40~i1ometers (TRC 

ES-2
 
evaluated considering costs, energy and environmental impacts, remaining useful life of the units 

and modeled visibility improvements. A summary of the results ofthe evaluations is provided in 

Table ES-l. 

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

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

conducted for fabric filters and ESPs. Mechanical collectors were not further evaluated because 

these are used as pre-filters and do not perform well as a retrofit option. The Colstrip Units 1&2 

already have venturi wet scrubbers that control both particulate matter and SOz emissions and 

therefore either an upgrade to the current technology, or the addition of fabric filter/ESP controls 

would be necessary to attain an emission rate equivalent to the best demonstrated technology 

(BOT) filterable particulate emission rate of 0.0 15 lbs/MMBtu. An upgrade to the existing 

scrubber technology was not evaluated as the existing particulate emissions level is already so 

low that there is little room for further improvement of the scrubber. For installation of an ESP 

or fabric filter, this would cost approximately $30,000 to $40,000 per ton of particulate 

emissions controlled and result in only a 0.042 deciview reduction which is not a visibly 

discernable improvement. Consequently, implementation of additional particulate control at 

Colstrip is not warranted. 

The cost effectiveness analysis for SOz and NOx was based on emission rates typical of 

30-day average emissions. These rates for the present (base case) emissions are 0.40 Ib/MMBtu 

for SOz and 0.35 Ib/MMBtu for NOx. However, consistent with the modeling guidance, the 

visibility modeling analysis was conducted at maximum daily emission rates. For the present 

(base case) emissions these maximum rates during the modeling years for SOz are 0.72 

Ib/MMBtu for Unit 1 and 0.80 Ib/MMBtu for Unit 2 and for NOx they are 0.45 Ib/MMBtu and 

0.53 Ib/MMBtu respectively. This distinction was also made for the control alternatives as well 

as for the base case. For filterable particulate, continuous emissions data (CEM data) are not 

available and a distinction between maximum and typical emission rates was not made. The 

present filterable particulate emission rates based on stack test data are 0.047 Ib/MMBtu and 

0.058 Ib/MMBtu for Units 1&2, respectively and the condensable particulate emission rates 

based on AP-42 emission factors are 0.038 Ib/MMBtu for both units. 

Upgrades to the current venturi scrubbers were considered as a way to improve SOz 

removal efficiency. The low sulfur Powder River Basin (PRB) coal is alkaline by nature and 

there is an estimated 75 percent control of SOz by virtue of flyash alkalinity acting with 

ES-3
 
scrubbing liquor alone. Enhancements to this removal have been evaluated that include the 

addition of lime to the scrubbers presently in operation to enhance removal. The addition of lime 

is projected to increase S02 removal efficiency from the present 75 percent level to 

approximately 88 percent with little adverse operational impact at a cost effectiveness (CE) of an 

estimated $2l8/ton of additional S02 removed. [t is projected that even higher increase in S02 

removal efficiency to 91 percent, which corresponds to the EPA presumptive BART S02 rate of 

0.15 lb/MMBtu can be achieved with even more lime addition, however, at additional costs. 

This presumptive rate applies to some coal-fired boilers, but it does not apply to the Colstrip 

boilers because they already achieve over a 50 percent control efficiency. Nevertheless, this rate 

was evaluated. The increased addition of lime to attain the 91 percent removal will incur scaling 

of the scrubber with significant downtime to descale the scrubbing vessel at an estimated cost of 

$499/ton of S02 removed. To eliminate the downtime for descaling, a spare scrubber vessel 

could be installed to eliminate downtime at a CE of $1 ,292/ton. Incremental CE of the high lime 

injection, and the backup scrubber module options are $1,621 and $5,590/ton respectively. Cost 

estimates are based on EPA Control Cost Manual information and techniques and PPL operating 

experience. All costs are indicated in 2007 dollars. Only a 0.422 deciview reduction is predicted 

with lime addition to improve S02 removal to 88 percent. This improvement is below the level 

considered discernable to the human eye. The incremental improvement to go beyond 88 

percent reduction is only 0.146 deciviews or less. Consequently, implementation of these controls 

is not warranted. 

NOx controls at Colstrip include the tangential firing design of the boilers and existing 

10w-NOx burners with close-coupled overfire air. The present typical annual emission rates are 

0.35 lb/MMBtu for each unit. By the addition of separated over-fire air (SOFA) and 

redistribution of combustion air to the multiple injection ports for the current NOx controls, it is 

likely that emissions can be reduced to an average of 0.18 lb/MMBtu at a cost effectiveness of 

$451/ton. Selective non-catalytic reduction (SNCR) by injection of urea into the same zone 

within the unit is projected to have only a slight additional effect on the 0.18 lb/MMBtu SOFA 

controlled rate resulting in a projected rate of 0.16 lb/MMBtu. The cost of SNCR technology has 

been estimated at $977/ton of NOx controlled, 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) was also reviewed to attain emissions to the presumptive BART NOx rate of 0.15 

ES-4
 
Ib/MMBtu, however its incremental cost over the addition of SNCR makes SCR economically 

unacceptable at an estimated $2,286/ton of NOx, and an incremental cost effectiveness of 

$30,786/ton. On a visibility basis, only a 0.573 deciview improvement results from 

implementation of SOFA. This improvement is unlikely to be visibly discernable. The 

incremental improvements from controls beyond SOFA are 0.163 deciviews or less. 

Consequently, implementation of controls is 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-l, 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. 

Table ES-l: Current / NSPS / Control Options Cost Summary 

Particulate Maller Sulfur Dioxide Nitrooen Oxides

Rate Units Rate Units Rate Units Control

Current(l) 

Emission rate 0.4 COFA(2) 0.050 Ib/MMBtu Ib/MMBtu 0.35 Ib/MMBtu

BD"jO) from I 

2006 NSPS 0.015 Ib/MMBtu 1.4 Ibs SOl/MW out 10 Ib/MWout

New Sources (0.15 Ib/MM Btu in ro.11 Ib/MM Btu in 

Cost Effeciveness Calcs Cost Effeciveness Calcs 

Option Evaluated Option Evaluated CE(7) Option Evaluated CE(8) Inc CE Inc CE

Rate Rate Rate 

Ib/MMBtu $/ton IblMMBtu $/ton $/ton Ib/MMBtu $/ton $/lon 

Control Added ESP 0015 $38,738 Present 0.4 $0 Present 0.35 

Options Added FF 0.015 $29,599 WS-FGD(4) 0.2 $218 SOFA 0.18 $451 

WS-FGD(5) 0.15 $499 $1,621 SNCR 016 $977 $3,424

WS-FGD(1l) 0.15 $1,292 $5,590 SCR 0.15 $2,272 $26,938 

Notes 1) Colstrip Unit 1 = 0047, Unit 2 = O.058lb/MMBtu ; 0.05 Ib/MMBtu used as representative of each unit 

2) Low-NOx Burners with Close-Coupled Ovetfire Air 

3) 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 megawall 

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

4) Wet Scrubber-Flue Gas Desulfunzatlon; actual emissions are 0.40 Ibs/MMBtu (per CEMS); 

adding lime to the scrubber will reduce emissions by 50% 

5) Similar to 3 but additional downtime due to scaling to allain a reduction to 0 15 Ibs/MMBtu 

6) Similar to (4), but more lime and an additional scrubber (per unit) necessary to reach the presumptive limit 

7) Control options considered separately; incremental cost of scrubbing options 

compares the relative additional removal to the baseline lime injected scrubber option 

8) Control options considered separately; incremental cost of SNCR 

and SCR reflect the relative cost of increased NOx removal 

ES-5
 
Table ES-2: Modeled Visibility and Visibility Improvements 

Sulfur Dioxide Nitrogen Oxides 

Modeled 

Filterable Particulate 

Improvement (7) 

Rate (1)(2) 

Improvement (7) Modeled Improvement (7) Modeled 

Prediction (3) from Rate (1 )(2) Prediction from Rate (1)(2 Prediction from
 

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

Present 

(lb/MMBtu) (deciviews) Present Option Present 

n/a n/a Present 2.233 n/a n/a Present 0.45/0.53 n/a n/a 

New ESP 

0.047/0.058 2233 0.72/0.80 2233 

WS-FGD(4) 0.422 023/0.27 1.781 0573 

Added FF 

0.015 2213 0.042 0.042 0.36/0.40 2.000 0.422 SOFA 0.573 

WS-FGD(5) 1.954 0.505 SNCR 0.21/0.24 1.713 0.638 0.068 

WS-FGD(6) 

0.015 2213 0042 0.042 0.27/030 0.091

0.15 1.832 0.651 0.146 SCR 0.15 1.584 0.801 0.163

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

(2) If Unit 1 and Unit 2 emission rates are different, they are indicated as Unit 1/Unit 2 rates. 

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

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

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

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

(7) Maximum improvements shown may occur at differeent Class I areas that the maximum prediction among all Class I areas. 

ES-6
 
1.0 INTRODUCTION/BACKGROUND 

The U.S. Environmental Protection Agency (EPA) Region 8 identified Colstrip 

generating station Units 1&2 as Best Available Retrofit Technology (BART) eligible units. This 

determination was made under the federal Regional Haze Rule (FR, Vol. 64, No. 126) which 

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 

(FlP) for Montana sources. Regional haze is caused by naturally occurring atmospheric particles 

and humidity as well as by anthropogenic emissions of primary particulate matter and of 

secondary emissions resulting from atmospheric gas to particle conversions of sulfur dioxide 

(S02) and nitrogen oxides (NOx). The BART regulations identify large stationary source 

emission units put into operation between 1962 and 1977, such as Colstrip Units 1&2, as BARTeligible. The pollutants subject to BART requirements are S02, NOx, particulate matter 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 S02, NOx, 

particulate matter and VOC emissions. Colstrip Units 1&2 each have a generating capacity of 

307 megawatts (MW), and have low S02 emissions due to the use of low sulfur coal and venturi 

scrubbers. Because Units I&2 already have post-combustion S02 scrubbers achieving greater 

than 50 percent S02 removal, BART presumptive S02 rates applicable to power plants with over 

750 MW capacity do not apply to Colstrip. The BART presumptive NOx rates, however, do 

need to be considered. There are no BART presumptive particulate rates. Units 1&2 have been 

evaluated for S02, NOx, and particulate matter controls. 

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 

I-I
 
results from the proposed emissions limit. The best system of continuous emission reduction is 

identified based on: 

• The available retrofit control options 

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

• The cost ofthe systems 

• The remaining use-life ofthe facility 

• The energy and non-air quality environmental impacts ofthe systems 

• The visibility impact analysis. 

This report details these steps for Colstrip Units 1&2. 

1-2
 
2.0 PLANT DESCRIPTIONS - BART AFFECTED UNITS 

2.1 Boiler Type 

The Colstrip Power Plant consists of a total of four electric utility steam generating units, 

however only Units 1&2 are subject to BART since Units 3&4 were not operational during the 

BART eligibility period. Units 1&2 are subject to BART and have a nominal net capacity of 307 

megawatts each. The boilers which began commercial operation in 1975 and 1976 are 

tangentially fired pulverized coal boilers that bum sub-bituminous coal as their exclusive fuel. 

PPL Montana LLC operates the Colstrip Plant under Air Quality Operating Permit OP0513-02. 

2.2 Emissions 

Present (base case) particulate matter emissions for Colstrip Units 1&2 are summarized 

in Table 2-1. The heat input rates (and associated emissions) for each boiler (3,981.8 MMBtu/hr 

and 3,897.2 MMBtu/hr) used to derive the particulate matter emissions are the highest daily 

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

corresponding to these heat input rates were used for modeling the base case. 

The total filterable particulate emission rates are based on stack tests conducted during 

the modeling years. For each unit, the highest of the single stack test conducted during each of 

the modeling years (2001-2003) was used. This is 0.047 Ib/MMBtu for Unit I and 0.058 

Ib/MMBtu for Unit 2. The speciation of the total filterable particulate into elemental carbon, fine 

soil and coarse soil and size fractions were based on guidance provided by the National Park 

Service (NPS). Stack test data for condensable particulates are not available for Units 1&2 

during the modeling years. The total condensable emissions are based on the AP-42 emission 

factor using a coal sulfur content of 0.68 percent, which is the highest annual average as received 

sulfur content during the modeling years. This gives a condensables emission rate of 0.038 

Ib/MMBtu for each unit, which was speciated into organic and inorganic particulate based on 

guidance provided by the NPS (20% organic and 80% inorganic). The particulate emissions 

used for the visibility modeling and the cost analyses were based on these filterable and 

condensable emission rates and the maximum daily average heat input during the modeling years 

(3,981.8 MMBtu/hr and 3,897.2 MMBtu/hr). 

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 total 

2-1
 
I 

Table 2-1: Colstrip Particulate Matter Type and Size Speciation 

Particle S - --­ Col 

Stack ID # 

Unit I 

Unit 2 

C B 

Particle speciation 

filterable PM 10 condensable PM IO 

0/0 0/0 

55.3 44.7 

60.4 39.6 

Condensable 

organic H2SO4 condensable (OC) 

M1=0.48, SD1=2.0 Jim 

Ib/hr Ib/hr 

30.26 121.05 

29.62 118.47 

COARSE 

Ib/hr 

53.47 

64.58 

Filterable 

Soil 

M1=0.48, SD1

=2.0 Jim 

Ib/hr 

128.73 

155.48 

M and SD stand for Geometric Mass Mean Diameter and Geometric Standard Deviation. These are the parameters used to calculate the particle size distribution 

2-2
 
filterable values used here are more accurate because they are based on stack test data. They are 

higher than the values that EPA used. In terms of mass emissions, the modeling presented here 

used total filterable particulate emissions of 187.2 Ib/hr for Unit 1 and 226.0 Ib/hr for Unit 2 

versus values used in the EPA modeling of 30.8 Ib/hr and 37.2 Ib/hr. The total condensables 

emission rates provided by PPL and used for modeling are similar the emission rates used in the 

EPA modeling. In terms of mass emissions, the modeling presented here used total condensables 

for Units 1&2 of 151.1 lb/hr and 148.1 Ib/hr respectively, versus values used in the EPA 

modeling of 123.0 Ib/hr and 148.7 Ib/hr. 

The S02 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 analyses, S02 and NOx present emission rates were based on typical 

emission rates representative of a 30-day rolling average actual emission rate for the units. 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 Tables 2-1 and 

the S02 and NOx present emissions are summarized in Table 2-2. 

Table 2-2: Present (Base Case) S02 and NOx Emissions 

Pollutant Emissions 

Unit 

Typical/Average 

Emission Rate (1) 

(lb/MMBtu) 

Maximum 

Emission Rate(2) 

(lb/MMBtu) 

Maximum 

Mass Emissions(2) 

(lb/hr) 

S0 2 Unit 1 0.40 0.72 2612.0 

Unit 2 0.40 0.80 2828.0 

NOx Unitl 0.35 0.45 1798.0 

Unit2 0.35 0.53 1955.0 

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. 

2-3
 
2.3 Potentially Impacted Class I Areas 

The Class I areas within 300 km of Colstrip are the UL Bend National Wildlife Refuge 

(200 km to the to the northwest), the North Absaroka Wilderness (254 km to the west), the 

Theodore Roosevelt National Park (260 km to the northeast), the Washakie Wilderness (278 km 

to the southwest) and Yellowstone National Park (281 km to the west). These Class I areas are 

shown in Figure ES-l. 

2-4
 
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 S02, NOx, VOC or particulate matter emissions of 250 tons per year (tpy) or more, and 

having construction dates between 1962 and 1977. These eligibility criteria include Colstrip 

Units 1&2 as BART-eligible units. 

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

for normal operating conditions of the units during the modeling period (2001-2003) and for 

each emission reduction percentage evaluated for the retrofit control options. 

Potentially applicable retrofit filterable PM, S02, and NOx control technologies which 

represent a 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 units. 

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-452-02-00 I, January 2002) was utilized where such data were 

available. The BART Final Rule states: 

3-1 
"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 detailfor a BARTanalysis. " 

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

S02 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 cited 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. 

In the capitalization of the total capital 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. 

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 particulate matter accordingly 

increases the solids collected. The addition of scrubbing solids to react with S02 may change the 

character of the ash residue and alter its salability. In the case of some NOx reduction 

technologies, ammonia used in the catalytic reduction equipment is an additional pollutant that 

can increase particulate matter formation. 

Remaining Useful Life 

The lives of the Colstrip boilers are expected to exceed the study period and projected to 

have no effect on the costing analyses for this facility. 

Visibility Impacts 

3-2
 
The modeled results for visibility impact, in units of deciviews, of application ofthe 

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

3-3
 
4.0. BART ANALYSES 

4.1 Approach 

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 

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. 

For the BART analyses, Colstrip Units I&2 were evaluated with respect to particulate 

emissions (particulate-filterable portion only), sulfur dioxide (S02) 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 BART eligible 

emissions units and pollutants under consideration for Colstrip. 

The Colstrip boilers fire sub-bituminous coal having a sulfur content typically under 1 

percent by weight. The permit limit for S02 emissions is specified as no more than 1.2 

Ib/MMBtu of heat input. Boilers I&2 are controlled by venturi scrubbers for simultaneous 

particulate and S02 control, and close coupled overfire air 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 analyses that reflect 

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 particulate, 

4-1
 
S02, 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 II, 1979. On February 27, 2006 

(see FR, Vol. 71, No. 38) the particulate, S02, 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 ofthe 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 represent the most stringent level of emissions control for new EUSGUs. 

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

facility), actual emission rates, the presumptive BART levels and the 2006 NSPS for particulate, 

S02, 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 particulate, S02, and NOx by EPA are discussed in the following 

sections. 

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

FOR THE PPL MONTANA , LLC , COLSTRIP UNITS 1&2

Particulate Matter Sulfur Dioxide Nitrogen Oxides 

Rate I Units Rate I Units Rate T Units 

Permitted 

Allowable(l) 0.1 IblMMBtu 1.2 IblMMBtu 0.45 Ib/MMBtu 

Emission Rate 

Current Typical 

Emission rate 0.050 Ib/MMBtu 0.4 IblMMBtu 0.35 Ib/MMBtu 

Colstrip Units 1&2 

BDT(3) from 

2006 NSPS 0.015 Ib/MMBtu 1.4 Ibs S02/MW out 1.0 IblMW out 

New Sources (0.15 Ib/MM Btu in) m.11 IblMMBtu in) 

Presumptive (4) 

BART for Not Applicable 0.15 Ib S02/MMBtuf5! 0.15 Ib/MMBtu(6) 

Laf/1;e EUSGUs 95 % control Itan!! fired sub-bituminous) 

Notes	 I) From current Title V Operatmg Permit - NOx short term IImll IS 0.7 IbIMMBtu; 

The allowable NOx limit is 0.45 Ib/MMBtu on an annual average basis 

2) EPA Reference Method 5 for PM and from coal analysis for S02 

3) BOT = "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 revised standards
 

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

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

post-combustion pollutant-specific controls 

5) Not applicable to Colstrip under the BART Guidelines 

6) Applicable to Colstrip under BART Guidelines 

4-2 
EPA's Regulatory Approach to the NSPS Revisions 

The publication ofthe 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 S02 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 ofthe 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 EPA's 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 S02 control technologies, as well as technologies for the control 

ofother pollutants, confirmed by a number ofrecent retrofits at Western power plants. 

Accordingly, EPA no longer concludes that the NSPS level ofcontrols automatically 

represents "the best these sources can install ". Analysis ofthe BARTfactors could result 

in the selection ofan NSPS level ofcontrol, but you should reach this conclusion only 

after considering the full range ofcontrol 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 particulate, S02, 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 Colstrip Units 1&2. The present NSPS levels for 

particulate and S02 were considered as well as the S02 and NOx presumptive BART levels and 

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

lowest level evaluated. 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: 

4-3 
• 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 fi Iters are highly efficient on very small particles and are capable of 

achieving high efficiencies of99 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. 

4-4
 
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 SOz 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 avai lable SOz control technologies in the Proposed Rule that led 

to revision of the NSPS for SOz 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 

• Fluidized-bed Combustion with Limestone 

Coal Pre-Treatment 

There are two basic coal pre-treatments that can reduce SOz 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 SOz has been 

demonstrated. 

4-5
 
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 S02 laden flue gas prior to 

the particulate collection device. Removal of S02 depends on the stoichiometric ratio of reactant 

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

particulate 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 particulate 

collection device. S02 removal occurs by adsorption of the pollutant on the particle surface and 

collection of the resulting solids with the fly ash in the particulate 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 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 ofNOx controls in EUSGUs.
 

• Primary NOxCombustion Controls 

o Low-NOx Burners (LNBs) 

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

o LNBs with OFA 

o Rotating Opposed Fire Air (ROFA) 

o Combustion Improvement Techniques 

• Secondary Control Techniques 

o Reburning 

o Selective Catalytic Reduction (SCR) 

o Selective Non-Catalytic Reduction (SNCR) 

4-6 
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 aI., 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 result in 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 (PRS) 

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

Over-Fire Air (OFA)/Air Staging and LNBs with OFA 

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% 02. 

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. 

4-7
 
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 ofthe locations of OFA injection locations to obtain optimum results. 

Selective Catalytic Reduction (SCR) 

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

zeolite to reduce NOx to molecular nitrogen. 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. 

4.2 Evaluated Retrofit Technologies for Colstrip Units I &2 

The following sections evaluate retrofit control technologies for Colstrip Units 1&2 for 

particulate matter, S02 and NOx • 

4.2.1 Particulate Controls 

The following table provides the present particulate emission rates from Colstrip Units 

1&2, as described in Section 2.2. 

Table 4-2: Particulate Emissions Summary for Colstrip 1&2 

Condensable 

Ibs/hr 

151.3 

148.1 

Condensable 

Ib/MMBtu 

0.038 

0.038 

4-8
 
The heat input rates shown above are the highest daily average heat input rates during the 

modeling years (2001-2003). The total particulate emission rate applied to these heat input rates 

is 0.085 Ib/MMBtu and 0.096 Ib/MMBtu respectively for Units I&2 based on stack test data. 

The speciation of the particulate emissions is described in Section 2.2. The above data show that 

emission rates from Units I&2 are already low due to the good combustion techniques and 

application of wet scrubbing being used in these boilers. The filterable particulate emission rates 

are typical for wet scrubbing using venturi scrubbing technology in coal-fired utility boilers. 

It is necessary, as part of the BART analysis, to identify the best demonstrated emission 

rate that a technology can deliver. Step I in the BART analysis process is considered complete if 

the BOT rate, the New Source Performance Standards (NSPS) emission rate, and emission rate 

from current New Source Review permits are included. The following list of potential filterable 

particulate control technologies has been evaluated for Colstrip Units 1&2: 

4.2.1.1 Particulate Control Technologies 

Electrostatic Precipitators and Fabric Filters (ESP/FF) 

In the Proposed Rule, EPA discussed these technologies as interchangeable. Both are 

capable of the control of fine particulate matter by 99+ percent for coal fired boilers. The 

Colstrip boilers are equipped with wet scrubbing technology that performs a dual function of 

particulate and SOz control. It is possible however, to use add-on control devices to attain the 

BOT emission rate of 0.015 Ib/MMBtu for Colstrip Units 1&2. 

Either ESP or FF technology could be applied to Colstrip Units 1&2. The additional 

removal of fine filterable particulate would be limited, however, it is assumed that either could 

attain the NSPS BOT limit of 0.015 IbIMMBtu. Ordinarily, FF technology would be eliminated 

from consideration because of the saturated exhaust from the venturi scrubbers. In the case of 

the Colstrip units, however, the exhaust is reheated to above the dew point by steam 

condensation reheat exchangers and therefore add-on devices could be feasible. Both 

technologies have therefore been analyzed as available and applicable add-on particulate 

controls. 

Mechanical Collectors 

Mechanical collectors, sometimes known as inertial separators, use the momentum of 

particulate matter to concentrate and remove particles from a gas stream. Devices such as 

cyclones and settling chambers are in this group of controls. Multiple parallel cyclones are often 

4-9
 
used in particulate control to obtain relatively high removal efficiencies of even fine particulate. 

One reference states that a multiple cyclone can control high percentages of particulate generated 

by coal-fired units, but cannot attain the very low regulatory allowable emission rates of the 

NSPS or most state agencies. 

Mechanical collectors, almost exclusively multiple cyclones, have been used on coal 

fired boilers as pre-filters to reduce particulate emissions to the primary control device. 

However, it is not possible to retrofit mechanical collection equipment to the Colstrip boilers 

since it must be installed before the main collector and in association with the design of the main 

collector. Furthermore, the existing wet scrubbers are already achieving an efficiency higher 

than would be achieved by mechanical collectors. Mechanical collectors were, therefore, given 

no consideration as an available retrofit technology. 

Wet Scrubbers 

Scrubbing equipment adds the effect of water washing to the inertial separation of 

mechanical collectors. The common venturi scrubber is a device where a converging section of 

duct is injected with water. The water, normally injected at the narrowest point in the venturi 

throat, expands downstream into micron and submicron sized droplets. High pressure drops are 

typically utilized to create the minute water droplets that are capable of absorbing the fine 

particulate. Particulate laden gases entering the throat of the venturi are captured by impaction 

and absorption in the downstream section of the venturi scrubber. The particle laden liquid can 

be filtered, recycled, and reused in most cases. As noted previously, particulate removal 

efficiencies of these types of devices, while not as high as baghouses and fabric filters, are 

potentially as high as 99 percent even for fine particulate generated from coal firing. 

Wet scrubbers are currently operating to control particulate and S02 emissions on 

Colstrip Units 1&2. While enhancements to particulate collection efficiency are potentially 

possible, the filterable emission rates of 0.047 and 0.058 Ib/MMBtu, as determined from stack 

testing, are already very low and indicative of excellent control efficiency for this technology. 

Furthermore, enhancement of the wet scrubbers would not be expected to result in additional 

particulate removal. Accordingly, ESP and FF controls were the applicable and available control 

technologies to enhance the already 98% particulate control efficiency of the Colstrip Units 1&2 

boilers. 

4-10
 
Other Impacts of Technically Feasible Control Options 

Other criteria are relevant in the BART selection process. The costs of retrofit controls, 

the energy consumption of these controls, and the non-air quality environmental impacts of the 

controls are included in the BART selection process. This section discusses these additional 

factors. 

4.2.1.2 Costs ofControls 

The costs of ESP and FF filterable particulate controls for application to the Colstrip 

Units 1&2 boilers were evaluated. The cost of control makes the assumption that adequate land 

acreage is available to locate the devices and that the controls will be installed after the ID fan 

and plume reheat exchangers. The cost effectiveness (CE) is assumed to be an incremental value 

determined as that to reduce the current particulate emissions of 0.058 Ib/MMBtu (Unit 2) to the 

BOT emission rate of 0.015 Ib/MMBtu. Unit 2 was analyzed as an example because it has the 

higher filterable particulate emission rate which would give the lower ofthe two CE values. 

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 for 99 percent control. Table 4-3 shows the ESP costing calculations 

for a 68 percent reduction from present emissions levels, which would reduce filterable 

particulate emissions to 0.015 Ib/MMBtu, see Appendix A, Tables A4-3(a) and A4-3(b) for 

complete details. The electrification of the fields and rapper costs are based on the specific 

collection area estimated for one PPL Colstrip boiler in accordance with EPA recommendations. 

The annualized cost is an incremental cost to reduce the current particulate emissions from one 

boiler. Equipment maintenance, administrative annual costs, and all calculations use the 

standardized OAQPS control costing methods. It is speculative whether this control efficiency 

could be attained for a unit with a present filterable particulate emissions level of 0.05 

Ib/MMBtu. At a CE of about $30,000 to $40,000/ton of additional control, this is not considered 

economically justifiable. 

The analysis of the cost of ESP and FF control summarized in Table 4-3 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 FF. EPA cost factors specifically developed for FF technology 

were used. An annualized capital cost ofthe equipment was determined using a capital recovery 

4-11
 
Figure 4-1: Cost Analysis of ESP Control 

110 _-----_,__,_..,..--,I""'""'..,..-'r""""-'t""""---,---"""T-------, 

I 

I 

I 

I 

LOW SULFUR, 

I 

100 

I 

.-

10 

• 70 CONSERVATIVE OESIGNS 

I 

I 

I 

ADVANCED 

DESIGNS I 

".HIGH SULFUR : I 

I I 

I I 

I I 

20 1971 

NIPS. 1979 NIPS 

I 

10 I 

I 

".0 ".0 .... 99.7 H.9 

COWCTJON EFFICIENCY·. " 

• eASED ON A COAL "AltO AT '0.000"'''' AND CONTAINING 1M' ASH. THE 117' 

N....IS 0.' ."oe Ihu. AND THE ,..,. NIPS IS 0.03 ."0' ..... 

Table 4-3: PPL BART Particulate Control Cost Summary (Per Unit) 

Tons 

Option Description Total Annual controlled Cost 

Cost ($) Effectiveness 

$/ton 

Added ESP Control $21,754,115 562 $38,738
 

Added Fabric Filtration $16,622,318 562 $29,599
 

4-12 
factor based on a depreciation schedule 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. As in the case of ESP controls, the 

cost estimate has been prepared for Colstrip Unit 2 and would be higher for the other unit, asUnit 

1 has a slightly lower filterable particulate emission rate. At a CE of approximately $30,000 to 

$40,000/ton of additional particulate controlled, application of this option is not economically 

justifiable. 

4.2.1.3 lSner£rV 

Although full costing data were not developed for each potential particulate 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 and venturi scrubber control. 

The energy cost of the control options is included in the cost effectiveness Table 4-3. 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) = 1.8 I x 10-4

x ACFM x ~p x annual operating hours 

Where:	 1.81 x 10-4 is a proportionality constant 

ACFM = the actual cubic feet per minute exhaust treated 

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

The following Table 4-4 is presented to illustrate the power consumption requirements of 

the four common types of particulate 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 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 particulate collection. The Colstrip scrubber pressure drop for Units 1&2 is on 

the order of 35" of water. 

4-13 
Table 4-4: Representative Control Equipment Pressure Drops 

Control Option Typical Ap 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 

4.2.1.4 Non-Air Quality Environmental Impacts 

The ESP or FF particulate controls for Colstrip, would generate a new particulate waste 

stream. The current ash collected by the scrubbers would remain, however, operation of 

particulate controls to collect an additional 70 percent of current particulate emissions, 562 tons 

per year from each unit. The cost for disposal ofthis ash is estimated at $40/ton. 

4.2.1.5 Remaining Useful Life 

The life of the Colstrip boilers is expected to exceed the study period and is projected to 

have no effect on the costing analyses for this facility. 

4.2.1.6 ViSibility Modeling 

The predicted visibility impacts from the present (base case) Colstrip particulate, SOz and 

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

Ib/MMBtu) are summarized in Table 4-5. 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 five Class I areas modeled. The highest of those visibility impacts among the five Class I 

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

particulate were at its controlled level (0.015 Ib/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. 

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

and Appendix B. 

4-14 
---

Table 4-5: Summary of Modeling Results for Particulate 

Max 98th 

Emissions (1) Percentile Deciview 

Control Option Prediction Difference 

Ib/MMBtu Ib/hr (deciviews) Relative to the 

Base Case 

Base Case 

0.047/0.058(f) 187.2/226.0 (f) 2.233 (2)

0.038 (c) 151.3/148.1 (c) 

NSPS Case 0.015 (f) 59.7/58.5(f) 2.21 (2) 0.042 (3)

0.038 (c) 151.3/148.1 (c) 

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

(2) The maximum deciview impact occurred at the UL Bend Class I area. 

(3) The maximum deciview difference occurred at the Theodore Roosevelt National Park. 

4.2.2 Sulfur Dioxide Controls 

The sub-bituminous coal fired boiler at Colstrip utilizes low-sulfur «I weight percent 

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

emissions for the Colstrip boilers are already low at 0.72 to 0.80 Ib/MMBtu of S02, maximum 

24-hr average, and are typically lower at 0040 Ib/MMBtu, which is representative of a typical 30­

day average emission rate considering the actual sulfur content of the fuel and the removal 

efficiency of the wet scrubbers. The Colstrip boilers are equipped with CEMS for S02 which 

were used to determine the baseline maximum 24-hr average S02 emission rates. 

4.2.2.1 Control Technologies 

Coal cleaning to reduce S02 emissions in addition to that performed prior to delivery to 

Colstrip would have no effect on S02 emissions. PRB coal already has low sulfur levels 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 Colstrip 

which was given no consideration. 

The controls evaluated to improve S02 control 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 S02 removals without impacting the particulate emissions with the existing scrubbers. 

In view of the alkaline nature of PRB coal, the inherent reaction between S02 and flyash is what 

accounts for an average S02 emission rate (from CEMS data) of 0040 Ib/MMBtu. PPL estimates 

4-15
 
that an increase in S02 removal can be attained by chemical addition using injection technologies 

(injection of lime). If this injection is limited to quantities that do not impact the operation ofthe 

current scrubbers, it is estimated that the current removal efficiency can be increased from 75% 

to about 88%, i.e., an additional 50% removal of S02 to a new emission rate of 0.20 IblMMBtu 

can be achieved before impacting the scrubber operation. 

As the amount of lime is increased, operation of the scrubbers will be affected. Scaling is 

projected to begin at levels of control exceeding 88 percent and become significant as removal 

efficiency increases and achieves an emission rate of 0.15 Ib/MMBtu. This will incur additional 

maintenance expenses and outages representing an additional cost of implementing this option. 

This could also require back-up scrubbers to reduce downtime for descaling. O&M time, 

however, will be greater despite the additional scrubbers. 

4.2.2.2 Cost O{S02 Controls 

PPL used experience from operation of the wet scrubbers on Units 3&4 at Colstrip to 

estimate the costs of lime injection and O&M costs for Colstrip Units 1&2. Three options were 

evaluated that are summarized in Table 4-6, see Appendix A, Tables A4-6(a), A4-6(b) and A4­

6(c) for complete details. Control options include the basic addition of lime injection equipment 

for Units 1&2, the cost of the lime, and minimal O&M costs. To attain the presumptive limit, 

the equipment cost doubles and there is additional expense for descaling and downtime. 

It is important to point out that the Colstrip boilers are currently equipped with wet 

scrubbers with a removal efficiency greater than 50% and thus the presumptive limit does not 

apply to Units 1&2. While the presumptive limit may be technically feasible, modifications to 

the current scrubbers to increase S02 removal incurs excessive O&M costs and may require 

backup scrubber modules at excessive incremental costs. 

4.2.2.3 ~ner£rV

The pressure drop of each of the venturi scrubbers is maintained in the range of 17 to 20 

inches of water column. The addition of lime to attain the 25% increase in S02 removal will be 

accompanied by little to no increase in pressure drop, but a small increase in pump power 

consumption. This is included in the cost analysis as an annual cost of additional operations and 

maintenance (O&M) expenses of an estimated $125,000 per year. 

4-16 
Table 4-6: PPL BART S02 Control Cost Summary (Per Unit) 

Option Description Total Annual 

Cost ($) 

Tons 

controlled Cost 

Effectiveness 

(CE) $/ton 

Incremental 

CE $/ton 

Lime Addition 

(88%control) $700,035 3209 $218 

Lime Addition 

(91 %control) $2,000,071 4011 $499 $1,621 

Added Scrubber Module $5,183,993 4011 $1,292 $5,590 

To achieve the higher removal of S02 of 70% over that currently attained, the additional 

sprays and pumps will increase O&M to an estimated $390,000. 

In summary, energy impacts of the addition oflime to the venturi scrubbers serving Units 

1&2 will be minimal and have been included in the cost analysis based on experience from 

Colstrip Units 3&4. 

4.2.2.4 Non-Air Quality Environmental Impacts 

The most significant impact of adding lime to the scrubbing equipment serving Units 

I&2 will be the scaling that will occur at high lime addition rates. This will appear as lost 

revenue from downtime for scrubber descaling. The third option listed in Table 4-6 with the 

added scrubber module will eliminate the downtime but not the O&M costs to descale one 

scrubber unit while other modules remain operational. 

4.2.2.5 Remaining Useful Life 

The life of the Colstrip boilers is expected to exceed the study period and is projected to 

have no effect on the costing analyses for this facility. 

4.2.2.6 Visibility Modeling 

The predicted visibility impacts from the present (base case) Colstrip S02, NOx and 

particulate emissions and for the alternative S02 control levels evaluated are summarized in 

Table 4-7. 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 five Class I areas 

modeled. For the modeled control alternatives, the emissions of S02 were at its controlled level 

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

4-17
 
--- ---

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 ofthe level of emissions reduction attained. 

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

and Appendix B. 

Table 4-7: Summary of Modeling Results for S02 

Max 98th 

Emissions Percentile Deciview Difference 

Control Option Prediction Relative Increment 

Ib/MMBtu (deciviews) to 

Base Case 

Ib/hr 

Base Case 0.72/0.80 2612.0/2828.0 2.233
 

Lime Injection
 

(50% reduction
 1433.4/1558.9 2.000 0.422 

from Present) 

Lime Injection
 

(63% Reduction from
 

0.36/0.40 0.422 

0.27/0.30 1075.111169.2 1.954 0.505 0.091 

Present) 

Add a Scrubber Vessel 0.15 597.3/584.6 1.832 0.651 0.146 

NOTE: The maximum deciview impacts and differences occur at either the UL Bend. 

Theodore Roosevelt or North Absaroka Class I areas. 

4.2.3 00 Controls 

The Colstrip boilers are tangentially fired units equipped with 10w-NOx burners. A 

review of CEMS data revealed that the maximum 24-hr NOx emission rates during the 2001 to 

2003 evaluation period were 0.45 Ib/MMBtu for Unit I and 0.53 Ib/MMBtu for Unit 2. While 

these values were used for BART modeling, a baseline value of 0.35 Ib/MMBtu was used as a 

typical NOx emission rate representative of a 30-day average for the BART cost analysis as 

applicable to either unit. This is maintained by operation of the current burners and c1osecoupled overfire air presently in operation at Colstrip. 

4-18 
4.2.3.1 Control Technologies 

PPL evaluated three control options for NOx reduction at Colstrip that include SOFA, 

SNCR, and SCR add-on controls. Adding SOFA and readjustment of the entire air distribution 

to the firebox is predicted to reduce NOx to 0.18 Ib/MMBtu. The addition of SNCR is predicted 

to produce little additional NOx reduction (to 0.16 Ib/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 Ib/MMBtu was analyzed. 

Reburning technology for application to Colstrip 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 Ib/MMBtu. 

4.2.3.2 Cost ofNOx Controls 

The costing analysis of the various control options for NOx reduction are summarized in 

Tables 4-8, see Appendix A, Tables A4-8(a), A4-8(b) and A4-8(c) for complete details. Table 4­

8 utilizes cost estimations for adding SOFA to the LNB technology, based on recent upgrades to 

the burners in Units 3&4 at Colstrip. Reduction from an emission rate of 0.35 Ib/MMBtu to 0.18 

Ib/MMBtu results in a CE of $451 /ton (in 2007 dollars) of NOx controlled. 

Table 4-8: PPL BART NOx Control Cost Summary (Per Unit) 

Option Description Total Annual 

Cost ($) 

Tons 

controlled Cost 

Effectiveness 

$/ton 

Incremental 

CE $/ton 

Separated Over-Fire Air $1,131,633 2509 $451 

SNCR $2,979,427 3049 $977 $3,424 

SCR $7,289,482 3209 $2,272 $26,938 

Cost for 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-452-02-00 I, January 2002). The cost analysis for application of SNCR is 

summarized in Table 4-8 which presents the CE calculations for reduction of boiler NOx 

emission rate ofO.35Ib/MMBtu to 0.18 Ib/MMBtu using SOFA. With the SNCR control option 

estimated to result in an emission rate of 0.16 IbIMMBtu, the CE of $977/ton for SNCR is not 

4-19
 
justifiable. Similarly, SCR controls, applied to a typical boiler emission rate of 0.35 Ib/MMBtu 

shows a CE value (Table 4-8) of $2,272/ton of NOx necessary to attain the presumptive limit of 

0.15 Ib/MMBtu. 

4.2.3.3 lSner&nV 

The NOx control alternatives in Table 4-8 each require additional energy. Each detailed 

cost calculation includes the electrical fan power consumption to run the SOFA fans, to pump 

urea solution, or to overcome SCR catalyst pressure drop. While these costs are a relatively 

small portion of the overall cost of control, they have been included in the analysis as part of the 

annualized cost for each option. 

4.2.3.4 Non-Air Quality lSnvironmental Impacts 

While SOFA may have impacts on particulate matter emissions with a slight change in 

LOl, this is of little impact for Colstrip boilers which use scrubbing for control of particulate and 

hence there is no salable ash. The addition of chemical reagents in SNCR and SCR controls adds 

equipment for its storage and use. The additional costs of chemicals and catalysts in the case of 

SCR have been included in the cost analysis. 

4.2.3.5 Remaining Useful Life 

The life of the Colstrip boilers is expected to exceed the study period and is projected to 

have no e~fect on the costing analyses for this facility. 

4.2.3.6 Visibility Modeling 

The predicted visibility impacts from the present (base case) Colstrip NOx, SOz and 

particulate emissions and for the alternative NOx 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 five Class 1 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 1areas. 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. 

4-20
 
--- ---

Table 4-9: Summary of Modeling Results for NOx 

Max 98th 

Emissions Percentile Deciview Difference 

Pollutant Control Option Prediction Relative to Increment 

IblMMBtu Ib/hr (deciviews) Base Case 

NOx Base Case 0.45/0.53 1798.0/1955.0 2.233 

SOFA 0.23/0.27 915.8/1052.2 1.781 0.573 0.573 

SNCR 0.21/0.24 836.2/935.3 1.713 0.638 0.068 

SCR 0.15 597.3/584.6 1.584 0.801 0.163 

NOTES: The maximum deciview impacts and differences occur at either the UL Bend 

or the Theodore Roosevelt Class I areas. 

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

and Appendix B. 

4.3 Visibility Modeling Procedures and Results 

Section 4.3.1 describes the general visibility modeling procedures and Section 4.3.2 

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

Appendix B. 

4.3.1 General Modeling Procedures 

The CALPUFF model was used to assess the impact of emissions from Colstrip BART 

eligible Units 1&2 on visibility in the five federal mandatory Class I areas within 300 km of the 

units, as identified in Section 2.3 and shown in Figure ES-l. CALPUFF (Scire et aI., 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/agm/308/bart.shtml) provided by 

EPA Region 8 in a February 28, 2007 letter to PPL identifying Colstrip Units 1&2 as subject to 

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

based on those data files with the following exceptions: 

4-21 
•	 Speciation of filterable and condensable particulate emissions was revised by PPL based 

on stack test data available during the modeling years (2001-2003) and AP-42 factors. 

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

The present (base case) S02, NOx and particulate emissions as modeled are presented in 

Tables 2-1 and Table 2-2. The particulate emissions presented include a breakdown of the 

particulate emissions by species and size fraction. Table 4-10 presents the emissions (and a 

summary of the modeling results as described below) for each of the control scenarios evaluated. 

These modeled S02, NOx and particulate emissions are based on the maximum actual daily 

operation of Units 1&2 during the three-year modeling period as described in Section 2.2. 

The present base case visibility impact of Colstrip Units 1&2 in each Class I area in terms 

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

modeled units' present emissions and the annual average background visibility level provided in 

the EPA/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 particulate emissions and the emissions control scenarios evaluated are 

presented and compared for each pollutant in Table 4-10. 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 five Class I areas evaluated. A summary of the results for each Class I area is 

presented in Appendix B. 

Under the present emissions case (base case), as presented in Table 4-10, the maximum 

of the annual 98th percentile Units I&2 daily visibility impacts is 2.233 deciviews and occurs at 

the UL Bend Class I area. The deciview impact for each of the control alternatives are also 

provided in the table. For each control alternative modeled, the emissions of the controlled 

4-22
 
--- ---

--- ---

--- ---

Table 4-10: Summary of Modeling Results 

Max 98th 

Emissions (1) Percentile Deciview Difference 

Pollutant Control Prediction Relative Increment 

Option IblMMBtu Ib/hr (deciviews) to 

Base Case 

2.233 (3) 

Lime Injection 

(50% 

S02 Base Case(2) 0.72/0.80 2612.0/2828.0

0.36/0.40 1433.4/1558.9 2.000 0.422 0.422 

reduction
 

from Present)
 

Lime Injection
 

(63%
 0.27/0.30 1075.1/1169.2 1.954 0.505 0.091 

Reduction 

from Present) 

Add a 0.15 597.3/584.6 1.832 0.651 0.146 

Scrubber
 

Vessel
 

NOx Base Case(2) 0.45/0.53 1798.0/1955.0 2.233 

SOFA 0.23/0.27 915.811052.2 1.781 0.573 0.573 

SNCR 0.21/0.24 836.2/935.3 1.713 0.638 0.068 

SCR 0.15 597.3/584.6 1.584 0.801 0.163 

PM Base Case(2) 0.047/0.058(f) 187.2/226.0 (f) 2.233

0.038 (c) 151.3/148.1 (c) 

NSPS Case 0.015 (f)) 59.7/58.5 (f) 2.213 0.042 (2) 0.042

0.038 (c) 151.3/148.1 (c) 

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

(2) The base case is the same for all three pollutants. 

(3) The maximum deciview impact of the base case occurred at the UL Bend Class I area. For other 

cases shown, the maximum impact or difference occurred at either the UL Bend or Theodore 

Roosevelt or North Absaroka Class I areas. 

4-23
 
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 the highest annual 98th 

percentile deciview impacts from each pollutant 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 

highest net change in visibility at any ofthe Class I areas evaluated. 

4-24
 
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. 

Colstrip Units 1&2 were determined to be BART-eligible under the Federal Regional 

Haze Rule by the EPA Region 8. The Colstrip are already relatively low particulate emitting 

units due to efficient operation and good combustion control. 

EPA's BART Guideline approach has been applied to Colstrip Units 1&2 to identify the 

"best system of continuous emission reduction" applicable to the units for filterable particulate 

control, S02 reduction and the control ofNOx• 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) and fabric filters (baghouses were evaluated for additional filterable 

particulate control. Mechanical collection and enhanced wet scrubbers were considered for 

particulate control but not further evaluated. Mechanical collection was not further evaluated 

because that technology is used as a pre-filter and does not perform well as a retrofit option. 

Enhancement to the wet scrubber was also not evaluated further as the existing particulate 

emissions level is already so low that there is little room for further improvement of the scrubber. 

Modified wet scrubbing by the existing venturi scrubbers to include lime injection and the 

addition of an additional scrubber vessel were evaluated for additional S02 control, 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 Colstrip Units 1&2 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 stack test data and there were a few modeling adjustments as described in Appendix B. 

Modeling was conducted to determine visibility impacts in the five mandatory Class I areas 

within 300 km of Colstrip. 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. 

5-1
 
For the modeling analyses maximum daily emissions during the modeling years (2001-2003) 

were used. 

The results of the cost and modeling analyses are presented in Tables 5-1 and 5-2. The 

highest modeled annual 98th percentile daily visibility impact of emissions from Units 1&2 based 

on present (base case) maximum actual load is predicted to occur in the in the UL Bend National 

Wildlife Refuge (NWR) Class I area and is 2.233 deciviews. 

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

0.042 deciview reduction, which is not visually discernable, would result from installation of 

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

Colstrip is not warranted. With respect to sulfur dioxide only a 0.422 deciview reduction is 

achieved with lime addition to improve S02 removal to 88 percent. This is below a level that is 

visually discernable. The incremental improvement through installation of any of the other 

technologies considered is 0.146 deciviews or less, which is not visibly discernable. Based upon 

the level of visibility improvement implementation of these control technologies are not 

warranted. And with respect to nitrogen oxides only a 0.573 deciview improvement results from 

implementation of SOFA. This is likely below a level that is visually discernable. The 

incremental improvements from controls beyond SOFA are 0.163 deciviews or less. Again, 

implementation of the controls is not warranted based upon the level of visibility improvement. 

5-2
 
Table 5-1: Current / NSPS / Control Options Cost Summary 

FOR THE PPL MONTANA, LLC, COLSTRIP UNITS 1 AND 2 (EACH UNIT) 

Particulate Matter Sulfur Dioxide NitrOOen Oxides 

Rate I Units Rate I Units I Rate I Units Control 

Current 

Emission rate 0.050 IblMMBtu 0.4 Ib/MMBtu 0.35 Ib/MMBtu COFA(2) 

BDT"'from I 

2006 NSPS 0.015 Ib/MMBtu 1.4 Ibs S02/MW out 1.0lb/MWout 

New Sources (0.15 Ib/MM Btu in 10.11 Ib/MM Btu in 

Cost Effeciveness Cales Cost Effeciveness Calcs 

Option Evaluated Option Evaluated CE(7) IncCE Option Evaluated CE' "' IncCE 

Rate Rate Rate 

Ib/MMBtu $Iton Ib/MMBtu $Iton $Iton Ib/MMBtu $lton $Iton 

Control Added ESP 0.015 $38,738 Present 0.4 $0 Present 0.35 

Options Added FF 0.015 $29,599 WS-FGD(4) 0.2 $218 SOFA 0.18 $451 

WS-FGD(5) 0.15 $499 $1,621 SNCR 0.16 $977 $3,424 

WS-FGD(6) 0.15 $1,292 $5,590 SCR 0.15 $2,286 $30,786 

Notes 1) Colstrip Unit 1 =0.047, Unit 2 =0.058Ib/MMBtu; 0.051b/MMBtu used as representative of each unit 

2) Low-NOx Burners with Close-Coupled Overfire Air 

3) BOT ="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 IblMMBtu input values listed in paren) 

4) Wet Scrubber-Flue Gas Desulfurization; actual emissions are 0.40 Ibs/MMBtu (per CEMS); 

adding lime to the scrubber will reduce emissions by 50% 

5) Similar to 3 but additional downtime due to scaling to attain a reduction to 0.15 Ibs/MMBtu 

6) Similar to (4), but more lime and an additional scrubber (per unit) necessary to reach the presumptive limit 

7) Control options considered separately; incremental cost of scrubbing options 

compares the relative additional removal to the baseline lime injected scrubber option 

8) Control options considered separately; incremental cost of SNCR 

and SCR reflect the relative cost of increased NOx removal 

Table 5-2: Modeled Visibility and Visibility Improvements 

Nitrogen Oxides 

Modeled 

Filterable Particulate Sulfur Dioxide 

Modeled Improvement (7) 

Rate (1)(2) 

Improvement (7) Modeled Improvement (7) 

Rate (1)(2 Prediction from
 

Option
 

Prediction (3) from Rate (1 )(2) Prediction from

(deciviews) Present Inc(6) 

Present 

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

0.04710.058 2.233 n/a n/a Present 0.72/0.80 2.233 n/a n/a Present 0.45/0.53 2.233 n/a n/a

0.23/0.27 1781 0.573 0.573 

Added FF 0.015 

New ESP 0.015 2.213 0.042 0.042 WS-FGD(4) 0.36/0.40 2.000 0.422 0.422 SOFA

0.21/0.24 1.713 0638 0.068 

WS-FGD(6) 

2.213 0.042 0.042 WS-FGD(5) 0.2710.30 1.954 0.505 0.091 SNCR

0.15 1.832 0.651 0.146 SCR 0.15 1.584 0.801 0.163

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

(2) If Unit 1 and Unit 2 emission rates are different, they are indicated as Unit l/Unit 2 rates. 

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

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

(5) See corresponding footnote in Table ES-l. 

(6) See corresponding footnote in Table ES-l. 

(7) Maximum improvements shown may occur at differeent Class I areas that the maximum prediction among all Class I areas. 

5-3
 
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. 68-0-98-026, 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


00 I, January 2002.
 

EPA, 2003, Guidance for Estimating Natural Visibility Conditions Under the Regional Haze
 

Rule, http://www.epa.gov/ttn/oarpg/tl/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/sagmtsd.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/ectOiIFiredBoiler.cfm
 

Scire, J, et al. 2000, A User's Guide for the CALPUFF Dispersion Model, Earth Tech, Inc.
 

January 2000.
 

6-4
 
APPENDIX A:
 

DETAILED COST CALCULATIONS
 

Table numbers in this appendix refer back to the summary tables in Section 4 of
 

the report (e.g., Table A4-3(a) in this appendix supports
 

Table 4-3 in Section 4 of this report).
 
Table A4-3(a): PPL BART Cost Analysis Electrostatic Precipitator Particulate Control 

330 Megawatt Coal Fired Steam Electric Unit
 

Dry-Bottom Combustion in Colstrip Unit 1 and Unit 2 (each)
 

Stack Exhaust Volumetric Flowrate, (acfm)
 

Maximum Gross Heat Input
 

Uncontrolled Filterable PM Emissions
 

ExhaustTemperature, (oF)
 

Steam Turbine Power Output (MW)
 

Hours of Operati on
 

Overall PM Reduction Efficiency, (%)
 

Uncontrolled PM Emissions, (Ib/hr)
 

Uncontrolled PM Emissions, (tons/yr)
 

Controlled PM Emissions, (ton/yr)
 

Annual Interest Rate, (%)
 

Depreciation Schedule, (yrs)
 

Capital Recovery Factor, CRF
 

o 1,233,748 

MMBtu/hr 3,982 

Ibs/MMBtu 0050 

T	 314 

MW	 330 

hr 8,059 

% 7000% 

199.1 

8023 

2407 

7 

11 

CRF 01334 

Unit Item 

Cost Item Suggested Factor Cost Cost 

Capital Equipment Cost (1988 EPRI Study)
 

Equipment Cost Total, (EC)
 

Retrofit Factor
 

Direct Capital Costs 

Purchased Equipment Costs 

ESP and Auxiliary Equipment 

Instrumentation 

Sales Tax 

Freight 

Purchased Equipment Costs, PEC 

Di rect Installation Costs 

Foundations and Supports 

Handling and Erection 

Electrical 

Piping 

Insulati on for Ductwork 

Painting 

Direct Installation Cost, DIC 

Site Preparati on 

Building 

Total Direct Capital Costs, DC 

Indirect Capital Costs 

Engineering
 

Construction and Field Expenses
 

Contractor Fees
 

Start-Up
 

Performance Test
 

Model Study
 

Contingencies
 

Total Indirect Capital Costs, IC 

Total Capital Costs, TCC .. DC + IC 

Capital Cost ($/KW)
 

EC (Adjusted by Cost Index Calcs)
 

New EqUipment Cost x 1.4
 

(Factors for ESPs from OAOPS Manual)
 

EC
 

0.10 EC
 

0.03 EC
 

0.05 EC
 

PEC =118 EC
 

0.04 PEC
 

050 PEC
 

008 PEC
 

001 PEC
 

002 PEC
 

002 PEC
 

DIC = 067 PEC
 

As Required, SP
 

As Required, BLDG
 

DC = 167 PEC + SP + BLDG 

0.20 PEC
 

020PEC
 

010 PEC
 

0.01 PEC
 

001 PEC
 

002 PEC
 

003 PEC
 

IC =057 PEC
 

TCC =224 PEC + SP + BLDG 

60
 

(2007 dollars)
 

(2007 dollars)
 

$19,800,000 

$31,337,501 

$43,872,502 

$43,872,502 

$4,387,250 

$1,316,175 

$2,193,625 

$51,769,552 

$2,070,782 

$25,884,776 

$4,141,564 

$517,696 

$1,035,391 

$1,035,391 

$34,685,600 

$0 

$0 

$34,685,600 

$10,353,910 

$10,353,910 

$5,176,955 

$517,696 

$517,696 

$1,035,391 

$1,553,087 

$29,508,645 

$115,963,796 
Table A4-3(a) continued 

Direct Annual Costs 

Utilities 

Fan Power1

) Fp =(181 x W 4 )(Q)(delta P)(hrs/yr) (01 in w.e. assumed) $143,975 

TR Set and Rapping Power2

) $0.08/kw hr $19,213 

Ash Disposal Costs Transportation not included $40/ton $22,463 

Operating Labor 

Operator 1.0 hrlshift $2286/hr $30,222 

Supervisor 15% of Operator $4,533 

Maintenance 

Labor $00825/tr Collector Area(J) 1987 $ $25,446 

2007 $ $41,440 

Matenals 001 PEC 1987 $ $517,696 

2007 $ $843,095 

Total Direct Annual Costs, DAC $1,104,942 

Indirect Annual Costs 

Overhead 60% of Operating Labor and $551,574 

Maintenance Costs 

Administrative 0.02TCC $2,319,276 

Propertry Taxes 001 TCC $1,159,638 

Insurance 001 TCC $1,159,638 

Capital Recovery CRF'TCC $15,459,047 

Total Indirect Annual Costs, lAC $20,649,173 

Total Annual Costs, TAC =DAC + lAC $21,754,115 

Cost Effectiveness (Slton pollutant removed) $38,738 

Cost data references 

Control Technologies for Hazardous Air Pollutants, Government Institutes, Inc., Office of Research and 

Development Center for Envi ronmental Research Informati on, June 1992 

OAQPS Cost Manual, Sixth Edition, EPA-452-02-001, January 2002 

Cost data assumptions 

Costs adjusted by cost indices for 2007 CI=118 049, 1987 CI=72.487, and 1988 CI=74.587 

1. ESP's have low pressure drop (01" wc. assumed) - Electricity cost at $008/kWHr is typical 

2. Transformer/Rectlfier and Rapping power is a function of the Specific Collecting Area (SCA) 

The OAQPS Control Cost Manual extimates P= 194 x 10-3 x SCA x hrs/yr as the total of electnfication and rapping 

electiciity power consumption in kWhrs/yr SCA is based on a SCA of 250 tr/1 ,000 ACFM 

and a migratIOn velOCity of 10 cm/sec characterisitc of coal fly-ash 

3. Collector area= 250 tr 11 ,000 ACFM x Q = 308,437 tr 
Table A4-3(b):
 

PPL BART Cost Analysis Pulse Jet - Fabric Filter for Additional Particulate Control
 

330 Megawatt Coal Fired Steam Electric Unit
 

Pulverized Coal· Dry Bottom Combustion in Colstrip Unit 1 or Unit 2 (each)
 

Stack Exhaust Volumetric Flowrate, (aclm) Q 

Maximum Gross Heat Input MMBtufhr 

Uncontrolled Filterable PM Emissions IbsfMMBtu 

ExhaustTemperature, (oF) T 

Steam Turbine Power Output (MW) MW 

Capacity Factor (hrsfyr at full load) hr 

Overall PM Reduction Efficiency, (%) % 

Uncontrolled PM Emissions, (Ibfhr) 

Uncontrolled PM Emissions, (tonsfyr) 

Controlled PM Emissions, (tonfyr) 

Annual Interest Rate, (%) 

Depreciation Schedule, (yrs) 

Capital Recovery Factor, CRF CRF 

1,233,748 

3,982 

0050 

314 

330 

8,059 

7000% 

199.1 

802.3 

240.7 

7 

11 

0.1334 

Cost Item 

Capital Equipment Cost (1988 EPRI Study) 

Equipment Cost Total, (EC) 

Direct Capital Costs 

Purchased Equipment Costs 

FF and Auxiliary Equipment 

Instrumentation 

Sales Tax 

Freight 

Purchased Equipment Costs, PEC 

Direct Installation Costs 

Foundations and Supports 

Handling and Erection 

Electrical 

Piping 

Insulation for Ductwork 

Painting 

Direct Installation Cost, DIC 

Site Preparation 

Building 

Total Direct Capital Costs, DC 

Indirect Capital Costs 

Engineering 

Construction and Field Expenses 

Contractor Fees 

Start-Up 

Performance Test 

Contingencies 

Total Indirect Capital Costs, IC 

Total Capital Costs, TCC .. DC + IC 

Suggested Factor 

Capital Cost ($fKW) 

EC (Adjusted by Cost Index Calcs) 

(Factors for FFs from OAQPS Manual) 

EC 

0.10EC 

003EC 

005EC 

PEC = 118 EC 

0.04 PEC 

050 PEC 

008 PEC 

001 PEC 

0.07 PEC 

0.04 PEC 

DIC =074 PEC 

As Required, SP 

As Required, BLDG 

DC = 1.74 PEC + SP + BLDG 

0.10 PEC 

020 PEC 

010 PEC 

0.01 PEC 

001 PEC 

0.03 PEC 

IC = 057 PEC 

TCC = 219 PEC + SP + BLDG 

Unit 

Cost 

50 

(2007 dollars) 

Item 

Cost 

$16,500,000 

$26,114,584 

$26,114,584 

$2,611,458 

$783,438 

$1,305,729 

$30,815,209 

$1,232,608 

$15,407,605 

$2,465,217 

$308,152 

$2,157,065 

$1,232,608 

$22,803,255 

$0 

$0 

$22,803,255 

$3,081,521 

$6,163,042 

$3,081,521 

$308,152 

$308,152 

$924,456 

$13,866,844 

$67,485,309 
Table A4-3(b) continued 

Direct Annual Costs 

Utilities 

Fan Power1) Fp =(1.81 x 10-4)(Q)(delta P)(hrs/yr) (7 in w. c. assumed) $1,007,825 

Compressed Air Cosf2

) 2 scfm/1 ,000 acfm (each minute) $0.25/1 ,000 scf $60,311 

Ash Disposal Costs Transportation not included $40/ton $22,463 

Operating Labor 

Operator 1.0 hrlshift $2286/hr $30,222 

Supervisor 15% of Operator $4,533 

Maintenance 

Labor $0.371 tt2 assumed $49,794 

Matenals (replacement bags) 15% of PEC assumed'3l $2,520,992 

Total Direct Annual Costs, DAC $3,696,140 

Indirect Annual Costs 

Overhead 60% of Operating Labor and $1,563,325 

Maintenance Costs 

Administrative 002TCC $1,349,706 

Propertry Taxes 001 TCC $674,853 

Insurance 001 TCC $674,853 

Capital Recovery CRF"TCC $8,663,440 

Total Indirect Annual Costs, lAC $12,926,177 

Total Annual Costs, TAC =DAC + lAC $16,622,318 

Cost Effectiveness (Slton pollutant removed) $29,599 

Cost data references 

Control Technologies for Hazardous Air Pollutants, Government Institutes, Inc, Office of Research and 

Development Center for Environmental Research Information, June 1992 

OAQPS Cost Manual, Sixth Edition, EPA-452-02-001, January 2002 

Cost data assurnptlons 

Costs adjusted by cost indices for 2007 CI=118 049, and 1988 CI=74.587 

1. FF's have highly van able pressure drops (70" wc assumed) - ElectnClty cost at $0.08/kWHr is typical
 

2 Compressed air cost is calculated as suggested by the OAQPS Control Cost Manual;
 

2 scfm of compressed air is assumed to be required for each 1,000 acfm per minute of operation
 

the cost of such compressed air is estimated to be $0.25 per 1,000 scfm
 

3. Bag replacement cost can vary WI dely from 15% to 100% of the PEC (15% assumed): 

the bag life is assumed to be 2 years and a capital recovery factor of 05454 has been applied to the annual 

bag replacement cost AlC ratio of 5 assumed. $03/tt2 labor cost assumed for bag replacement 
Table A4-6(a):
 

PPL BART Cost Analysis Wet Scrubbing Sulfur Dioxide Control (Option 1)
 

330 Megawatt Coal Fired Steam Electric Unit
 

Tangentially Fired Sub·bltumlnous Coal Combustion at Colstrip Unit 1 or Unit 2
 

Stack Exhaust Volumetric Flowrate, (acfm)
 

Maximum Gross Heat Input
 

Design Percent Load
 

Uncontrolled S02 Emissions (with low S coal)
 

ExhaustTemperature, (OF)
 

Steam Turbine Power Output (TMW)
 

Hours of Operation
 

Controlled S02 Emissions
 

Overall S02 Reduction Efficiency, (%)
 

Uncontrolled S02 Emissions, (lb/hr)
 

Uncontrolled S02 Emissions, (tons/yr)
 

Controlled S02 Emissions, (ton/yr)
 

Value of Power Generated
 

Annual Interest Rate, (%)
 

Depreciation Schedule (yrs)
 

Capital Recovery Factor, CRF
 

Q 

MMBtu/hr 

% 

Ibs/MMBtu 

T 

MW
 

hr
 

Ibs/MMBtu
 

% 

$/kW-hr 

CRF 

1,233,748 

3,982 

92 

0400 

314 

330 

8,059 

020 

5000 

15927 

64180 

32090 

008 

7 

11 

01334 

Cost Item 

Cost of Lime Injection Equlpmen(l) 

Equipment CostTotal, (EC) 

Total Capital Costs, TCC 

Direct Annual Costs, DCC 

Operations and Maintenance Costs 

Miscellaneous O&M Costs 

Total O&M Cost 

Indirect Annual Costs 

Capital Recovery 

Total Indirect Annual Costs, lAC 

Total Annual Costs, TAC" DAC + lAC 

Cost Effectiveness ($lton pollutant Removed) 

Suggested Factor 

Lime Cost 

$/year 

CRF"TCC 

Umt 

Cost 

(2007 dollars) 

Item 

Cost 

$1,500,000 

$1,500,000 

$375,000 

$125,000 

$500,000 

$200,035 

$200,035 

$700,035 

$218 

Cost data references 

1) Includes lime injection equipment based on the cost of similar equipment for units 3&4 
Table A4-6(b):
 

PPL BART Cost Analysis Wet Scrubbing Sulfur Dioxide Control (Option 2)
 

330 Megawatt Coal Fired Steam Electric Unit
 

Tangentially Fired Sub-bltuminous Coal Combustion at Colstrip Unit 1 or Unit 2
 

Stack Exhaust Volumetric Flowrate, (acfm)
 

Maximum Gross Heat Input
 

Design Percent Load
 

Uncontrolled S02 Emissions (with low S coal)
 

ExhaustTemperature, (oF)
 

Steam Turbine Power Output (TMW)
 

Hours of Operation
 

Controlled S02 Emissions
 

Uncontrolled S02 Emissions, (Ib/hr)
 

Uncontrolled S02 Emissions, (tons/yr)
 

Controlled S02 Emissions, (ton/yr)
 

Value of Power Generated
 

Annual Interest Rate, (%)
 

Depreciation Schedule (yrs)
 

Capital Recovery Factor, CRF
 

Q 

MMBtu/hr 

% 

IbsfMMBtu 

T 

MW
 

hr
 

IbsfMMBtu
 

$fkW-hr
 

CRF
 

1,233,748 

3,982 

92 

OAOO 

314 

330 

8,059 

015 

15927 

64180 

24068 

008 

7 

11 

01334 

Cost Item 

Cost of Lime Injection Equipment<') 

Basic lime Injection equipment 

Additional sprays and absorption pump 

Total Capital Costs, TCC 

Direct Annual Costs, DCC 

Operations and Maintenance Costs 

Additi onal fresh water 

35% increase in scrubber downtime 

35% Increase in scrubber O&M 

Miscellaneous O&M Costs 

Total O&M Cost 

Indirect Annual Costs 

Capital Recovery 

Total Indirect Annual Costs, lAC 

Total Annual Costs, TAC = DAC + lAC 

Cost Effectiveness ($lton pollutant removed) 

Suggested Factor 

Lime Cost 

(Lost revenue per unit) 

$fyear 

CRF'TCC 

Unit 

Cost 

(2007 dollars) 

Item 

Cost 

$1,500,000 

$1,500,000 

$3,000,000 

$550,000 

$10,000 

$525,000 

$390,000 

$125,000 

$1,600,000 

$400,071 

$400,07'1 

$2,000,07'1 

$499 

Cost data references 

1) InclUdes lime injection equipment based on the cost of similar equipment for units 3&4 
Table A4-6(c):
 

PPL BART Cost Analysis Wet Scrubbing Sulfur Dioxide Control (Option 3)
 

330 Megawatt Coal Fired Steam Electric Unit
 

Tangentially Fired Sub-bltumlnous Coal Combustion at Colstrip Unit 1 or Unit 2
 

Stack Exhaust Volumetric Flowrate, (acfm)
 

Maximum Gross Heat Input
 

Design Percent Load
 

Uncontrolled S02 Emissions (with low S coal)
 

ExhaustTemperature, (OF)
 

Steam Turbine Power Output (TMW)
 

Hours of Operati on
 

Controlled S02 Emissions
 

Uncontrolled S02 EmiSSions, (Ib/hr)
 

Uncontrolled S02 EmiSSions, (tons/yr)
 

Controlled S02 EmiSSions, (ton/yr)
 

Value of Power Generated
 

Annual Interest Rate, (%)
 

Depreciation Schedule (yrs)
 

Capital Recovery Factor, CRF
 

Q
 

MMBtu/hr
 

% 

Ibs/MMBtu
 

T
 

MW
 

hr
 

IbslMMBtu
 

$/kW-hr 

CRF 

1,233,748 

3,982 

92 

0400 

314 

330 

8,059 

015 

1592.7 

64180 

2406.8 

008 

7 

11 

0.1334 

Unit Item 

Cost Item Suggested Factor Cost Cost 

Cost of Lime Injection Equipment<l) 

BaSIC lime Injection equipment 

Additional sprays and absorption pump 

Spare scrubber vessel 

Total Capital Costs, TCC 

Direct Annual Costs, DCC 

Operations and Maintenance Costs
 

Additi onal fresh water
 

35% increase in scrubber O&M
 

Operations and Maintenance Costs
 

Miscellaneous O&M Costs
 

Total O&M Cost 

Indirect Annual Costs 

Capital Recovery 

Total Indirect Annual Costs, lAC 

Total Annual Costs, TAC =DAC + lAC 

Cost Effectiveness ($lton pollutant removed) 

(2007 dollars) 

Includes Lime Cost 

Descaling
 

Applicable O&M for Scrubber 2
 

$/year
 

CRF'TCC
 

$1,500,000 

$1,500,000 

$25,000,000 

$28,000,000 

$550,000 

$10,000 

$390,000 

$375,000 

$125,000 

$1,450,000 

$3,733,993 

$3,733,993 

$5,183,993 

$1,292 

Cost data references 

1) Includes lime Injection equipment based on the cost of similar eqUipment for units 3&4 
Table A4-8(a): PPL BART Cost Analysis Low NOx Burner Controls with SOFA 

330 Megawatt Coal Fired Steam Electric Unit
 

Tangentially Fired Sub-bituminous Coal Combustion in Colstrip Unit 1
 

Stack Exhaust Volumetric Flowrate, (acfm)
 

Maximum Gross Heat Input
 

Annual Capacity Factor (hrsfyr at full load)
 

Design Gross Heat Input
 

Uncontrolled NOx Emissions
 

ExhaustTemperature, (oF)
 

Steam Turbine Power Output (TMW)
 

Hours of Operation
 

Controlled NOx Emissions
 

Overall NOx Reduction Efficiency, (%)
 

Uncontrolled NOx Emissions, (Ibfhr)
 

Uncontrolled NOx Emissions, (tonsJyr)
 

Controlled NOx Emissions, (ton/yr)
 

Annual Interest Rate, (%)
 

Depreci ati on Schedule (yrs)
 

Capital Recovery Factor, CRF
 

Q 

MMBtufhr 

%. 

IbsfMMBtu 

T
 

MW
 

hr
 

IbsfMMBtu
 

% 

CRF 

1,233,748 

3,982 

92 

3,663 

0350 

314 

330 

8,059 

018 

48.57 

12821 

5166.5 

2657.1 

7 

11 

01334 

Cost Item 

Capital EqUipment Cost (2007) 

Equipment Cost Total, (EC) 

Total Capital Costs, TCC" DC + IC 

Total Direct Annual Costs, DAC 

Indirect Annual Costs 

Capital Recovery 

Total Indirect Annual Costs, lAC 

Total Annual Costs, TAC = DAC + lAC 

Cost Effectiveness ($lton pollutant removed) 

Suggested Factor 

Cost From Expenence at Units 3&4 

025 millfkW-hr 

CRF"TCC 

Unit 

Cost 

(2007 dollars) 

Item 

Cost 

$3,500,000 

$3,500,000 

$664,884 

$466,749 

$466,749 

$1,131,633 

$451 

Cost data references 

1) Cost of addl ng SOFA at Colstn p Units 3&4 
Table A4-8(b): SNCR Cost Analysis for Colstrip Unit 1 Maximum Heat Input (MM Btu/hr) Os 

Annual Average Heat Input (MMBtLJIhr) 0." 

NOx Emission Rate (Uncontrolled, IbsIMMBtu) 

Normalized Stolchometric Ratio (NSR) from Figure 1 8 (of EPA CCM) 

CapaCity Factor (hrslyr at full load) 

Overall NO, ReducDon Efficiency, (%) eff 

Uncontrolled NO, EmisSions, (Ib/he) 

Uncontrolled NO, Emissions, (tonslyr) 

Controlled NO, Emissions, (tonlyr) 

Annual Interest Rate, (%) 

Coal Cost ($IMMBtu) 

Water Cost ($/gallon) 

Electricity Cost ($II<Whr) 

Urea Cost lor a 50% Solution ($/gallon) 

SNCR Life, (yrs) 

Capital Recovery Factor, SNCR CRF(11 yr) 

Do'ign P,,,,,,,oto.. Suggomd Factor 

SNCR Capital Equipment Cost SNCR System, ,"eluding 

( Per Control Cost Manual, Equation 1 19) - Urea unloading skid 

Includes equIpment, instrumentation, sales tax - Centngugal pumps for unloading 

freight, math modeling, urea pumps. etc - VertIcal Insulated fiber-g18s5 urea storage tank 

- Pumps, heaters, valves, pressure, temp, flow 

instrumentation 

-Injection zone metenng for five zones 

- Water boosler pumps 

- Urea solution distribution module 

- Valved connectors for urea and atomIzing air 

- Flow mOnltonng for each Injector- wall and 

lor lance type '"Jectors 

- NOx monitor With feedback controls for urea 

Injection control 

- FoundaDonfor tank 

- EqUipment skids, 

- Platforms, strairvvftYs to access Injectors 

Urea consumpoon (as CON,H" Iblhr) (EPAIEPRI equation 1 15) 

Urea consumplion (as 50% aqueous solution, gaUhr) 

Water consumption (dilute to 10% aqueous solution, gallhr) 

Total Direct Cllpital Colli, TDCC (Soo coil roferonco, noto,) 

Indirect Coils 

Indirect Installation Colli 

General Facilities Cost o05xTDCC 

Engineering and Home OffICe Fees 010 xTDCC 

Process Contingency 005 xTDCC 

TotallndlleCI Installation Costs, TIIC 

Other Capttal Costs 

Project Contingency o15x(TDCC +TIIC) 

Preproduction Cost 0.02 x (TDCC + TIIC + Project ConDngency) 

Total Other Capital Costs, TOCC TDCC + TIIC + ProJ ConDngency 

Total Cllpillli Colli, TCC TDCC + TIIC + TOCC 

Direct Annual Costs 

Urea cost (50% aqueous solu~on) 50% solu~on @ $0 85/gal 

Dilution water COSl 

ElectriCity (added cost due to SNCR) CCM, Equa~on 1 23 

Added coal cost Increased coal consumption for vapOrization 

Annual maintenance cost 0015 xTCC 

Total Dllect Annual Costs, TDAC 

Indirect Annual Costs 

Administrative o02xTCC 

Propsnry Taxes 001 xTCC 

Insurance 001 xTCC 

Capital RecovelY - SNCR System CRFxTCC 

Total Indirect Annual Costs, TIAC 

Total Annual Coil', TAC· TDAC + TlAC 

Coil Effectlvonoss (Silon pollutant Romovod) 

Cost data references 

OAOPS Control Cost Manual (CCM), Sixth Edition, EPA-452-02-001, JanualY 2002 

TDCC Adjusted uSing CI=103 450 (2002) to CI=118 049 (2007) 

Equaoon 1 19 from OAQPS CCM DCC = $950 x O. x [2375 / a"f,n x [066 + 0 85 x eff] 

3,982 

3,663 

035 

150 

8,059 

543% 

1,394 

5,616 

2,567 

7% 

160 

00004 

008 

0.85 

11 

0133 

Valuo 

Cost taken
 

from EPA Cost
 

Manual 

Equation 1 19 

(See notes for equation) 

1.255 

265 

1,355 

$3,605,699 

$180,285 

360.570 

180285 

$721,140 

$649.026 

$99,517 

$748,543 

$6,075,382 

$1.812,057 

4,367 

$0 08!kw hr 61.346 

HV=900 Btullb 145,675 

76,131 

$2,099,575 

$101508 

50,754 

50,754 

676,837 

$879,852 

S2,979,427 

S9n 
Table A4-8(c): 

Maximum Heat Input (MMBtu/hr) 

Annual Average Heat Input (MMBtu/hr) 

NOx Emission Rate (Uncontrolled, Ibs/MMBtu) 

Normalized Stolchometric Ratio (NSR) 

Hours of Operation 

SCR NO, Reduction Efficiency, (%) 

Uncontrolled NO, Emissions, (Ib/hr) 

Uncontrolled NO, Emissions, (tons/yr) 

Controlled NO, Emissions, (ton/yr) 

Fw (wet scf/MMBtu) 

Exhaust Gas Velocity through SCR (ftimin) 

Percent O2 at SCR mlet 

Exhaust Gas Temp at SCR Inlet (deg F) 

Ammonia slip (ppmv) 

Ammonia Solution Concentration 

Sulfur content in coal 

Annual Interest Rate, (%) 

Electricity Cost ($/kWhr) 

Ammonia Cost for a 29% Solution ($/gallon) 

Catalyst Amortization Period, (yrs) 

SCR Amortization Period, (yrs) 

Capital Recovery Factor, Catalyst 

Capital Recovery Factor, SCR 

Design Parameters 

ACFM 

Catalyst Volume 

Base Volume 

w/NOx Efficiency Adjustment Factor 

w/lnlet NOx Adjustment Factor 

wiAmmonl a Sli p Adjustment factor 

w/Sulfur in Fuel Adjustment 

wITemperature Adjustment Factor 

Area Catalyst (A) 

Area of SCR (If) 

Length and Width of SCR (tt) 

N layers 

Number of Layers 

Height of a Layer (tt) (hl

• yo,) 

Number of Empty Layers 

SCR Height Per Industry Standards (tt) 

Ibs/hr ammonia as NH3 

gallons/hr of aqueous ammonia 

SCR Cost Analysis for Colstrip Unit 1 

08 

0.V9 

NOxin
 

from Figure 1.8 (of EPA CCM)
 

eff
 

T 

slip 

S 

CRF(3yr) 

CRF(11 yr) 

Suggested Factor 

281 X08
 

02869 + (1.058 x eff/100)
 

08524 + (03208 x NOxin)
 

12835 - (0.0567 x slip)
 

0.9636 + (0.0455 x S)
 

15.16 - (003937 xT) + 2.74 x 10-5 x T2
 

Based on veloicty of 960 fpm
 

1.15xA
 

Square Bed
 

Veal/31/A
 

(to nearest integer value)
 

(Veall N layersl A) + 1
 

(For catalyst management)
 

hscR =1'\a1a1 x (7 + hl• yo,) + 9
 

Noxin x 0,v9 x NSR x eff x 17/46
 

Total Direct Capital Costs, TDCC (See cost references notes) 

3,982 

3,663 

0.35 

1.50 

8,059 

571% 

1,394 

5,616 

2,407 

10,640 

960 

4% 

700 

5 

29% 

1% 

7% 

008 

0.85 

3 

11 

0.381 

0.133 

Value 

1,243,803 

11,189 

0891471429 9,975 

0.96468 9,622 

1000 9,622 

10091 9,710 

1027 9,972 

1,296 

1.15 1,490 

38.60 

248 

2.0 

4.85 

1 

44.5 

407 

187 

$17,961,234 
Table A4-8(c) continued 

Indirect Costs 

Indirect Installation Costs 

General Facilities Cost 

Engineering and Home Office Fees 

Process Contingency 

Total Indirect Installation Costs, TIIC 

005xTDCC 

010xTDCC 

005xTDCC 

Other Capital Costs 

Project Conti ngency 

Preproduction Cost 

Total Other Capital Costs, TOCC 

015 x (TDCC + Tile) 

0.02 x (TDCC + TIIC + Project Contingency) 

TDCC + TIIC + Pro) Contingency 

Total Capital Costs, TCC TDCC + TIiC + TOCC 

Direct Annual Costs 

Annual Ammonia Cost 

Electricity (Added Cost due to SCR)1 

Annual Maintennace Cost 

Total Direct Annual Costs, TDAC 

CCM, Equation 2.48 

0015xTCC 

$0 85/gal 

$0.08/kw-hr 

Indirect Annual Costs 

Administrative 

Propertry Taxes 

Insurance 

Capital Recovery - Catalysr 

Capital Recovery - SCR System Less Catatyst 

Total Indirect Annual Costs, TIAC 

002 xTCC 

0.01 xTCC 

001 xTCC 

CRF (3 yr) x Catalyst Cost 

CRF(11 yr) x (TCC - Catalyst Cost) 

Total Annual Costs, TAC =TDAC + T1AC 

Cost Effectiveness ($lton pollutant Removed) 

Cost data references: 

OAQPS Control Cost Manual (CCM), Sixth Edition, EPA-452-02-001, January 2002 

TDCC Adjusted USing CI=1 03.450 (2002) to CI=118049 (2007) 

Notes 

1. Electricity cost includes ammonia vaporization heaters 

2. Assumes replacement of all catalyst at the end of 3 years with replacement catalyst @ $290 cubic foot 

$898,062 

1,796,123 

898,062 

$3,592,247 

$3,233,022 

$495,730 

$3,728,752 

$25,282,233 

$1,283,617 

527,480 

379,233 

$2,190,330 

$505,645 

252,822 

252,822 

1,101,953 

2,985,909 

$5,099,151 

$7,289,482 

$2,272 
APPENDIXB
 

CALPUFF APPLICATION FOR BART
 

ASSESSMENTS AT PPL COLSTRIP UNITS
 

1&2
 
CALPUFF Application for BART Assessments at 

PPL Facility Colstrip Units 1&2 in Montana for 

the UL Bend, Theodore Roosevelt, Washakie, 

North Absaroka, and Yellowstone 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 
TABLE OF CONTENTS
 

1.0 INTRODUCTION I
 

2.0 SOLIRCE 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 26
 
LIST OF FIGURES
 

Figure 2-1. 

Figure 3-1. 

Figure 3-2. 

Figure 3-3. 

Figure 3-4. 

Figure 4-1. 

Aerial photo ofthe PPL Colstrip facility 4 

Terrain contours (m MSL) at 2 km resolution for the 780 km by 570 km 

CALMET and CALPUFF computational domains. The Class I areas and 

the Colstrip facility are also shown. 8 

Dominant land use categories at 2 km resolution on the CALMET and 

CALPUFF modeling domains. Class I areas and the location of Colstrip 

PPL are also shown. 10 

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 

Locations of ozone monitoring stations used in the CALPUFF modeling. 15 

Locations of receptors at UL Bend, North Absaroka, Theodore Roosevelt, 

Washakie and Yellowstone Class I areas. 19 

11 
LIST OF TABLES
 

Table 2-1. Colstrip: Source Parameters and Emission Rates - Base Case 5
 

Table 2-2. Colstrip: Particle Speciation - Base Case 5
 

Table 2-3. Colstrip: Emissions for Base Case and Control Alternatives 6
 

Table 3-3. Meteorological Data Sources and Parameters Available I I
 

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 (S02 Control Efficiency
 

Increased to 88%) 24
 

Table 5-3. Summary of Visibility Results for Alternative 2 (S02 Control Efficiency
 

Increased to 91 %) 24
 

Table 5-4. Summary of Visibility Results for Alternative 3 (S02 Reduced to
 

0.15 Ib/MMBtu) 24
 

Table 5-5. Summary of Visibility Results for Alternative 4 (NOx Reduced with
 

SOFA) 25
 

Table 5-6. Summary of Visibility Results for Alternative 5 (NOx Reduced with
 

SNCR) 25
 

Table 5-7. Summary of Visibility Results for Alternative 6 (NOx Reduced to
 

0.15 Ib/MMBtu with SCR) 25
 

Table 5-8. Summary of Visibility Results for Alternative 7 (Filterable PM Reduced to
 

0.015 Ib/MMBtu) 25
 

III 
1.0 INTRODUCTION 

TRC Environmental Corporation has conducted a Best Available Retrofit Technology (BART) 

analysis for Units 1&2 at PPL Montana, LLC's Colstrip 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. 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.edulaqm/308/bart.shtml) provided by EPA 

Region 8 in a February 28, 2007 letter to PPL identifying the Colstrip units as subject to BART 

and providing preliminary modeling results. In this report, results are presented for' Units 1&2 of 

the Colstrip PPL plant. Colstrip PPL plant is located east 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 (S02), nitrogen 

oxides (NOx) and primary particulate matter (PM) emissions (including primary sulfuric acid, 

H2S04, emissions), at those Class I areas that are located within 300 km from the plant. A total of 

five Class r areas are located within this radius: North Absaroka WA, Theodore Roosevelt 

National Park (NP), UL Bend WA, Washakie WA and Yellowstone NP. 

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 

Introduction 
effects. The CALMET and CALPUFF non-steady-state models (Scire et aI., 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 

fifth generation Penn StatelNCAR (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 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. 

2 Introduction 
2.0 SOURCE DESCRIPTION
 

The Colstrip Power Plant is located in Colstrip, Montana. The BART-eligible sources consist of 

two tangential coal-fired units, Units 1&2. Figure 2-1 shows the aerial photo of the Colstrip 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, 

AP-42 emission factors and current guidance of the National Park Service. The particulate matter 

was modeled using the geometric mass mean diameter of 0.4 micrometers (11m) and geometric 

standard deviation of 2 Ilm. 

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 

emission 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. 

3 Source Description 
Figure 2-1. Aerial photo ofthe PPL Colstrip facility 

4 Source Description 
Table 

I 

2-1 Colstrip: Source Parameters and Emission Rates - Base Case 

Stack 

Lambert Conformal 

Coordinatesl Stack 

Height 

Base 

Elevation Diameter Gas Exit 

Velocity 

Stack 

Gas Exit 

Temp. 

SOz 

Emissions 

HzS04 

Emissionsz NO. 

Emissions 

10# 

LCC East LCC North 

km km m m m m/s K Ib/hr Ib/hr Ib/hr 

Unit I 823.887 185.596 152.4 988.0 5.0292 29.7 366.3 2612.0 121.05 1798.0 

Unit 2 823.930 185.598 152.4 988.0 5.0292 28.44 367.3 2828.0 118.47 1955.0 

I The LCC projection is based on standard parallels of45.0 Nand 49.0 N. an origin latitude and longitude of 44.25 Nand 109.5 W. false easting is 600 km, a

2 H2S04 emissions are entered in CALPUFF as S04 i.e., weighted by ratio of molecular weights (96/98).
 

3 PM IO emission rate includes filterable and condensable emissions. The condensable component includes H2S04 emissions.
 

Table 2-2 Colstrip: Particle Speciation - Base Case 

Stack 10 # Particle speciation Condensable Filterable 

filterable PM IO condensable PM IO 

organic HzS04 condensable (OC) 

M1=0.48, SD1=2.0 Jim 

COARSE Soil 

M 1

=0.48, SD1=2.0 Jim 

% 0/0 Ib/hr Ib/hr Ib/hr Ib/hr 

Unit I 55.3 44.7 30.26 121.05 53.47 128.73 

Unit 2 60.4 39.6 29.62 118.47 64.58 155.48 

M and SO stand tor Geometric Mass Mean Diameter and Geometric Standard Deviation. These are the parameters used to calculate the particle size distribu

5 
Table 2-3 Colstrip: Emissions for Base Case and Control Alternatives 

Stack 

10# Condensable Filterable 

S02 

Emissions 

NO. 

Emissions 

PM IO 

Emissions3 

organic 

condensable 

(OC) 

H2SO4 COARSE Soil 

Elemental 

Carbon 

(EC) 

Ib/hr Ib/hr Ib/hr Ib/hr Ib/hr Ib/hr Ib/hr Ib/hr 

Unit I Base Case 2612.0 1798.0 338.45 30.26 121.05 53.47 128.73 4.95 

Control All. I 1433.4 1798.0 338.45 30.26 121.05 53.47 128.73 4.95 

Control All. 2 1075.1 1798.0 338.45 30.26 121.05 53.47 128.73 4.95 

Control All. 3 597.3 1798.0 338.45 30.26 121.05 53.47 128.73 4.95 

Control All. 4 2612.0 915.8 338.45 30.26 121.05 53.47 128.73 4.95 

Control Alt. 5 2612.0 836.2 338.45 30.26 121.05 53.47 128.73 4.95 

Control Alt. 6 2612.0 597.3 338.45 30.26 121.05 53.47 128.73 4.95 

Control All. 7 2612.0 1798.0 211.03 30.26 121.05 17.06 41.08 1.58 

Unit2 Base Case 2828.0 1955.0 374.13 

374.13 

374.13 

374.13 

374.13 

29.62 118.47 64.58 155.48 5.97 

Control All. 1 1558.9 1955.0 29.62 118.47 64.58 155.48 5.97 

Control All. 2 1169.2 1955.0 29.62 118.47 64.58 155.48 5.97 

Control All. 3 584.6 1955.0 29.62 118.47 64.58 155.48 5.97 

Control Alt. 4 2828.0 1052.2 29.62 118.47 64.58 155.48 5.97 

Control All. 5 2828.0 935.3 374.13 

374.13 

206.54 

29.62 118.47 64.58 155.48 5.97 

Control All. 6 2828.0 584.6 29.62 118.47 64.58 155.48 5.97 

Control All. 7 2828.0 1955.0 29.62 118.47 16.70 40.21 1.54 

NOTES: Control Alt 1 = S02 control efficiency increased to 88% with lime injection. 

Control Alt 2 = S02 control efficiency increased to 91 % with lime injection. 

Control Alt 3 = S02 reduced to 0.15 Ib/MMBtu by adding an additional scrubber vessel. 

Control Alt 4 = NOx reduction with SOFA. 

Control Alt 5 =NOx reduction with SNCR. 

Control Alt 6 = NOx reduction to 0.15 Ib/MMBtu with SCR. 

Control Alt 7 = Filterable PM reduced to 0.015 Ib/MMBtu. 

6 
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 I degree by I degree blocks of latitude and longitude. The I-degree DEMs are produced by the 

Defense Mapping Agency using cartographic and photographic sources. USGS I:250,000 scale 

topographic maps are the primary source of I-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 780 km by 570 km (Figure 3-1). 

It includes Colstrip and all Class I areas within 300 km from it. These Class I areas are: North Absaroka 

WA, Theodore Roosevelt NP, UL Bend WA, Washakie WA and Yellowstone NP. The domain also 

includes the other PPL Bart-eligible facility in Montana (Corette) 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 represent 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 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 Montana Protocol was 6 km. In the current analysis, 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 the modeling domain much smaller in size than the originally proposed. 

Hence, better horizontal resolution of 2 km was possible to achieve with still using the reasonable 

number of grid cells. In addition, domain was extended to the south to include 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 locations of 

Colstrip and a circle with 300-km radius around the facility. North Absaroka, Theodore Roosevelt, 

7 Geophysical and Meteorological Data 
450 

400 

350 

Terrain 300 (meters) 

4500 

3900 

250 3700 NO 3500 

3300 

3100 

i 200 2900 

OJ 2700

2500 

2300 !

.. 150 2100 

u 1900

1700 

1500 

1300 100 1100 

900 

700 

500 50 300 

100 

-1 

-50 

'W I;~~r~> '-----,__--+-___ 

350 400 450 500 550 600 650 700 750 800 850 900 950 1000 

LCC. (km), WGS-34 

Map pro,lectlon: Lee, WGS~

FN5' .. 600 km, Fnorth .. 0 11m 

PPL, Montana	 LATo" 44.25N, LANo" 109.5W
 

LAT1 .. 45 N, LAT2" 49 N
 

Figure 3-1. Terrain contours (m MSL) at 2 km resolution for the 780 km by 570 km CALMET and 

CALPUFF computational domains. The Class I areas and the Colstrip facility are also shown. 

1050 1100 

8	 Geophysical and Meteorological Data 
UL Bend, Washakie and Yellowstone Class I areas are within the 300 km from the Colstrip. These five 

Class I areas were included in the BART visibility analysis for the Colstrip 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 of200 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=l, 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.OAT has been recreated using Integrated Surface Hourly Weather Observations (ISHWO) data 

base. Eight stations in 200 I and 5 from 2002 and 2003 from the original SURF.OAT file were not found 

in any of ISHWO or METAR databases. The records from theses stations were extracted from the 

original SURF.OAT files and added to the new ones (first eight stations listed in Table 3-4). 

9 Geophysical and Meteorological Data 
100 

95 Snow/Ice 

90 

85 Tundra 

80 

75 Barren 

70 

65 Wetland 

60 

55 water 

50 

45 Forest 

40 

35 Range 

30 

25 Agriculture 

20 

15 Urban/Buill-Up 

10 

'" 

t 

'I 

.. ," 

40(1 .' 350 I. • 

300 

250 

... 

'I' 200 III 

" :l: 

!.. 150 , U 

U

... 

100 

50 

350 400 450 500 550 600 650 700 750 800 850 900 950 1000 '050 1100 

LCC. (km), WGS-ll4 

Map pro;ection: lee, WGS.a4
 

Feul- 800 km, Fnorttl '"' 0 kin
 PPL, Montana LATo '" 44.26N, LANa. 109.&W
 

LAT1 • 45 N.LAn" 4' N
 

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 Colstrip PPL are also shown. 

10 Geophysical and Meteorological Data 
Table 3-3 Meteorological Data Sources and Parameters Available 

Type of Dataset Frequency Source Parameters 

Surface observations Hourly NWS 

Modeled Profiles 

MM5 for 200 I, 2002 

and 2003 

Hourly WRAP 

Wind speed, wind 

direction, temperature, 

ceiling height, cloud 

cover, relative humidity, 

surface pressure, 

precipitation type 

Hourly, gridded fields of 

winds, temperature, 

pressure, and humidity and 

liquid water content on 

36 km grid for 2003, 2004 

and 2005. 

II Geophysical and Meteorological Data 
Table 3-4........................................................................................... NWS Hourly Surface Stations
 

WMO WBAN Station Name State Latitude Longitude CALL ID LCCXI LCCyl 

(deg.) (deg.) (km) (km) 

Colstrip region MT 46.90 -103.40 TH28 824.377 178.618 

Border ofWY & MT close to KSHR MT 4510 -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 M039 828.340 159.976 

Colstrip region 1 MT 45.60 -106.50 GA38 836.341 154.721 

Colstrip region 1 MT 45.70 -106.60 BA37 831.370 162.314 

718620 99999 ESTEVAN AIRPORT SA 49.22 -10297 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 KRlW 685.694 -132.898 

725776 99999 JACKSON HOLE (A WOS) WY 43.60 -110.73 KJAC 500.578 -71.50 I 

725780 24156 POCATELLO REGIONAL AP ID 42.92 -112.57 KPIH 348939 -143.020 

725785 24145 IDAHO FALLS FANNING FIEL ID 43.52 -11207 KIDA 392.002 -77.767 

725865 99999 HAILEY/FRIEDMAN MEM ID 43.50 -114.30 KSUN 211558 -71.499 

725867 24133 BURLEY MUNICIPAL ARPT ID 42.53 -113.77 KBYI 248.522 -181773 

726514 99999 CUSTER (RAMOS) SO 43.73 -103.62 KCUT 1073.773 -40.031 

726516 99999 PHILIP ARPT SO 44.05 -10160 KPHP 1232.468 9.686 

726517 99999 PINE RIDGE SO 43.03 -102.52 KIEN 1169.119 -110.323 

726539 99999 FAITH SO 45.03 -102.02 KD07 1188.561 114823 

726620 24090 RAPID CITY REGIONAL ARPT SO 44.05 -103.05 KRAP 1116.674 -0.951 

726625 99999 ELLSWORTH AFB SO 44.15 -103.10 KRCA 1111770 9.802 

726627 99999 BUFFALO (AMOS) SO 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 526875 33.779 

726665 24062 WORLAND MUNICIPAL WY 43.97 -107.95 KWRL 724.471 -29.90 I 

726667 99999 SOUTH BIG HORN CO WY 44.52 -108.08 KGEY 712.923 31039 

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 4705 -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 193375 

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 161596 

726818 99999 REXBURG ID 43.83 -11180 KRXE 414.859 -43982 

726865 99999 SALMON/LEMHI (AWOS) 10 45.12 -113.88 KSMN 255576 106.332 

727584 99999 HETTINGER NO 46.02 -102.65 KHEI 1129.513 219.869 

727645 24012 DICKINSON MUNICIPAL AP NO 46.80 -102.80 KDIK 1110.543 305.206 

727670 94014 WILLISTON SLOULIN INTL A NO 48.20 -103.65 KISN 1034.294 455151 

727675 99999 MINOT AFB NO 48.42 -101J5 KMIB 1201973 494.726 

727676 24013 MINOT FAA AP NO 48.27 -101.28 KMOT 1208.871 478.684 

727677 99999 GARRISON (AMOS) NO 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 -10558 KOLF 891719 4351 I I 

727687 99999 SIDNEY-RICHLAND MT 47.70 -104.20 KSDY 997.286 396.803 

727720 24144 HELENA REGIONAL AIRPORT MT 46.60 -11197 KHLN 410886 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 -111J8 KGTF 458.369 359.499 

727770 94012 HAVRE CITY-COUNTY AP MT 48.55 -10977 KHVR 580.071 477.866 

727790 24146 KALISPELL GLACIER PK INT MT 4832 -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 

The Lambert Conformal Conic (LCC) projection is based on standard parallels of 45.0 Nand 49.0 N, an origin latitude and 

longitude of 44.25 Nand 109.5 W, false easting is 600 km, and datum WGS-84. 

Available for year 200 I only 

12 Geophysical and Meteorological Data 

2 
KaTF . 

GRn 

KN60 . 

KD07 . K<WX . KBZN

8019 •

KHLN . 

1<012 

I Gat."Of~YMalhIl

, 

, 

,BU20 

, 

, 

I 

, 

KBTM . 

32 

SA 2 

KSM. 

KMSO . 

MI14 

400 

350 

300 

250 

! 200 

150 

100 

PPL, Montana 

MM5 grid points 

• Surface mel stations 

II 

en 

.. 

" -' " 

50 

10 KRCA KAA

RAP •

-50 KSUN . -100 

• • KCPR KLNII'34 KDGW MOOELING DOMAIN .1SOl KPIH

POlS CAS8 • . LAN3 • Mllp proteCtion: lCC, WGS.a4 I KaYI KBPI Fe..' • 800 kin, Fnorth • 0 km 

LATo· 44.2!N, LANo. 109.5W

-200~ - - "l - - : - - r - - ,- - - 1- - - 1-- - -1- - -~ - - --, -- - "l - - T - - T - - r - - 1- - - 1- - -, - - -I - - --, - - "l - - T - - T - ­ LAT1-45N,LAT2-4I9N 

150 200 250 300 350 400 450 soa 550 600 650 700 750 800 850 900 950 1000 1050 1100 1150 1200
 

LCC. (km), WGS-84
 

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 Geophysical and Meteorological Data 
3.4 Air Quality Monitoring Data 

CALPUFF uses hourly ozone concentration measurements in the chemical transformation calculations 

(S02 to S04, NOx to HNOiN03). The ambient ozone measurements were used in determining S02 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.OAT). The original OZONE.OAT 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, NO. The MOEQ 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. 

14 Geophysical and Meteorological Data 
550 L I .L 1 J. 1__ - J-- L - - _I -- - - .L - - - 1- - - J. - - _ 1 .J L - - _I - - - .L~ .1 - - - 1- - ­

500 PPL, Montana -	 \-~ GL~~g~'oo,

.50 

MODELING OOIMlN 

400 

350 

300 MT 

250 NO 

;;

:g 200 

! 

so 

100 

WY \

t

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.'"~

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.& AIRS 

.'50.	 PND16~ MapprqKtIon:LCC,WGs.-&I

flll.lst.600 kill, fnorth .0 kill 

-200 - - - r - - -1- - T - - - -1- - - I	 - - - - - - -. - - r - - -I - - - T 1 p __ ~~~~~~~a.A~~~~09'~r - - -I - - - T - - -1- - - ,. - - - ,- -­

~ ~ ~ 350 450 6~ ~ ~ 850 ~ ~ 1~ 1~ 1100 1150 1200 

LCCll. (km), WGS~

•
 

·50 

1602~0101

50 

Figure 3-4. Locations of ozone monitoring stations used in the CALPUFF modeling. 

15	 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 

16 Geophysical and Meteorological Data 
4.0 AIR QUALITY MODELING METHODOLOGY 

4.1 Model Selection 

The CALPUFF modeling system (Scire et aI., 2000a,b) was used in the Colstrip BART analysis at UL 

Bend, North Absaroka, Theodore Roosevelt, Washakie and Yellowstone Class I areas. The EPAapproved version ofCALPUFF 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 Colstrip 

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=I), indicating the selection of the mixing height 

method (lMlXH=-1 using the Maul-Carson method over land and the OCD method over water; 

lCOARE=O using the OCD method for turbulence and fluxes over water; and THRESHL=O.O 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 I wind field, CAL MET 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 ofTERRAD 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 I 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 I wind field to produce a final wind field. Each 

observation site influences the final wind field within a radius of influence (parameters RMAXI at the 

surface and RMAX2 aloft). Observations and Step I field are weighted by means of parameters RI at 

17 Air Quality Modeling Methodology 
the surface and R2 aloft: at a distance R I from an observation site, the Step I wind field and the surface 

observations are weighted equally. As recommended in the Montana Protocol, RMAXI and RMAX2 

were set to 40 km and 100 km, while R I 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, 200 1,2002 and 2003. 

The receptor locations along with receptor elevations were available from the National Park Service 

(NPS). The distribution of the receptors within UL Bend, Theodore Roosevelt, Washakie, North 

Absaroka, and Yellowstone are shown in Figure 4-1. In the screening modeling, the domain did not 

include the southernmost part of the Yellowstone NP 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 O"y 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. 

18 Air Quality Modeling Methodology 
380 

100 L , , , , , 

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L6!t. (km WGS-34 

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1030 1040 1050 1050 1070 1080 1090 705 710 715 720 725 

LCC. (km), WGS,84	 LCC. (km), WGS·84 

Fig 

ure 

4-1. 

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730 

19	 Air Quality Modeling Methodology 

l 
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 o 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: S02, S04, NOx, NO), 

HNO), and four subcategories of PM 10, (PMF, PMC, EC, and SOA). Of these nine species, seven are 

emitted by the Colstrip sources: S02, S04, NOx and four subcategories of PM IO• The chemical 

mechanism computes transformation rates of S02 to S04 and NOx to NOiHNO). 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. 

To allow for flexibility, the two units were modeled individually and their source contributions were 

summed in postprocessing steps. 

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)2S04] + 3f(RH)[NH4N03] + 

4[OC] + I[Soil] + 0.6[Coarse Mass] +lO[EC] + bray 

The concentrations, in square brackets, are in ~g/m) and bex, is in units ofMmol • The Rayleigh scattering 

term (bray) has a default value of 10 Mmol , as recommended in EPA Guidance for Estimating Natural 

Visibility Conditions Under the Regional Haze Program (U.S. EPA, 2003b). Note that organic carbon 

(oq, 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 ~m and geometric standard deviation of 2 11m. 

The haze index (HI) is calculated from the extinction coefficient via the following formula: 

HI = 10 In(bext/lO) 

20 Air Quality Modeling Methodology 
where HI is in units of deciviews (dv) and bext is in Mm-I

. The impact of a source is determined by 

comparing HI for estimated natural background conditions with the impact ofthe source and without the 

impact of the source. 

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 five 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- I. 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. 

21 Air Quality Modeling Methodology 
Table 4-1 Summary of Background Natural Visibility Conditions 

Average Natural Dry Extinction Efficiency 

Class I area Concentration West (lIglmJ

) Coefficient (mJ/g) 

Ammonium sulfate
 

Ammonium nitrate
 

Organic carbon mass
 

Elemental carbon
 

Soil
 

Coarse Mass
 

0.12 

0.\0 

0.47 

0.02 

0.50 

3.00 

3 

3 

4 

10 

0.6 

Source: Guidancejor 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 

UL Bend WA 2.6 2.4 2.4 2.3 2.2 2.\ 1.9 1.8 1.9 2.2 2.6 2.6 

Theodore Roosevelt NP 2.9 2.8 2.8 2.4 2.4 2.5 2.4 2.2 2.2 2.3 3.0 3.0 

Washakie WA 2.4 2.2 2.2 2.\ 2.\ 1.9 1.6 1.5 1.8 2.0 2.3 2.4 

North Absaroka WA 2.4 2.2 2.2 2.\ 2.\ 1.9 1.6 1.5 1.8 2.0 2.3 2.4 

Yellowstone NP 2.5 2.3 2.2 2.\ 2.1 1.9 1.7 1.6 1.8 2.\ 2.4 2.5 

Source: Guidancejor Estimating Natural Visibility Conditions Under the Regional Haze Rule (2003), Appendix A 

22 Air Quality Modeling Methodology 
5.0 RESULTS
 

The change in light extinction relative to the natural background due to S02, NOx and PM IO from 

Colstrip Units 1&2 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 units on visibility at the five 

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 five 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. 

23 Air Quality Modeling Afethodology 
Table 5-1.. Summary of Visibility Results for Base Case 

Class I Area Minimum 

Distance (km) 

2001 2002 2003 

98th percentile delta-deciview 

UL Bend 200 1.880 2.124 2.233 

North Absaroka WA 254 0.649 1.569 0.981 

Theodore Roosevelt NP 260 1.781 2.186 1.749 

Washakie WA 278 1.202 1.152 0.642 

Yellowstone NP 281 0.783 1.037 0.571 

Table 5-2.Summary of Visibility Results for Alternative 1 (S02 Control Efficiency Increased to 88%) 

Class I Area Minimum 

Distance (km) 

2001 2002 2003 

98th percentile delta-deciview 

UL Bend 200 1.537 1.524 1.811 

North Absaroka WA 254 0.480 1.263 0.795 

Theodore Roosevelt NP 260 1.553 2.000 1.466 

Washakie WA 278 1.025 0.932 0.632 

Yellowstone NP 281 0.606 0.842 0.449 

Table 5-3.Summary of Visibility Results for Alternative 2 (S02 Control Efficiency Increased to 91%) 

Class I Area Minimum 

Distance (km) 

2001 2002 2003 

98th percentile delta-deciview 

UL Bend 200 1.452 1.728 1.689 

North Absaroka WA 254 0.434 1.172 0.736 

Theodore Roosevelt NP 260 1.479 1.954 1.342 

Washakie WA 278 0.945 0.874 0.580 

Yellowstone NP 281 0.564 0.775 0.391 

Table 5-4........ Summary of Visibility Results for Alternative 3 (S02 Reduced to 0.15 Ib/MMBtu)
 

Class I Area Minimum 

Distance (km) 

2001 2002 2003 

98th percentile delta-deciview 

UL Bend 200 1.331 1.543 1.582 

North Absaroka WA 254 0.364 1.041 0.653 

Theodore Roosevelt NP 260 1.373 1.832 1.176 

Washakie WA 278 0.830 0.765 0.505 

Yellowstone NP 281 0.503 0.677 0.320 

24 Air Quality Modeling Methodology 
Table 5-5 Summary of Visibility Results for Alternative 4 (NOx Reduced with SOFA) 

Class I Area Minimum 

Distance (km) 

2001 2002 2003 

98th percentile delta-deciview 

UL Bend 200 1.586 1.557 1.781 

North Absaroka WA 254 0.534 1.280 0.805 

Theodore Roosevelt NP 260 1.426 1.613 1.305 

Washakie WA 278 0.972 0.929 0.560 

Yellowstone NP 281 0.619 0.844 0.460 

Table 5-6 Summary of Visibility Results for Alternative 5 (NOx Reduced with SNCR) 

Class I Area Minimum 

Distance (km) 

2001 2002 2003 

98th percentile delta-deciview 

UL Bend 200 1.554 1.492 1.713 

North Absaroka WA 254 0.522 1.248 0.786 

Theodore Roosevelt NP 260 1.388 1.548 1.272 

Washakie WA 278 0.953 0.904 0.559 

Yellowstone NP 281 0.605 0.823 0.449 

Table 5-7.Summary of Visibility Results for Alternative 6 (NOx Reduced to 0.15 Ib/MMBtu with SCR) 

Class I Area Minimum 

Distance (km) 

2001 2002 2003 

98th percentile delta-deciview 

UL Bend 200 1.456 1.298 1.584 

North Absaroka WA 254 0.484 1.151 0.729 

Theodore Roosevelt NP 260 1.236 1.385 1.173 

Washakie WA 278 0.895 0.829 0.555 

Yellowstone NP 281 0.561 0.760 0.418 

Table 5-8.Summary of Visibility Results for Alternative 7 (Filterable PM Reduced to 0.015 Ib/MMBtu) 

Class I Area Minimum 

Distance (km) 

2001 2002 2003 

98th percentile delta-deciview 

UL Bend 200 1.856 2.090 2.213 

North Absaroka WA 254 0.644 1.541 0.971 

Theodore Roosevelt NP 260 1.762 2.144 1.728 

Washakie WA 278 1.177 1.129 0.635 

Yellowstone NP 281 0.776 1.023 0.566 

25 Air Quality Modeling Methodology 
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, lS., D.G. Strimaitis, and RJ. Yamartino, 2000a: A User's Guidefor the CALPUFF 

Dispersion Model (Version 5). Earth Tech, Inc., Concord, MA 

Scire, J.S., F.R. Robe, M.E. Fernau, and RJ. Yamartino, 2000b: A User's Guidejor the 

CALMET Meteorological Model (Version 5). Earth Tech, Inc., Concord, MA. 

U.S. Environmental Protection Agency (EPA), 1998: Interagency Workgroup on Air Quality 

Modeling (lWAQM), 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 jor 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. 

26