# BestAvailableRetrofit Teclmology(BART) 

# Assessment ColstripGeneratingStation

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# PPL Montana, LLC Billings Montana



### Prepared

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Windsor, ConnectK:ut



### August 2007

# BestAvailableReuofit Technology(BART) AssessInent**C~lstrip** 

# C-.enerating Station

Prepared for



# PPL**Montana~** 

# LLC BIIIIngs. Montana

21 Griffin Road North Windsor, Connecticut06095

Telephone 860-298-9£92 Facsimile 860·298·6399

TRC**Proj~t** No, 114175 OOZQ 00004 

### August 2007TABLE OFCONTENTS 

### SECTION PAGE EXECUTIVE SUMMARY ES-I 1.0 INTRODUCTION/BACKGROUND I-I 2.0 PLANT DESCRIPTIONS

- BART AFFECTED UNITS 2-1 2.1 BoilerType 2-1 2.2 Emissions 2-1 2.3 Potentially Impacted Class IAreas 2-4 3.0 BART METHODOLOGY OVERVIEW 3-1 4.0 BARTANALySES 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 RetrofitTechnologies for Colstrip Units I &2

.4-8 4.2.1 Particulate Controls 4-8 4.2.1.1 ParticulateControl Technologies

.4-9 4.2.1.2 Costs ofControls 4-11 4.2.1.3 Energy 4-13 4.2.1.4 Non-AirQuality Environmental Impacts 4-14 4.2.1.5 Remaining Useful Life

.4-14 4.2.1.6 Visibility Modeling 4-14 4.2.2 SulfurDioxide Controls 4-15 4.2.2.1 Control Technologies 4-15 4.2.2.2 CostofS02 Controls 4-16 4.2.2.3 Energy 4-16 4.2.2.4 Non-AirQuality 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-AirQuality 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 ofModeling Results 4-22 5.0 SUMMARYAND 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 MatterType and Size Speciation 2-2 Table 2-2: Present (Base Case) S02 andNOx 

### 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 ofModeling Results for Particulate 4-15 Table 4-6: PPL BART S02 Control Cost Summary (Each Unit) .4-17 Table 4-7: Summary ofModeling Results for S02 4-18 Table 4-8: PPL BARTNOx 

### Control Cost Summary (Each Unit) .4-19 Table 4-9: Summary ofModeling Results for NOx•••••••••••••.••••••••••••••••••••••••••••••••••••••••••••••••••

### 4-21 Table 4-10: Summary ofModeling 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 FIGURE4-1: COSTANALYSIS OF ESP CONTROL. .4-12

APPENDICES APPENDIX A: DETAILED COST CALCULATIONS APPENDIX B CALPUFF APPLICAnON FOR BARTASSESSMENTS 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 thatcould potentially cause orcontribute to a degradation ofvisibility at Prevention of Significant Deterioration (PSD) mandatory Class IAreas. Coal fired Units I

### &2 atthe Colstrip generating plantlocated 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 ProtectionAgency Region 8. The Class I 

### areas within 300 km ofColstrip are the UL Bend National Wildlife Refuge (200 km to the northwest), the North Absaroka Wilderness Area (254 km to the west), the Theodore RooseveltNational Park (260 km to the northeast), the Washakie Wilderness Area (278 km to the southwest) and YellowstoneNational Park (281 km to the west). These Class I 

### areas are shown in relation to the Colstripplantin 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 ofwet scrubbers that remove both particulate and sulfur dioxide, low sulfur Powder River Basin coal and good combustion control using low NOx burners. A range ofdemonstrated control alternatives for sub-bituminouscoal-fired boilers was

ES-l

### Figure

### ES-l: Colstrip Location and 

### ClassI 

### AreasEvaluated



### .6. Colstrip

Idaho North Absaroka Wilderness

Nebraska

.. Class IAreas 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 ofthe units and modeled visibility improvements. A summary oftheresults 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 currenttechnology, orthe addition offabric filter/ESP controls would be necessary to attain an emission rate equivalent to the best demonstrated technology (BOT) filterable particulate emission rate of 0.015 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 ofthe scrubber. For installation ofan 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 notwarranted. 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 oflime to the scrubbers presently in operationto enhance removal. The addition oflime is projected to increase S02 removal efficiency from the present 75 percent level to approximately 88 percent with little adverse operational impact at a costeffectiveness (CE) ofan estimated $2l8/ton ofadditional 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 overa 50 percentcontrol efficiency. Nevertheless, this rate
was evaluated. The increased addition oflime to attain the 91 percentremoval will incur scaling ofthe scrubber with significant downtime to descale the scrubbing vessel atan estimated cost of $499/ton of S02 removed. To eliminate the downtime for descaling, a spare scrubber vessel could be installed to eliminate downtime ata CE of$1,292/ton. Incremental CEofthe high lime injection, and the backup scrubber module options are $1,621 and $5,590/ton respectively. Cost estimates are based on EPA Control CostManual information and techniques and PPL operating experience. All costs are indicated in 2007 dollars. Only a 0.422 deciviewreduction 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 ofthese controls is not warranted. NOx 

### controls at Colstrip include the tangential firing design ofthe 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 ofcombustion air to the multiple injection ports for the current NOx 

### controls, it is likely that emissions can be reduced to an average of0.18 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 of0.16 lb/MMBtu. The costofSNCRtechnology 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 ofammonia 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 ofSNCR 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 ofcontrols 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 ofcontrol to the next. A summary ofthe modeled visibility impacts of the present emissions and the control alternatives based on maximum emissions is provided in Table ES-2, both relativeto the presentemissions and incrementally.

TableES-l: Current/ NSPS/ Control OptionsCostSummary Nitrooen Oxides Particulate Maller Sulfur Dioxide Control Rate Units Rate Units Rate Units Current(l) Emission rate COFA(2) 0.4 Ib/MMBtu 0.35 Ib/MMBtu 0.050 Ib/MMBtu
BD"jO)from 

### I 0.015 Ib/MMBtu 1.4 Ibs SOl/MW out 10 Ib/MWout 2006 NSPS (0.15 Ib/MM Btu in New Sources ro.11 Ib/MM Btu in Cost Effeciveness Calcs Cost Effeciveness Calcs CE(7) CE(8) Option Evaluated Option Evaluated Option Evaluated Inc CE Inc CE Rate Rate Rate Ib/MMBtu $/ton IblMMBtu $/ton $/ton Ib/MMBtu $/ton $/lon Added ESP Control 0015 $38,738 Present 0.4 Present $0 0.35 WS-FGD(4) Added FF 0.015 Options $29,599 0.2 $218 SOFA 0.18 $451 WS-FGD(5) 0.15 $499 $1,621 SNCR $977 $3,424 016 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 agross 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 scrubberwill reduce emissions by 50% 5) Similarto 3 but additional downtime due to scaling to allain a reduction to 0 15 Ibs/MMBtu 6) Similarto (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

### TableES-2: Modeled Visibility and Visibility Improvements

Sulfur Dioxide Nitrogen Oxides Modeled Filterable Particulate Improvement (7) Rate (1)(2) Improvement (7) Modeled Improvement (7) Modeled Rate (1)(2 Prediction (3) from Rate (1)(2) Prediction from 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 Present n/a n/a Present 2.233 n/a 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 0.042 0.27/030 0.091 0042 0.651 0.146 1.584 0.163 0.15 1.832 SCR 0.15 0.801
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/Unit2 rates. (3) Prediction is from all three pollutants at present emissions exceptthe one being controlled (4) Seecorresponding 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 occuratdiffereent Class I areas thatthe 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 BestAvailable 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 ofMontana withdrew its effortto adopt the provisions ofthe 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 ofthese 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 Underthe 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 oflow sulfurcoal and venturi scrubbers. Because Units I&2 already have post-combustion S02 scrubbers achieving greater than 50 percent S02 removal, BART presumptive S02 rates applicableto powerplants with over 750 MW capacity do not apply to Colstrip. The BART presumptive NOxrates, however, do need to be considered. There are no BARTpresumptive particulate rates. Units 1&2 have been evaluated for S02, NOx , and particulate mattercontrols. 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 ofeach pollutant," and to predict the degree ofvisibility improvement that

I-I

### results from the proposed emissions limit. The best system ofcontinuous emission reduction is identified based on:
• The available retrofit control options • Pollutioncontrol equipmentalready in use orplannedto be in use • The costofthe systems • The remaining use-life ofthe facility • Theenergy andnon-airquality environmental impacts ofthe systems • The visibility impactanalysis. This reportdetails these stepsfor Colstrip Units 1&2.

1-2

### 2.0 PLANTDESCRIPTIONS

- BARTAFFECTEDUNITS 2.1 BoilerType The Colstrip Power Plantconsists ofa total offour electric utility steam generating units, however only Units 1&2 are subject to BART since Units 3&4 were not operational during the BARTeligibility period. Units 1&2 are subjectto BART andhave a nominal net capacity of307 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 MontanaLLC operates the Colstrip Plantunder 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 modelingthe base case. The total filterable particulate emission rates are based on stack tests conducted during the modeling years. For each unit, the highest ofthe 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 ofthe 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 sulfurcontentof0.68 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 inputduringthe modeling years (3,981.8 MMBtu/hr

### and 3,897.2 MMBtu/hr). 

### These particulate emissions used for PPL's BART modeling are differentthan those used by EPA in the preliminary BART modeling provided to PPL. PPL believes that the total

2-1I 

### Table2-1: Colstrip ParticulateMatterTypeand Size Speciation
Particle S

- --­ Col Stack ID #

Unit I Unit 2 C B Particle speciation filterable PM 10 condensable PMIO

0/0 0/0 55.3 44.7 60.4 39.6 Condensable organic H2SO4 condensable (OC) M1=0.48, SD1 =2.0Jim 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=2.0Jim Ib/hr 128.73 155.48 Elemental Carbon (EC)
Ib/hr 4.95 5.97
Mand SD stand for Geometric MassMean Diameter and Geometric StandardDeviation. These are the parameters used to calculate the particle size distribution in CALPUFF.



### 2-2

### filterable values used here are more accurate because they are based on stacktest data. They are higher than the values that EPA used. In terms ofmass 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 similarthe emission rates used in the EPA modeling. In terms ofmass 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 BARTmodelingthatwas provided to PPL. These are the highest 24-houraverage emissions overthe 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 ofa 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 S02and

### NOx 

### presentemissions are summarized in Table 2-2. 

### Table2-2: 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 forthe control technology and cost analyses. (2) 

### Maximum emission rates are the highestdaily average emissions during the modelingyears (2001-2003). 

### These emissions were used forthe modeling analyses. 2-3

### 2.3 Potentially Impacted Class IAreas The Class I areas within 300 km ofColstrip 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 ofthe Clean Air Act "26 named source categories" which include steam electric plants, having potential S02,NOx, 

### VOC or particulate matter emissions of250 tons peryear (tpy) ormore, 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 ofthe units during the modeling period (2001-2003) and for each emission reduction percentageevaluated for the retrofitcontrol options. Potentially applicable retrofit filterable PM, S02, and NOx 

### control technologies which represent a range ofdemonstrated 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 operatingcost • The energy impacts • Theenvironmental impacts • The remaining use-life ofthe emission units • The visibility impacts Based on the information compiled for each ofthe steps above, evaluations were conducted regarding retrofitcontrols applicable tothe units.
Capital and Operating Cost To estimate the capital and operating cost ofcontrol technologies, information from the U.S. Environmental Protection Agency, Control Cost Manual ("EPA Air Pollution Control Cost Manual", Sixth ed., EPA-452-02-00I, 

### January 2002) was utilized where such data were available. The BARTFinal Rule states:
3-1

### "In order to maintain and improve consistency, cost estimates should be based on the OAQPS Control CostManual wherepossible. The Control CostManual addresses most control technologies in sufficientdetail for 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 ofinformation 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 ofthe total capital cost of a technology, PPL uses 11 years as its standard depreciation schedule, consistentwith 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 ofCommerce, Implicit Price Deflatorcost index.
Energy Impacts The inherent energy consumption to operate air pollution control equipment is appropriate for inclusion in the annual operatingcostanalysis.

Environmental Impacts In some technology applications, a new waste stream is generated or an existing waste stream increases. As examples ofthis, an enhanced removal ofparticulate matter accordingly increases the solids collected. The addition ofscrubbing solidsto reactwith 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 particulatematterformation.
Remaining Useful Life The lives ofthe Colstrip boilers are expected to exceed the study period and projected to have no effecton the costing analyses for this facility. Visibility Impacts

3-2The modeledresults for visibility impact, in units ofdeciviews, ofapplication ofthe selected BARToptions were determined as a result ofthis study.

3-3

### 4.0. BARTANALYSES 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 ifit 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 commentphase. 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, oradverse effects on the rest ofthe 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 ofthe technologies listed in:

• EPA's CleanAirTechnology Center(the RACT/BACT/LAERClearinghouse) • State and Local BestAvailable Control Technology Guidelines • Control Technology Vendors • Federal/State/Local permits and associated inspection/performance test reports • EPA'sNSR Bulletin Board • DepartmentofEnergy's Clean Coal ProgramTechnical 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 emissionsunits and pollutants underconsideration 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 ofoptions for analyses that reflect
a comprehensive list ofavailable technologies for each pollutant. The list is considered complete ifthe list includes the maximum level ofcontrol thateach technology is capable ofachieving. The New Source Performance Standards (NSPS) for Electric Utility Steam Generating Units (EUSGUs) are based on EPA's recent review ofthe state-of-the-artcontrols 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 ofSubpartDa are appropriate in lightofthe control technology developments sincethe 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 representthe most stringentlevel ofemissions control for new EUSGUs. A summary ofthe Colstrip allowable emission rates (as listed in the Title V permitfor the facility), actual emission rates, the presumptive BART levels andthe 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. 

### Table4-1: Allowable/ Current/NSPS/ PresumptiveEmission Limits FOR THE PPL MONTANA LLC COLSTRIP UNITS 1&2 , , ParticulateMatter 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/MWout 1.0 IblMW out NewSources (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) Fromcurrent Title V Operatmg Permit

- NOx shortterm 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 February27, 2007, Final Rule (NSPS for EUSGUs) February 27, 2006. Final Rule (NSPS for EUSGUs)

- the 2006revised standards were revised to a gross MW output basis (equivalentin 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 Colstripunder the BART Guidelines 6) Applicable to Colstrip under BART Guidelines 

### 4-2

### EPA's Regulatory Approach to theNSPS 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 criteriapollutants 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 performanceandcostof the emission technologies discussedabove. "
In the BART Final Rule, EPA does not limit BARTanalysis to NSPS standards (see FR Vol. 70,No. 128/Wednesday, July 6,2005, p. 39164, bottom center) where EPA notes:



### "In EPA's 1980BARTGuidelines for reasonablyattributable Visibility impairment, we concludedthatNSPSstandardsgenerally, atthattime, representedthe bestlevelsources couldinstallasBART. In the 20-yearperiodsince thisguidance wasdeveloped, there have been advances in S02 controltechnologies, aswellas technologies for the control of otherpollutants, confirmedby a numberof recent retrofits at Westernpowerplants. Accordingly, EPA no longerconcludes that theNSPSlevelof controlsautomatically represents "the bestthese sources can install". Analysisof theBART factors couldresult in the selectionof an NSPSlevelof control, butyou shouldreach this conclusion only after considering thefull range of controloptions. " Certainly to use the original Subpart Da NSPS emission standards (circa 1979) as proposed BART controls would fall underthis 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 newNOx

### NSPS level is belowthe presumptive BART level and was not evaluated.

4.1.1 Particulate Matter In the proposed rule, EPA discussed the following available particulatemattercontrol 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 ofparticles 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 collectedmaterial falls into a hopper and is disposed properly. ESP technology is capable of high removal efficiencies of99 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 ofreverse flow air injected into the bag, a mechanical shaking system, or a blast ofsonic energy. Fabric fiIters are highly efficienton very small particles and are capable of achieving high efficiencies of99percentorhigher similarto 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 ofthe cylinder and gas with a reduced particle concentration exitingthe top ofthe cyclone. For large gasflows, numerous parallel cyclones are typical and are called multiple cyclones. These devices are mostly used as pre-filtration devices to remove the largestparticles andcan remove up to 80 percentofonly the largestparticles.

4-4

### Wet Scrubbers If water is injected into a cyclone, impaction of particles on water droplets enhances removal and effectively scrubsthe gas. The most common type ofscrubber is a venturi scrubber where water is injected into the exhaust at the throat of a converging section of duct. The converging section ofduct 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 ofthis pollutant to form water soluble sulfite and sulfate compounds.

4.1.2 SulfurDioxide In theirdiscussion ofthe available SOz control technologies in the Proposed Rule that led to revision ofthe NSPS for SOz in February 2006, EPA lists the following available control technologies:
• Coal Pre-Treatment • Alkali Wet Scrubbing • Limestone Scrubbing with ForcedOxidation • Spray DryerAbsorption • Dry Injection • Fluidized-bedCombustion with Limestone
Coal Pre-Treatment There are two basic coal pre-treatments that can reduce SOz emissions: physical coal cleaning andgasification. Physical cleaning can remove 20to 90 percentofpyritic 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 ofwater 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 ofFGD scrubbing is dependent on the fuel sulfurcontent, and the scrubber design parameters, however, up to 98 percent removal of SOz has been demonstrated.

4-5

### Limestone Scrubbingwith 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 DryerAbsorption An alkali containing slurry is used in spray form to contactthe S02 laden flue gas priorto the particulatecollection device. Removal ofS02depends on the stoichiometric ratio ofreactant 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 ofthe reactant. Such systems generally attain greaterthan 90 percentcontrol.
Dry Injection Dry solid absorbent is injected directly into the ductwork upstream of the particulate collection device. S02removal occurs by adsorption ofthe 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 ifanother sorbent such as sodium bicarbonate is used.

4.1.3 Nitrogen Oxides There are both primary and secondary categories ofNOx

### controls in EUSGUs.

• Primary NOx

### Combustion Controls o Low-NOx

### Burners (LNBs) o Over-FireAir(OFA) also known as air staging o LNBs with OFA o Rotating Opposed Fire Air (ROFA) o Combustion ImprovementTechniques

• Secondary Control Techniques o Reburning o Selective Catalytic Reduction (SCR) o SelectiveNon-Catalytic Reduction (SNCR)

4-6

### Low-NOx

### Burners (LNBs) This technique requires control ofthe combustion stoichiometric air/fuel ratio and the boiler temperature profile. NOx 

### formation is dependent on peak flame temperature and the availability ofexcess air in and aroundthe combustion zone. Reduction ofthe 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, September2005). 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 ofup 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 possibleto limitthe increase in UBC to lessthan 0.5 percent.

Over-Fire Air (OFA)/Air Staging and LNBs with OFA In air staging, 5 to 20 percent ofthe 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 limitedto 50 ppm 

### @3% 

### 02.
Rotating Opposed Fire Air (ROFA) or Separated OverfireAir (SOFA) The addition ofa 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.



### 4-7Combustion ImprovementTechniques 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 ofOFA injection locations to obtain optimum results.

SelectiveCatalytic 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 ofthe catalyst bed and by using the proper injection ratio ofammonia to NOx, the "reduction" ofNOxto N2 and H20 occurs. The process is temperature dependent and coal-fired boilers typically locatethe catalystbed in the boilerbetweenthe economizeroutlet and the air preheater where the necessary reaction temperature of 450 to 750 degrees F is found. This technology is capable of90 percentor greaterNOx control.

SelectiveNon-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 withoutthe catalyst bed. Thetechnique only attains 30 to 50 percentNOxcontrol.

4.2 Evaluated RetrofitTechnologies for Colstrip Units I &2 The following sections evaluate retrofit control technologies for Colstrip Units 1&2 for particulate matter, S02 andNOx•

4.2.1 ParticulateControls The following table provides the present particulate emission rates from Colstrip Units 1&2,as described in Section2.2. 

### Table4-2: ParticulateEmissions SummaryforColstrip 1&2
Condensable Ibs/hr
151.3 148.1 Condensable Ib/MMBtu

0.038 0.038 4-8The heat inputrates shown above are the highest daily average heat inputrates during the modelingyears (2001-2003). The total particulate emission rate applied to these heat inputrates is 0.085 Ib/MMBtu and 0.096 Ib/MMBtu respectively for Units I&2 based on stack test data. The speciation ofthe particulate emissions is described in Section 2.2. The above data showthat emission rates from Units I&2 are already low due to the good combustion techniques and application ofwet scrubbing beingused in these boilers. The filterable particulate emission rates
are typical for wet scrubbing using venturi scrubbingtechnology in coal-fired utility boilers. 

### It is necessary, as part ofthe BART analysis, to identify the best demonstrated emission rate that a technology can deliver. Step I in the BARTanalysisprocess is consideredcomplete if the BOT rate, the New Source Performance Standards (NSPS) emission rate, and emission rate from currentNew Source Review permits are included. The following list ofpotential filterable particulatecontrol 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 BOTemission rate of0.015 Ib/MMBtu for Colstrip Units 1&2. Either ESP or FF technology could be applied to Colstrip Units 1&2. The additional removal offine filterable particulate would be limited, however, it is assumed that either could attain the NSPS BOT limit of0.015 IbIMMBtu. Ordinarily, FF technology would be eliminated from consideration because ofthe 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 ofcontrols. Multiple parallel cyclones are often 4-9used in particulate control to obtain relatively high removal efficiencies ofeven fine particulate. Onereference statesthat a multiple cyclone can controlhigh percentages ofparticulate generated by coal-fired units, but cannot attain the very low regulatory allowable emission rates ofthe NSPS ormost 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 mustbe installed before the main collector and in association with the design ofthe 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 availableretrofittechnology.

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 ofthe venturi are captured by impaction and absorption in the downstream section ofthe 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 percenteven 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 of0.047 and 0.058 Ib/MMBtu, as determined from stack testing, are already very low and indicative ofexcellent control efficiency for this technology. Furthermore, enhancement ofthe wet scrubbers would not be expected to result in additional particulate removal. Accordingly, ESP and FF controls were the applicable and available control technologiesto enhance the already 98%particulate control efficiency ofthe Colstrip Units 1&2 boilers.

4-10

### Other Impacts ofTechnically Feasible Control Options Other criteria are relevant in the BART selection process. The costs ofretrofit controls, the energy consumption ofthese controls, and the non-air quality environmental impacts ofthe controls are included in the BART selection process. This section discusses these additional factors.



### 4.2.1.2 Costs of Controls The costs of ESP and FF filterable particulate controls for application to the Colstrip Units 1&2 boilers were evaluated. The cost ofcontrol 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 costeffectiveness (CE) is assumed to be an incremental value determined as thatto reduce the current particulate emissions of0.058 Ib/MMBtu (Unit 2) to the BOT emission rate of0.015 Ib/MMBtu. Unit 2 was analyzed as an example because it has the higherfilterable particulate emission rate which would give the lowerofthe two CE values. The cost ofESP 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. Ata CE ofabout $30,000 to $40,000/ton ofadditional control, this is not considered economicallyjustifiable. The analysis ofthe cost ofESP 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 costfor installation ofan FF. EPA cost factors specifically developed for FF technology
were used. An annualized capital cost ofthe equipmentwas determined using a capital recovery

4-11

### Figure4-1: CostAnalysis ofESPControl
110

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

### I I LOW SULFUR, I 100

I 

# .- 10 

# • 70 CONSERVATIVE OESIGNS I I

I ADVANCED DESIGNS I ".HIGHSULFUR : 

### I I I I 

### I 

### I I 20 1971 NIPS 

# . 1979 NIPS



### I 10 

### I 

## I ".0 ".0
.... 99.7 H.9 COWCTJON EFFICIENCY·. "

• eASEDON A COAL "AltOAT '0.000"''''ANDCONTAINING 1M'ASH. THE 117'

N

.... IS0.'

# ."oe Ihu.ANDTHE ,..,.NIPSIS0.03

# ."0'

.....

Table4-3: PPLBART ParticulateControl CostSummary(PerUnit)

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 equipmentcostdata are correctedto 2007

### dollars. As in the case ofESP controls, the costestimate has been prepared for Colstrip Unit 2 and would be higherfor the otherunit, asUnit 1 

### has a slightly lower filterable particulate emission rate. At a CE ofapproximately $30,000 

### to 

### $40,000/ton of additional particulate controlled, application ofthis 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 parameterthatcan be readily estimated for ESP and venturi scrubbercontrol. 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 ofthe 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 CostManual:
Power(kw-hrs/year) = 1.8

### I x 10-4 

### x ACFM x**~p** 

### xannual operating hours Where: 1.81 

### x 10-4 

### is a proportionality constant ACFM = 

### the actual cubic feet perminute exhausttreated**~p** 

### is the equipmentpressure drop in inches ofwatercolumn (w.c.) The following Table 4-4 is presentedto illustrate the powerconsumption requirements of the four common types of particulate control devices. Each technique has predictable energy consumption in terms ofthe 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 ofthe multiple cyclone (MC) leads to the loss ofconsiderable 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 orderof35" ofwater. 4-13

### Table4-4: Representative ControlEquipmentPressureDrops ControlOption TypicalAp Reference TableorPageNo. (inchesw.c.) ESP 0.09to 0.38 EPA, 2002 Pg. 3-34 Section 6 FF 6 to 7 EPA,2002 Pg. 1-47 Section 6 MC 4 VendorEstimate VS 

### < 100 AWMA Table 5.4-5


### 4.2.1.4 Non-Air QualityEnvironmentalImpacts The ESP or FF particulate controls for Colstrip, would generate a new particulate waste stream. Thecurrent ash collected by the scrubbers wouldremain, however, operation of particulate controls to collect an additional 70 percent ofcurrent particulate emissions, 562 tons peryearfrom each unit. Thecostfordisposal ofthis ash is estimated at 

### $40/ton.

4.2.1.5 Remaining UsefulLife The life ofthe Colstrip boilers is expected to exceed the study period and is projected to have no effectonthe costing analyses for this facility.



### 4.2.1.6 ViSibilityModeling 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 ofthe annual 98th percentiles ofdaily modeled visibility impacts among the three years modeled (2001-2003) and the five Class I areas modeled. The highest ofthose 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 ofthe Class I areas. Thisdifference is shown relative to the base case. The visibility modeling results are described and presented in more detail in Section 4.3 andAppendix B.

4-14

### --- Table4-5: SummaryofModelingResults for Particulate
Max 98th Emissions (1) Percentile Deciview ControlOption Prediction Difference Ib/MMBtu (deciviews) Ib/hr Relative to the BaseCase Base Case 0.047/0.058(f) 2.233 (2) 187.2/226.0 (f) 0.038 (c) 151.3/148.1 (c) 2.21 (2) 0.042 (3) NSPS Case 0.015 (f) 59.7/58.5(f) 0.038 (c) 151.3/148.1 (c)

NOTES: (1) "f"refersto filterable and "c" refers to condensable particulate. (2) The maximum deciview impactoccurred at the UL Bend Class I area. (3) The maximum deciviewdifference occurredat the Theodore RooseveltNational 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 ofsuch coal, the baseline emissions for the Colstrip boilers are already low at 0.72 to 0.80 Ib/MMBtu ofS02, maximum 24-hraverage, and are typically lowerat 

### 0040 Ib/MMBtu, which is representative ofa typical 30­ day average emission rate considering the actual sulfur content of the fuel and the removal efficiency ofthe wet scrubbers. The Colstrip boilers are equipped with CEMS for S02 which
were used to determine the baseline maximum 24-hraverage S02emissionrates.



### 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 effecton S02 emissions. PRB coal already has low sulfur levels and any further reduction in this fuel sulfurcontentby any mechanical means is notexpected. Theoption to gasify the coal for sulfur removal is a complete change in the method ofoperation forColstrip which was given no consideration. The controls evaluated to improve S02 control below the levels attained by using the low-sulfurcontentcoal 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 ofthe alkaline nature ofPRB 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

### thatan increase in S02 removal can be attained by chemical addition using injection technologies (injection oflime). Ifthis injection is limited to quantities thatdo not impactthe 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 ofS02 to a new emission rate of0.20 IblMMBtu
can be achieved before impactingthe scrubberoperation. As the amount oflime is increased, operation ofthe scrubbers will be affected. Scaling is projected to begin at levels ofcontrol exceeding 88 percent and become significant as removal efficiency increases and achieves an emission rate of0.15 Ib/MMBtu. This will incur additional maintenance expenses and outages representing an additional cost ofimplementing this option. This could also require back-up scrubbers to reduce downtime for descaling. O&M time, however, will be greaterdespitethe additional scrubbers.



### 4.2.2.2 Cost O{S02 

### Controls PPL used experience from operation ofthe wet scrubbers on Units 3&4 at Colstrip to estimate the costs oflime 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 oflime injection equipment for Units 1&2, the cost ofthe lime, and minimal O&M costs. To attain the presumptive limit, the equipmentcostdoubles 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 scrubbermodules atexcessive incremental costs.



### 4.2.2.3**~ner£rV** 

### The pressure drop ofeach ofthe venturi scrubbers is maintained in the range of 17 to 20 inches ofwater column. The addition oflime 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 costanalysis as an annual cost ofadditional operations and maintenance (O&M) expenses ofan estimated $125,000 peryear.

4-16

### Table4-6: PPLBARTS02ControlCostSummary (PerUnit)
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 ofS02 of70% overthat currently attained, the additional sprays and pumps will increase O&Mto an estimated $390,000. In summary, energy impacts ofthe addition oflimeto 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 QualityEnvironmentalImpacts 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 scrubberunitwhile othermodules remain operational.



### 4.2.2.5 Remaining Useful 

### Life The life ofthe Colstrip boilers is expected to exceed the study period and is projected to have no effecton the costing analyses for this facility.



### 4.2.2.6 VisibilityModeling 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 ofthe annual 98th percentiles ofdaily modeled visibility impacts among the three years modeled (2001-2003) and the five Class I 

### areas modeled. For the modeled control alternatives, the emissions ofS02 were at its controlled level and the emissions ofthe 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 ofthe Class I 

### areas. These differences are shown relative to the base case and also incrementally relative to the immediately preceding control alternative in termsofthe level ofemissions reduction attained. The visibility modelingresults are described and presented in more detail in Section 4.3 andAppendix B.



### Table4-7: SummaryofModeling Results for S02
Max 98th Emissions Percentile Deciview Difference ControlOption Prediction Relative Increment Ib/MMBtu (deciviews) to BaseCase 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 eitherthe UL Bend. Theodore RooseveltorNorth AbsarokaClass Iareas.



### 4.2.3 

### 00Controls The Colstrip boilers are tangentially fired units equipped with 10w-NOx 

### burners. A review ofCEMS 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 of0.35 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 airpresently in operation atColstrip.

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 ofthe entire air distribution to the firebox is predicted to reduce NOx 

### to 0.18 Ib/MMBtu. The addition ofSNCR 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-firedboilers of0.15 Ib/MMBtu was analyzed. Reburning technology for application to Colstrip was not evaluated. This technology option is considered as the equivalent ofSOFA. Both technologies produce fuel-rich zones in the combustion chamber which can reduce NOx 

### emissions by significant amounts. Therefore, PPL limitedthe control evaluationto SOFA with an anticipated reduction to 0.18 Ib/MMBtu.



### 4.2.3.2 Costof NOx

### Controls The costing analysis ofthe various control options for NOx 

### reduction are summarized in Tables 4-8, see AppendixA, Tables A4-8(a), A4-8(b) andA4-8(c) for complete details. Table4­ 8 utilizes cost estimations for adding SOFA to the LNB technology, based on recent upgrades to the burners in Units 3&4 atColstrip. Reduction from an emission rate of0.35 Ib/MMBtuto 0.18 Ib/MMBtu results in a CE of$451 /ton (in 2007 dollars) ofNOx

### controlled.



### Table4-8: PPL BARTNOx 

### ControlCost Summary(PerUnit)

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-452-02-00I, January 2002). The cost analysis for application ofSNCR 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 SNCRcontrol option estimated to result in an emission rate of0.16 IbIMMBtu, the CE of $977/ton for SNCR is not 4-19

### justifiable. Similarly, SCR controls, applied to a typical boiler emission rate of0.35 Ib/MMBtu shows a CE value (Table 4-8) of$2,272/ton ofNOx 

### 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 ofthe overall cost ofcontrol, they have been included in the analysis as part ofthe annualized costfor each option.


### 4.2.3.4 Non-Air QualitylSnvironmentalImpacts While SOFA may have impacts on particulate matter emissions with a slight change in LOl, this is oflittle impact for Colstrip boilers which use scrubbing for control ofparticulate and hencethere is no salable ash. The addition ofchemical reagents in SNCRand SCRcontrols adds equipmentfor its storage and use. The additional costs ofchemicals and catalysts in the case of SCRhave been included in the cost analysis.



### 4.2.3.5 Remaining UsefulLife The life ofthe 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 VisibilityModeling 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 ofthe annual 98th percentiles ofdaily modeled visibility impacts among the three years modeled (2001-2003) and the five Class 1 areas modeled. Forthe modeled control alternatives, the emissions ofNOx 

### were at its controlled level and the emissions ofthe 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 ofthe Class 1areas. These differences are shown relative to the base case and also incrementally relative to the immediately preceding control alternative in terms ofthe level ofemissions reduction attained.

4-20

### --- --- Table4-9: SummaryofModelingResults forNOx Max 98th Emissions Percentile Deciview Difference Pollutant ControlOption Prediction Relativeto Increment IblMMBtu (deciviews) BaseCase Ib/hr

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 0.573 836.2/935.3 1.713 SNCR 0.21/0.24 0.638 0.068 SCR 597.3/584.6 0.801 0.15 1.584 0.163 NOTES: The maximum deciview impacts and differences occurat eitherthe UL Bend orthe Theodore Roosevelt Class Iareas.

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 ofemissions from Colstrip BART eligible Units 1&2 on visibility in the five federal mandatory Class I areas within 300 km ofthe 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 ofhourly 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 letterto PPL identifying Colstrip Units 1&2 as subject to BART and providing preliminary modeling results. The modelingconductedby TRC for PPL is basedonthose datafiles withthe following exceptions: 4-21

### • Speciation offilterable and condensable particulate emissions was revised by PPL based
on stacktest dataavailableduringthe modeling years (2001-2003) and AP-42 factors

. • There were a few modificationsto the modelingas 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 ofthe modeling results as described below) for each ofthe control scenarios evaluated. These modeled S02, NOx 

### and particulate emissions are based on the maximum actual daily operation ofUnits 1&2 duringthe three-year modeling period as described in Section 2.2. Thepresentbase case visibility impactofColstrip Units 1&2 in each Class I area in terms ofthe deciview haze index was determined by comparing the combined visibility impact ofthe 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 ofeach ofthe control alternatives were then compared against the base case and each otherto determine the degree ofvisibility improvementfor each control alternative.

4.3.2 Summary ofModeling Results The highest ofthe annual 98th percentiles ofdaily 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 ofthe 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 ofthe control alternatives are also provided in the table. Foreach control alternative modeled, the emissions ofthe controlled

4-22

### --- ---

--- ---

--- --- Table4-10: SummaryofModeling Results
Max 98th Emissions (1) Percentile Deciview Difference Pollutant Control Prediction Relative Increment Option IblMMBtu Ib/hr (deciviews) to BaseCase

2.233 (3) Lime Injection (50% Base Case(2) 0.72/0.80 2612.0/2828.0 S02 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

Base Case(2) NOx 0.45/0.53 1798.0/1955.0 2.233 SOFA 0.23/0.27 915.811052.2 1.781 0.573 0.573 0.21/0.24 SNCR 836.2/935.3 1.713 0.638 0.068 SCR 1.584 0.15 597.3/584.6 0.801 0.163

Base Case(2) 187.2/226.0 (f) 2.233 0.047/0.058(f) PM 151.3/148.1 (c) 0.038 (c) 0.042 (2) 0.015 (f)) 59.7/58.5 (f) 2.213 0.042 NSPS Case 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 impactofthe base case occurred at the UL BendClass I area. Forother cases shown, the maximum impactordifference occurred at eitherthe UL Bend orTheodore RooseveltorNorth Absaroka Class Iareas.



### 4-23

### pollutant were at its controlled level and the emissions ofthe 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 ofthe level ofemissions reduction attained. The net changes presented are highest netchange in visibility at any ofthe Class Iareas 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 orcontribute to a degradation ofvisibility at Prevention of Significant Deterioration (PSD) mandatory Class IAreas. 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 efficientoperation and good combustion control. EPA's BART Guideline approach has been applied to Colstrip Units 1&2 to identify the "best system ofcontinuous emission reduction" applicable to the units for filterable particulate control, S02 reduction and the control ofNOx• A range ofdemonstrated control alternatives for large tangentially-fired coal boilers was evaluated considering costs, energy and environmental impacts, remaining useful life ofthe 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 thatthere is little room for further improvementofthe scrubber. Modified wet scrubbing by the existing venturi scrubbers to include lime injection and the addition ofan additional scrubbervessel were evaluated for additional S02control, and separated over-fire air, selective non-catalytic reduction and selective catalytic reduction were evaluated for NOxcontrol. The CALPUFF model was used to evaluate the visibility impacts ofpresent 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 ofColstrip. 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. 5-1For the modeling analyses maximum daily emissions during the modeling years (2001-2003)
were used. The results ofthe cost and modeling analyses are presented in Tables 5-1 and 5-2. The highest modeled annual 98th percentiledaily visibility impactofemissions from Units 1&2 based
on present (base case) maximum actual load is predictedto occur in the in the UL Bend National Wildlife Refuge (NWR) Class Iarea 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 ofadditional 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 S02removal 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 orless, 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 ofthe controls is notwarranted based upon the level of visibility improvement.

5-2

### Table 5-1: Current/ NSPS/ ControlOptions CostSummary FOR THE PPL MONTANA, LLC, COLSTRIP UNITS 1AND 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 ofeach 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 (NSPSfor EUSGUs)
- the 2006 revised standards were revised toa 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 (perCEMS); adding limetothe scrubberwill reduce emissions by 50% 5) Similarto 3 but additional downtimedueto scaling to attain a reduction to0.15 Ibs/MMBtu 6) Similarto (4), but more lime and an additional scrubber (per unit) necessaryto reach the presumptive limit 7) Control options considered separately; incremental cost ofscrubbing options comparesthe relative additional removal tothe baseline lime injected scrubber option 8) Control options considered separately; incremental cost of SNCR and SCR reflect the relative cost ofincreased NOx removal



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

Nitrogen Oxides Modeled Sulfur Dioxide Filterable Particulate Modeled Improvement (7) Rate (1)(2) Modeled Improvement (7) Improvement (7) Rate (1)(2 Prediction from Option Rate (1)(2) Prediction from Prediction (3) from (deciviews) Present Inc(6) Present Option Ib/MMBtu (lb/MMBtu) (deciviews Present Inc (6) Present Inc (6) Option (lb/MMBtu) (deciviews) n/a Present 0.45/0.53 2.233 n/a n/a n/a n/a n/a Present 0.72/0.80 2.233 2.233 0.04710.058 0.23/0.27 1781 0.573 0.573 Added FF 0.015 0.422 0.422 SOFA 0.042 WS-FGD(4) 0.36/0.40 2.000 2.213 0.042 New ESP 0.015 0.21/0.24 1.713 0638 0.068 WS-FGD(6) 0.091 SNCR 0.042 0.2710.30 1.954 0.505 0.042 WS-FGD(5) 2.213 1.584 0.801 0.163 0.146 SCR 0.15 1.832 0.651 0.15 Notes; (1) The modeled emission rate is the rate corresponding tothe 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/Unit2 rates. (3) Prediction is from all three pollutants at presentemissions exceptthe 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 atdiffereent Class I areas that the maximum prediction among all Class I areas.



### 5-3

### 6.0 REFERENCES AWMA, Air Pollution Engineering Manual, Air& Waste ManagementAssociation, Anthony J. Buonicore and Wayne T. Davis, eds., VanNostrand Reinhold, 1992. EC/R, Stationary Source Control Techniques Documentfor Fine Particulate Matter, EPA ContractNo. 68-0-98-026, WorkAssignmentNo. 0-08, EC/R Incorporated, October 1998. EPA 2002,AirPollution Control CostManual, U.S. EPA, Volume 2, Sixth Ed., EPA-452-02­ 00I, January 2002. EPA, 2003, Guidance for EstimatingNatural Visibility Conditions Underthe Regional Haze Rule, http://www.epa.gov/ttn/oarpg/tl/memoranda/rh envcurhr gd.pdf EPA 2004, Supplemental Air Quality ModelingTechnical 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, etal. 2000, A User's Guide for the CALPUFF Dispersion Model, Earth Tech, Inc. January 2000.

6-4

# APPENDIXA: DETAILED COST CALCULATIONS

Table numbers in this appendix referbackto the summarytables in Section4 of the report (e.g., Table A4-3(a) in this appendix supports Table 4-3 in Section4 ofthis report).

### TableA4-3(a): PPL BART CostAnalysis ElectrostaticPrecipitatorParticulate Control 330 Megawatt Coal Fired Steam Electric Unit Dry-Bottom Combustion in Colstrip Unit 1and Unit2(each)
Stack Exhaust Volumetric Flowrate, (acfm) Maximum Gross Heat Input Uncontrolled Filterable PM Emissions ExhaustTemperature, (oF) SteamTurbine Power Output (MW) Hours of Operation 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 CostTotal, (EC) Retrofit Factor Direct Capital Costs Purchased Equipment Costs

ESP and Auxiliary Equipment Instrumentation SalesTax 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 DirectCapital Costs, DC IndirectCapital Costs

Engineering Construction and Field Expenses Contractor Fees Start-Up PerformanceTest Model Study Contingencies

Total IndirectCapital Costs, IC Total Capital Costs,TCC
.. DC + IC Capital Cost ($/KW) EC (Adjusted byCost IndexCalcs) New EqUipment Costx 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

### TableA4-3(a) continued DirectAnnual Costs

Utilities

Fan Power1) Fp =(181 x W 4)(Q)(delta P)(hrs/yr) (01 in w.e. assumed) $143,975 TR Setand 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 CollectorArea(J) 1987 $ $25,446 2007 $ $41,440 Matenals 001 PEC 1987$ $517,696 2007 $ $843,095 Total DirectAnnual Costs, DAC $1,104,942 IndirectAnnual Costs

Overhead 60% of Operating Laborand $551,574 Maintenance Costs Administrative 0.02TCC $2,319,276 PropertryTaxes 001 TCC $1,159,638 Insurance 001 TCC $1,159,638 Capital Recovery CRF'TCC $15,459,047

Total IndirectAnnual 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 Centerfor Environmental Research Information, 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 afunction ofthe Specific Collecting Area (SCA)

The OAQPS Control Cost Manual extimates P= 194x 10-3x SCAx hrs/yras the total of electnfication and rapping electiciitypower consumption in kWhrs/yr SCA is based on a SCA of 250tr/1 ,000 ACFM and a migratIOn velOCity of 10 cm/sec characterisitc of coal fly-ash 3. Collector area= 250

### tr 11 ,000 ACFMx Q = 308,437

### tr

### TableA4-3(b): PPL BART CostAnalysis PulseJet- Fabric Filterfor Additional Particulate Control 330 MegawattCoal 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 atfull 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 CostTotal, (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 IndirectCapital Costs, IC Total Capital Costs, TCC
.. DC + IC Suggested Factor
Capital Cost ($fKW) EC (Adjusted by Cost IndexCalcs)

(Factors for FFs from OAQPS Manual) EC 0.10EC 003EC 005EC PEC = 118EC

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

### TableA4-3(b) continued DirectAnnual 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 DirectAnnual Costs, DAC $3,696,140 IndirectAnnual Costs

Overhead 60% ofOperating Laborand $1,563,325 Maintenance Costs Administrative 002TCC $1,349,706 PropertryTaxes 001 TCC $674,853 Insurance 001 TCC $674,853 Capital Recovery CRF"TCC $8,663,440

Total IndirectAnnual 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 Centerfor 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 highlyvanable pressure drops (70"wc assumed)
- ElectnClty cost at $0.08/kWHr is typical 2 Compressed air cost is calculated as suggested bythe OAQPS Control Cost Manual;

2 scfm of compressed air is assumedto be required for each 1,000 acfm perminute of operation the cost of such compressed air is estimated to be $0.25 per 1,000 scfm 3. Bag replacement costcan varyWIdelyfrom 15%to 100% ofthe PEC (15% assumed):

the bag life is assumed to be 2years and a capital recoveryfactor of 05454 has been applied to the annual bag replacement cost AlC ratio of5 assumed. $03/tt2 labor cost assumed for bag replacement

### TableA4-6(a): PPL BART CostAnalysis WetScrubbing SulfurDioxide Control (Option 1) 330 Megawatt Coal Fired Steam Electric Unit Tangentially Fired Sub·bltumlnous Coal Combustion at Colstrip Unit 1orUnit2

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

Costof Lime Injection Equlpmen(l) EquipmentCostTotal, (EC) Total Capital Costs,TCC DirectAnnual Costs, DCC

Operations and Maintenance Costs Miscellaneous O&M Costs Total O&M Cost IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual 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

Costdata references 1) Includes lime injection equipment based on the costof similar equipmentfor units 3&4

### TableA4-6(b): PPL BART CostAnalysis Wet Scrubbing SulfurDioxide Control (Option 2)
330 MegawattCoal Fired Steam Electric Unit Tangentially Fired Sub-bltuminous Coal Combustion at Colstrip Unit 1 orUnit 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 DirectAnnual Costs, DCC

Operations and Maintenance Costs Additional fresh water 35% increase in scrubber downtime 35% Increase in scrubber O&M Miscellaneous O&M Costs Total O&M Cost IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual 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 equipmentfor units 3&4

### Table A4-6(c): PPL BART CostAnalysis Wet Scrubbing SulfurDioxide Control (Option 3) 330 Megawatt Coal Fired Steam Electric Unit Tangentially Fired Sub-bltumlnous Coal Combustion at Colstrip Unit 1orUnit2

Stack Exhaust Volumetric Flowrate, (acfm) Maximum Gross Heat Input Design Percent Load Uncontrolled S02 Emissions (with low Scoal) 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 % 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

Costof Lime Injection Equipment<l) BaSIC lime Injection equipment Additional sprays and absorption pump Spare scrubbervessel Total Capital Costs, TCC DirectAnnual Costs, DCC

Operations and Maintenance Costs Additional fresh water 35% increase in scrubberO&M Operations and Maintenance Costs Miscellaneous O&M Costs Total O&M Cost IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual 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

Costdata references 1) Includes lime Injection equipment based on the cost ofsimilar eqUipmentfor units 3&4

### Table A4-8(a): PPL BART CostAnalysis LowNOx

### BurnerControls with SOFA 330 MegawattCoal 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 atfull 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, (%) Depreciation 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) EquipmentCostTotal, (EC)

Total Capital Costs,TCC" DC + IC Total DirectAnnual Costs, DAC IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual 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 addlng SOFA at Colstnp Units 3&4

### TableA4-8(b): SNCRCostAnalysis for ColstripUnit 1 Maximum Heat Input (MM Btu/hr) Os Annual Average HeatInput (MMBtLJIhr) 0." NOx Emission Rate (Uncontrolled, IbsIMMBtu) Normalized Stolchometric Ratio (NSR) from Figure 1 8 (of EPA CCM) CapaCity Factor (hrslyr atfull 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) ElectricityCost($II<Whr) Urea Cost lora 50% Solution ($/gallon) SNCR Life, (yrs) Capital Recovery Factor, SNCR CRF(11 yr) Do'ign P,,,,,,,oto
.. SuggomdFactor SNCR Capital Equipment Cost SNCR System, ,"eluding ( PerControl Cost Manual, Equation 1 19) - Urea unloading skid Includes equIpment, instrumentation, salestax - 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 forfive zones

-Water boosler pumps

- Urea solution distribution module

- Valved connectors for urea and atomIzing air

- Flow mOnltonng for each Injector- wall and lorlance type '"Jectors

- NOx monitor With feedbackcontrols for urea Injection control

- FoundaDonfortank

- 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 DirectCllpital Colli,TDCC (Soo coilroferonco,noto,) Indirect Coils IndirectInstallation Colli

General Facilities Cost o05xTDCC Engineering and Home OffICe Fees 010xTDCC Process Contingency 005xTDCC 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 DirectAnnual 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 0015xTCC Total DllectAnnual Costs,TDAC IndirectAnnual Costs

Administrative o02xTCC PropsnryTaxes 001 xTCC Insurance 001 xTCC Capital RecovelY
- SNCR System CRFxTCC Total IndirectAnnual Costs,TIAC Total Annual Coil',TAC·TDAC +TlAC CoilEffectlvonoss (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 = $950x O. x [2375/a"f,nx [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 Costtaken from EPA Cost

Manual Equation 1 19 (See notesfor 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!kwhr 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

### TableA4-8(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 Velocitythrough SCR (ftimin) Percent O 2 at SCR mlet Exhaust Gas Temp at SCR Inlet (deg F) Ammonia slip (ppmv) Ammonia Solution Concentration Sulfurcontent in coal Annual Interest Rate, (%) Electricity Cost ($/kWhr) Ammonia Costfor a29% Solution ($/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/NOxEfficiency Adjustment Factor w/lnlet NOx Adjustment Factor wiAmmonlaSlipAdjustmentfactor w/Sulfur in Fuel Adjustment wITemperature Adjustment Factor Area Catalyst (A) Area of SCR (If) Length and Width of SCR (tt) Nlayers 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 

### SCRCostAnalysis 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 xeff/100) 08524 + (03208xNOxin)

12835
- (0.0567 xslip) 0.9636 + (0.0455 xS) 15.16
- (003937 xT) + 2.74 x 10-5x T 2 Based on veloicty of 960 fpm 1.15xA Square Bed V

eal/31/A (to nearest integervalue)

(Veall Nlayersl A) + 1 (For catalyst management) h scR

### = 1'\a1a1 x (7 + h l•yo,) + 9 Noxin x0,v9x NSR xeffx 17/46

Total DirectCapital 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

### TableA4-8(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 Contingency Preproduction Cost Total OtherCapital Costs,TOCC 015x(TDCC +Tile) 0.02 x(TDCC +TIIC + Project Contingency) TDCC +TIIC + Pro) Contingency Total Capital Costs, TCC TDCC +TIiC +TOCC DirectAnnual Costs

Annual Ammonia Cost Electricity (Added Cost due to SCR)1 Annual Maintennace Cost Total DirectAnnual Costs, TDAC CCM, Equation 2.48 0015xTCC $0 85/gal $0.08/kw-hr

IndirectAnnual Costs

Administrative PropertryTaxes Insurance Capital Recovery
- Catalysr Capital Recovery
- SCR System Less Catatyst Total Indirect Annual Costs, TIAC 002xTCC 0.01 xTCC 001 xTCC CRF(3yr) xCatalyst 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, January2002 TDCC Adjusted USing CI=103.450 (2002) to CI=118049 (2007) Notes 1. Electricity cost includes ammoniavaporization heaters 2. Assumes replacement of all catalyst atthe end of 3years 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 CALPUFFAPPLICATIONFORBART ASSESSMENTSATPPL COLSTRIPUNITS 1&2

# CALPUFFApplication for BARTAssessments at PPLFacility Colstrip Units 1&2 in Montana for the UL Bend, TheodoreRoosevelt, Washakie, North Absaroka, andYellowstone Class IAreas

PreparedFor: PPL Montana, LLC Billings, Montana



### SubmittedBy: 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 DataBase 9 3.4 AirQuality 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. Figure4-1. Aerial photo ofthe PPL Colstrip facility 4 Terraincontours (m MSL) at 2 km resolution forthe 780 km by 570km CALMETand 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 andthe location ofColstrip PPL are also shown. 10 Surface stations. The stations included in the SURF.DAT files are plotted in purple. Forreference in orange are shown the stations included in the original SURF.DATfiles. Asthe figure shows bettercoverage ofthe domain is achievedby using the ISHWO database. 

### 13 Locations ofozone monitoring stations used in the CALPUFF modeling. 15 Locations ofreceptors at UL Bend,NorthAbsaroka, Theodore Roosevelt, Washakie and Yellowstone Class I areas. 19

11

### LIST OFTABLES

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 ofBackgroundNatural Visibility Conditions 22 Table 4-2. Monthly f(RH) values basedonthe Representative IMPROVE Site Location, for Visibility Method 6 applications 22 Table 5-1. Summary ofVisibility Results for Base Case 24 Table 5-2. Summary ofVisibility Results forAlternative 1(S02 Control Efficiency Increasedto 88%) 24 Table 5-3. Summary ofVisibility Results for Alternative 2 (S02 Control Efficiency Increasedto 91%) 24 Table 5-4. Summary ofVisibility Results for Alternative 3 (S02 Reduced to 0.15 Ib/MMBtu) 24 Table 5-5. Summary ofVisibility Results for Alternative4 (NOx Reduced with SOFA) 25 Table 5-6. Summary ofVisibility Results for Alternative 5 (NOx Reduced with SNCR) 25 Table 5-7. Summary ofVisibility Results for Alternative 6 (NOx Reduced to 0.15 Ib/MMBtu with SCR) 25 Table 5-8. Summary ofVisibility 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 datadescribed in the MontanaProtocol 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 ColstripPPL plant. Colstrip PPL plant is located eastofBillings, Montana.
On July 6, 2005 the US Environment Protection Agency amendedthe Federal Register document, 40 CFR Part 51 in orderto introduce new National Regional Haze Regulations for BestAvailable 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 ofa visibility-impairing air pollutant, were put in place between August 7, 1962 and August 7, 1977 and whose operations fall within one or more of26 specifically listed source categories, ofwhich 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 ofcontrol ofBART, States are required by section 169A(g) ofthe CAA to consider; (a) the costs ofcompliance, (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 ofthe source and (e) the degree ofvisibility improvement which may reasonably be anticipated from the use ofBART.
The purpose ofthe modelingwas to assess the visibility impacts ofsulfur dioxide (S02), nitrogen oxides (NOx) and primary particulate matter (PM) emissions (including primary sulfuric acid, H2 S04, 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 ofthe modeling domain includes areas ofcomplex terrain. There is the potential for terrain effects, both on the meteorological fields and in terms of plume-terrain interaction

Introductioneffects. 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 GuidelineModel for Class Iimpactassessments 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 ofterrain effects such as slope flows, terrain blocking effects, and kinematic effects. Meteorological observations were used to determinethe 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 ofthe wind fields. The horizontal resolution ofdata 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.), chemicaltransformation, 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 theClass Iareas. In Montana Protocol, Table 3.0 lists the versions ofthe CALMET, CALPUFF, POSTUTIL and CALPOST codes to be used in the modeling. The Protocol also states that "ifnew and improved versions become available, the MDEQ will apply those versions and document the changes". In June 2007, EPA has approved the new version ofCALPUFF 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 ofthe 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 ofthe 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 ofthe National Park Service. The particulate matter was modeled using the geometric mass mean diameter of0.4 micrometers (11m) and geometric standard deviation of2 Ilm.
Stack parameters for modeling were based on full load operation. Table 2-1 summarizesthe stack parameters and emissions, while Table 2-2 summarizes the particulate speciation for the present emission case. Table 2-3 summarizesthe emissions and particulate speciation for the base case and seven control alternatives evaluated. Each control alternative is relatedto a single pollutant emission reduction.

3 Source Description

### Figure 2-1. Aerial photo ofthe 

### PPL Colstrip facility

4 Source DescriptionI 

### Table 2-1 Colstrip: Source Parameters and EmissionRates

- Base Case
Stack Lambert Conformal Coordinatesl Stack Height Base Elevation Diameter GasExit Velocity Stack Gas Exit

Temp. SOz Emissions Hz S04 Emissionsz NO. Emissions PMIO EmissionsJ 10# LCCEast LCC North km km m m m m/s K Ib/hr 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 1798.0 338.45 Unit 2 823.930 185.598 152.4 988.0 5.0292 28.44 367.3 2828.0 118.47 1955.0 374.13

I The LCC projection is based on standard parallelsof45.0 Nand49.0N. an origin latitude and longitude of 44.25Nand 109.5 W. false eastingis 600 km, and datum NAD83. 2 H2S04 emissions are entered in CALPUFF as S04 i.e., weighted by ratio ofmolecularweights (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 PMIO condensable PMIO organic Hz S04 condensable (OC) M1=0.48, SD1 =2.0Jim COARSE Soil M 1=0.48, SD1=2.0 Jim Elemental Carbon (EC)
% 0/0 Ib/hr Ib/hr Ib/hr Ib/hr Ib/hr Unit I 55.3 44.7 30.26 121.05 53.47 128.73 4.95 Unit 2 60.4 39.6 29.62 118.47 64.58 155.48 5.97
Mand SO stand torGeometric Mass Mean Diameter and Geometric Standard Deviation. These are the parameters used to calculate the particle size distribution in CALPUFF.

5 Source Description

### Table 2-3 Colstrip: Emissions for Base Case and Control Alternatives Stack 10# Condensable Filterable S02 Emissions NO. Emissions PMIO Emissions3 organic condensable (OC) H2 SO4 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 Alt2

### = S02 control efficiency increased to 91

### % with lime injection. Control Alt 3 = 

### S02reduced to 0.15 Ib/MMBtu by adding an additional scrubbervessel. Control Alt4 = 

### NOxreduction with SOFA. Control Alt 5

## =NOxreduction with SNCR. Control Alt 6 = 

### NOxreduction to 0.15 Ib/MMBtu with SCR. Control Alt 7

### =Filterable PM reduced to 0.015 Ib/MMBtu.

6 SourceDescription

### 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 oflatitude 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 ofI-degree DEMs.
One degree DEM data consists ofan array of 1201 by 1201 elevations referenced on the geographic (latitude/longitude) coordinate system ofthe World Geodetic System 1972 Datum. Elevations are in meters relative to mean sea level, and the spacing ofthe elevations along each profile is 3 arc-seconds, which corresponds to a spacing ofapproximately 90 meters. The CALMET computational domain was designed to cover an area of780 km by 570 km (Figure 3-1). Itincludes Colstrip and all Class I areas within 300 km from it. These Class Iareas 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 Iareas within 300 km of it. The domain includes an adequate buffer ofmore than 50 km in all directions from each ofthe two facilities and each of the Class I areas. A horizontal resolution of 2km was used to represent the variations ofthe 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 ofMontana and parts offive neighboring states, since that modeling domain was intended tobe used for 10 BARTeligible 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 ofgrid cells. In addition, domain was extended to the south to include complete set ofreceptors in Yellowstone, Washakie and Teton Class Iareas. Figure 3-1 shows contours ofthe 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 ofthe important terrain features and valleys associated with the Class I areas and the surrounding area are capturedby the 391 x 286 grid cells, a workable number ofcells. 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 GeophysicalandMeteorological Data450

400

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Terrain 300 (meters) 4500 3900 250 3700 NO 3500 3300 3100 

## i 200 2900 2700 OJ 2500 2300 

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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) at2 km resolution for the 780km by 570km CALMET and CALPUFF computational domains. The Class Iareas andthe Colstrip facility are also shown. 1050 1100

8 GeophysicalandMeteorologicalDataUL 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 ofdominant Land Use categories. The Land Use data for the analysis were obtained in Composite Theme Grid (CTG) format from the USGS, with aresolution of200m. 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 leafarea index were computed proportionally to the fractional land use. The 14 CALMET land use categories are described in the MontanaProtocol. Figure 3-2 showsthe 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 ofwind 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 ofvertical profiles ofwind 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 ofobservational and modeled data available that are used in the modeling. A total of60 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 wetdeposition 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 200I and 5from 2002 and 2003 from the original SURF.OAT file were notfound in any of ISHWO or METAR databases. The records from theses stations were extracted from the original SURF.OATfiles and added to the new ones (first eight stations listed in Table 3-4).

9 GeophysicalandMeteorological Data100 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



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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 CALMETand CALPUFF modeling domains. Class Iareas andthe location ofColstrip PPL are also shown.

10 GeophysicalandMeteorological Data

### Table 3-3 Meteorological Data Sources and Parameters Available TypeofDataset Frequency Source Parameters

Surface observations Hourly NWS

Modeled Profiles MM5 for 200I, 2002 and 2003 Hourly WRAP Wind speed, wind direction, temperature, ceiling height, cloud cover, relative humidity, surface pressure, precipitationtype Hourly, gridded fields of winds, temperature, pressure, and humidity and liquid watercontenton 36 km grid for 2003, 2004 and 2005.

II GeophysicalandMeteorological Data

### Table 3-4

...........................................................................................NWS Hourly Surface Stations WMO WBAN StationName State Latitude Longitude CALL ID LCCX I LCCyl (deg.) (deg.) (km) (km) Colstrip region MT 46.90 -103.40 TH28 824.377 178.618 BorderofWY & 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 BorderofID & MTclose to KSMN ID 45.10 -113.50 SA32 1064.318 312.121 GlacierWA 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 CASPERNATRONA 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 (AWOS) WY 43.60 -110.73 KJAC 500.578 -71.50I 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 -29.90I 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 GREATFALLS 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 of45.0 Nand 49.0 N, an origin latitude and longitude of44.25 Nand 109.5 W, false easting is 600 km, and datum WGS-84. Available for year 200I only

12 GeophysicalandMeteorologicalData 2KaTF 

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..' • 800 kin, Fnorth • 0 km LATo·44.2!N, LANo. 109.5W**-200~** - - "l - - : - - r - - ,- - - 1-
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- - 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 shownthe stations included in theoriginal SURF.DAT files. Asthefigure shows bettercoverageofthe domain is achieved by using the ISHWO database.

13 GeophysicalandMeteorologicalData

### 3.4 AirQuality 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 ofthese 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 ofMontana background ammoniaconcentrations and the EPA concurs. These ammoniabackground concentrations, shown in Table 4.3.2 ofthe MontanaProtocol were used in the CALPUFF modeling.

14 GeophysicalandMeteorological Data550 L I .L 1 J. 1

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# •

·50**1602~0101** 50

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

15 GeophysicalandMeteorological Data

### Table 3-5

................................................................................................................... Ozone Stations Station ID Latitude(deg.) Longitude(deg.) Land use Setting Site name 160230101 43.46 113.56 BlightedAreas Rural 300298001 48.51 114.00 Agricultural Rural GlacierNational Park 380070002 46.89 103.37 Agricultural Rural Painted Canyon 380130004 48.64 102.40 Agricultural Rural LostwoodNwr 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 BeulahNorth 380650002 47.19 101.43 Agricultural Rural Hannover 460711001 43.75 101.94 Agricultural Rural 461030016 44.06 103.21 Residential Urban NearRobinsdale School 560050123 44.67 105.29 Desert Rural 560391011 44.57 110.40 Forest Rural Nearthe WaterTowerofHwy98 560358001 42.93 109.79 Forest Rural FreemontLake South, WV

16 GeophysicalandMeteorological Data

### 4.0 AIRQUALITYMODELINGMETHODOLOGY
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 DomainConfiguration CALMET and CALPUFF use terrain-following coordinates. The modeling domain consists of391x286 grid cells, uniform in the horizontal with a spatial resolution of2 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 ofthe 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 ofthe 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 ofzero 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 datawere available for years 2001-2003 with a horizontal grid spacing of36 km and 34vertical levels. Step 1 Field: Terrain Effects
In developing the Step I wind field, CALMET adjusts the initial guess field to reflect kinematic effects ofthe terrain, slope flows and blocking effects. Slope flows are a function ofthe local slope and altitude ofthe nearest crest. The crest is defined as the highest peak within a radius TERRAD around each grid point. Forthe domain used to perform the modeling, a value ofTERRADof 15 km was used. This value has been recommended by MDEQ in the Montana Protocol and is considered appropriate for this modelingdomain. The Step I field produces a flow field consistent with the fine-scale CALMETterrain resolution (2 km). Step2 Field: ObjectiveAnalysis
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 ofinfluence (parameters RMAXI at the surface and RMAX2 aloft). Observations and Step I field are weighted by means ofparameters RI at 

### 17 AirQualityModelingMethodologythe 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 setto 40 km and 100 km, while R I and R2 were setto 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 ofat least 50 km from the source and beyond the borders ofthe Class I areas. This minimizes the edge effects and allow pollutants involved in flow reversals to be brought back intothe Class I areas. CALPUFF was run for threeyears, 2001,2002 and 2003.
The receptor locations along with receptor elevations were available from the National Park Service (NPS). The distribution of the receptors within 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 ofreceptors for these Class I areas was included. 

### 4.5 Dispersion Modeling Options The CALPUFF simulations were conducted usingthe following model options:



### - Gaussian near-field distribution

- Transitional plume rise

- No building downwash

- Pasquill-Gifford (PG) dispersion coefficients (rural areas) and

McElroy-Poolercoefficients (urban areas)

- Transition ofO"y 

### to time-dependent (Heffter) growth rates

- Partial plume path adjustmentforterrain

- Wet deposition, dry deposition, andchemical transformation usingthe

MESOPUFF II scheme.

- Regulatory option used

Two important computational parameters in CALPUFF are XMXLEN (maximum length ofan emitted puff, in grid units) and XSAMLEN (maximum travel distance ofa puff, in grid units, during one time step). Both ofthese 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 ofan emitted puffdoes 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 thetravel distance during one time step does not exceed the grid size.
18 AirQuality Modeling Methodology380 100 L , , , , , 

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19 AirQualityModeling Methodology 

### lThe partial plume path adjustment option was used in CALPUFF for this analysis (MCTADJ=3). The CALMET wind field incorporates the effect ofthe 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 forthis 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 ofPM 10, (PMF, PMC, EC, and SOA). Ofthese 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 duringthe 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 postprocessingsteps. 4.6 Visibility Calculations Calculations ofthe impact ofthe 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 componentconcentrations. Usingthe notations ofCALPOST,the formula is the following: 

### Bext 

### = 3f(RH)[(NH4)2S04] 

### +3f(RH)[NH4 N03] 

### + 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 ofcondensable 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 of0.4**~m** and geometric standard deviation of2 11m.
The haze index (HI) is calculated from the extinction coefficient viathe following formula: HI

### = 10 In(bext/lO)

20 AirQualityModeling Methodologywhere HI is in units ofdeciviews (dv) and bext is in Mm- I

. The impact ofa source is determined by comparing HI for estimatednatural background conditions with the impact ofthe source and without the impact ofthe source. CALPOST Method 6 was used to compute the extinction change in deciviews consistent with the procedures outlined in the MontanaProtocol. 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 suitableto represent background light extinctionfor all particulates (hygroscopic 

### + non-hygroscopic) atthe same time when multiplied by an extinction coefficientofone. A monthly background concentration must be entered into the CALPOST input control file for all aerosols definingthe background. The 20% best days for each ofthe 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 Guidancefor Estimating Visibility Conditions Under the RegionalHaze Program (U.S. EPA, 2003) and MontanaProtocol are shown in Table 4- I.Table 4-2 provides the monthly f(RH) values based on the representative IMPROVE site location ofthe Class I areas as required for application of Method 6. The monthly f(RH) values for each month are extracted from Appendix A ofGuidancefor EstimatingNatural Visibility Conditions UndertheRegionalHaze 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 AirQuality Modeling Methodology

### Table 4-1 SummaryofBackgroundNatural 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: GuidancejorEstimatingNatural Visibility Conditions Under the RegionalHaze 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 Iarea 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 YellowstoneNP 2.5 2.3 2.2 2.\ 2.1 1.9 1.7 1.6 1.8 2.\ 2.4 2.5 Source: GuidancejorEstimatingNatural Visibility Conditions Under the RegionalHaze Rule (2003), AppendixA



### 22 AirQualityModelingMethodology

### 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 ofthe 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 ofchange in deciview (dv) for each ofthe five Class I areas, consistent withthe 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, withthe other pollutants modeled at theirbase case emissions.



### 23 AirQualityModelingAfethodology

### Table 5-1.. Summary ofVisibility Results for Base Case
Class I Area Minimum Distance (km) 2001 2002 2003 98th percentiledelta-deciview UL Bend 200 1.880 2.124 2.233 North AbsarokaWA 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 ofVisibility Results for Alternative 1(S02 Control Efficiency Increased to 88%)
Class I Area Minimum Distance (km) 2001 2002 2003 98th percentiledelta-deciview UL Bend 200 1.537 1.524 1.811 North AbsarokaWA 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 ofVisibility Results for Alternative 2 (S02 Control Efficiency Increasedto 91%)
Class I Area Minimum Distance (km) 2001 2002 2003 98th percentiledelta-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 ofVisibility Results for Alternative 3 (S02 Reducedto 0.15 Ib/MMBtu)
Class I Area Minimum Distance (km) 2001 2002 2003 98th percentiledelta-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 YellowstoneNP 281 0.503 0.677 0.320



### 24 AirQuality Modeling Methodology

### Table 5-5 Summary ofVisibility Results for Alternative4 (NOx 

### Reduced with SOFA)
Class I Area Minimum Distance (km) 2001 2002 2003 98th percentiledelta-deciview UL Bend 200 1.586 1.557 1.781 North Absaroka WA 254 0.534 1.280 0.805 Theodore RooseveltNP 260 1.426 1.613 1.305 Washakie WA 278 0.972 0.929 0.560 YellowstoneNP 281 0.619 0.844 0.460



### Table 5-6 Summary ofVisibility Results for Alternative 5 (NOx 

### Reduced with SNCR)
Class I Area Minimum Distance (km) 2001 2002 2003 98th percentiledelta-deciview UL Bend 200 1.554 1.492 1.713 North AbsarokaWA 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 ofVisibility Results for Alternative 6 (NOx 

### Reducedto 0.15 Ib/MMBtu with SCR)
Class IArea Minimum Distance (km) 2001 2002 2003 98th percentiledelta-deciview UL Bend 200 1.456 1.298 1.584 North AbsarokaWA 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 ofVisibility Results for Alternative 7 (Filterable PM Reducedto 0.015 Ib/MMBtu)
Class I Area Minimum Distance (km) 2001 2002 2003 98th percentiledelta-deciview UL Bend 200 1.856 2.090 2.213 North AbsarokaWA 254 0.644 1.541 0.971 Theodore RooseveltNP 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 AirQualityModeling Methodology

### 6.0 REFERENCES
FLAG, 2000. Federal Land Manager' AirQuality 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 Guideforthe CALPUFF DispersionModel (Version 5). 

### Earth Tech, Inc., Concord, MA Scire, J.S., F.R. Robe, M.E. Fernau, and RJ. Yamartino, 2000b:

### A User's Guidejorthe CALMETMeteorologicalModel (Version 5). 

### Earth Tech, Inc., Concord, MA. U.S. Environmental ProtectionAgency (EPA), 1998: Interagency Workgroup on AirQuality 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 ProtectionAgency (EPA), 2003a: Revision to the Guideline on AirQuality Models: Adoption ofa Preferred Long Range TransportModel and Other Revisions; Final Rule. 40 CRF 51. 

### FederalRegister, April 15,2003,68,72, pp 18440-18482. U.S., Environmental Protection Agency (EPA), 2003b: 

### GuidancejorEstimatingNatural Visibility Conditions Under the RegionalHaze Program. EPA-454/B-03-005, September2003. U.S. Environmental Protection Agency (EPA), 2005: Regional Haze Regulations and Guidelinesfor BestAvailable Retrofit Technology (BART) Determinations; Final Rule, 40 CFR41. 

### FederalRegister, July 6, 2006, 70, 128, pp 39104-39172.

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