James M Parker Manager

- Compliance Services, Env PPL Montana, LLC 303 N. Broadway, Suite 400 Billings, MT 59101 Tel. 406.237.6932 Fax 406.237.6901 jmparker@pplweb.com PPL MONTANA",



### June 25, 2008 

# 0ubjectto 

# C· f" Laurel Dygowski 

# on IdentialityClaim Air Quality Planning and ManagementUnit US EPA

- Region 

### 8 1595 Wynkoop Street Denver, CO 80202-1129
Re: BestAvailable Retrofit Technology (BART), Colstrip Generating Stations
DearMs. Dygowski:
Enclosedplease find a revised paperversion ofPPL Montana's submittal ofa supplement to our August, 2007 BARTAnalysis for Units 1&2 ofthe Colstrip SteamElectric Generating Station. I 

### Permyrecent voice mail, the hardcopy report we previously sent you contained errors. Please discard the previous hard copy version ofthis report. The electronic version we sent you onJune 12,2008, is correct and matches this corrected paper version.
Please contact me at 406-237-6932 orReid Clemmer at 610-774-5475 with any questions.

James M Parker, PE Manager, Environmental Compliance Services
JMP/jmp enclosure

J Please note that this addendum contains information designated Confidential Business Information (CBI) which is entitled to protection against release to the public pursuant to 40 C.F.R. Section 2.203(b). This document should not bedistributed beyond its intended recipients (U.S. EPA Region 8 and any otherregulatory agency involved in the Colstrip BART determination) without providing PPLnotice and an opportunity to object. Upon request, PPLMontana could provide as CBI the Coal Unloading Facility Siting study and the Alstom, Inc. proposal referenced here.

# Addendumto PPLMontana's

ColstripBART Report

1

### .,h.;,;)111 

## \"0

# ConHdtntiality

# Claim 8

­

UHJ

....'" 

### Prepared for



# PPL Montana, LLC Billings, Montana

Prepared

### by 

# C'TRC 21 Griffin Road North Windsor, Connecticut 06095

Telephone 860-298-9692 Facsimile 860-298-6399

TRC Project No. 160158



### June 

### 2008

### EXECUTIVE SUMMARY
On January 28,2008 EPA Region 8 provided PPL Montana (PPL) with comments on the Best Available Retrofit Technology (BART) Assessment for Colstrip Units 1&2 that PPL submitted on August 8, 2007. A copy of the EPA letter is provided in Appendix 

### 1. This Addendum to that report responds to those comments and provides additional analyses as needed.The Colstrip power plant, is located in Colstrip, Montana, is jointly owned by Puget Sound Energy and PPL Montana, LLC and is operated by PPL Montana, LLC. Units 1&2 were determined to be BART-eligible under the Federal Regional Haze Rule by the U.S. Environmental Protection Agency Region 8. They are electrical generation units (333 MW each) that bum sub-bituminous coal. The initial BART analysis by PPL and TRC estimated costs for the control technologies evaluated based on typical emission rates representative ofa 30-day average. In this addendum the costs are evaluated for both the typical emission rates and the maximum 24-hour emission rates based on data during the modeling years (2001, 2002 & 2003). EPA had requested that PPL provide this additional cost evaluation. Even though PPL believes that the actual cost effectiveness should be based on a longer time basis utilizing typical emission rates (30-day average at a minimum) and that a shorter time basis and maximum emission rates are not representative ofsite-specific cost effectiveness, we are providing the 24-hour cost calculation as requested. For the initial BART analysis, visibility predictions were made at Class I areas within 300 km ofthe Colstrip plant with the EPA's CALPUFF model. These are the UL Bend National Wildlife Refuge (200 km to the to the northwest), the North Absaroka Wilderness Area (254 km to the west), the Theodore Roosevelt National Park (260 km to the northeast), the Washakie Wilderness Area (278 km to the southwest) and Yellowstone National Park (281 km to the west). For this addendum, visibility impacts were estimated by interpolation and extrapolation ofthose modeling results. Visibility estimates were made for maximum 24-hour emission rates only. In addition to conducting cost analyses for maximum 24-hour as well as typical emission rates, the following analyses were conducted for this addendum.

• Control costs were based on 15 years for S02 and 20 years for NOx, 

### ratherthan 11 

### years for both.

ES-l

### • The maximum NOx 

### control level with SCR was evaluated at 0.06 lb/MMBtu. The NSPS level of0.11lb/MMBtu was also evaluated. (Note that 

### PPL believes that the 0.06 lb/MMBtu control level may not even be appropriate for new sources, and that level ofcontrol has not been reliably demonstrated in a retrofit application

- in fact the typical control level specified in the NSR settlement cases was 0.10 lb/MMBtu.) • The maximum particulate control level was evaluated at 0.010 lb/MMBtu. • The NOx

### control level with SOFA was revised from 0.18 lb/MMBtu to 0.19 lb/MMBtu (typical) • The NOx 

### control level with SNCR was revised from 0.16 lb/MMBtu to 0.15 lb/MMBtu (typical) • Fuel switching to lower sulfur coal was evaluated. • There is an expanded discussion of

- Fuel switching and coal cleaning options for SOz control Transferal ofenergy impacts associated with SOz control from Units 3&4 to Units 1&2.

- How SOFA costs at Units 3&4 were transferred to Units 1&2. Additional NOx 

### technologies.

- Venturi scrubber upgrades and operation.

- Cost documentation is provided in several sections ofthis addendum.
EPA's January 28, 2008 letter questioned whether 91% (0.15 lb/MMBtu) was appropriate

as the maximum SOz control efficiency or whether a higher efficiency was attainable. 

### PPL concluded that 91% was appropriate as an average efficiency and that higher efficiencies were attainable, but not on a continual basis. Even at a control level of91%, increased scaling ofthe scrubber vessels would reduce their efficiency and increase required down time for de-scaling. 

### In order to attain higher control efficiency on a continual basis it would be necessary to add a
new scrubber vessel. This option, in fact, was evaluated in the original BART submittal as a potentially more palatable option to reduce SOz emissions to the presumptive level of 0.15 lb/MMBtu (by having a spare vessel for de-scaling) than to attain that level with existing equipment only. 

### PPL has since concluded that because the units have existing equipment that is attaining greater than 50% removal efficiency, the BART guidelines only require that upgrades to existing equipment be evaluated and that purchase of an additional scrubber vessel is beyond BARTrequirements. Summaries of the cost and visibility analyses for all BART control levels evaluated, including the new levels evaluated in this addendum, are provided in Tables ES-l, ES-2 and ES3. The cost evaluations in Table ES-l are based on typical emissions representative ofa 30-day average and the cost evaluations in Table ES-2 are based on maximum 24-hour average emissions. The costs are presented both relative to the present emissions and incrementally from

one level ofcontrol to the next. The visibility impacts ofthe present emissions and the control ES-2

### alternatives based on maximum 24-hour emissions are provided in Table ES-3, both relative to the present emissions and incrementally. The visibility impacts are provided based on modeled predictions for any emissions levels that were modeled and otherwise based on interpolated or extrapolated values. The additional analysis provided in this addendum does not change the conclusion that 

### PPL reached in its August 2007, BART Assessment for Colstrip Units I & 2, that implementation offurther controls is not warranted.

ES-3

### Table ES-l: Control Costs Summary

- Typical30-DayAverage Emission Rates

TABLE ES·1 •CURRENT I NSPS I CONTROL OPTIONS COST SUMMARY FOR THE PPL MONTANA, LLC, AVERAGE OF COLSTRIP UNITS 1&2

- 30-DAY AVERAGE EMISSIONS BASIS**l~urrent<l)** Emission rate Particulate Matter Sulfur Dioxide Nitrooen Oxides Rate I Units

0.0525 IblMMBtu Rate I Units
0.4 IblMMBtu I Rate I Units Control
0.35 IblMMBtu COFA(l)
BD1O) from 

### I 2006 NSPS 0.015 IblMMBtu 1.4 Ibs S02/MWout 1.0 IblMW out New Sources (0.15 IblMM Btu in (0.11 IblMM Btu in Cost Effeci<eness Calcs Cost Effeciveness Calcs Option Evaluated Rate Option Evaluated Rate cE<8) Incremental from Present) cE<7) Option Evaluated Rate cE<8) Incremental (fromPresenl)**C~** IblMMBtu $Iton IblMMBtu $Iton $/ton IblMMBtu $Iton $lton Control Present 00525 Present 0.4 Present 0.35 Options FF 0.015 $24,270 Fuel Switch 0.23 $10,258 SOFA 0.19 $437 FF 0.010 $21,420 'NS-FGI14) 0.2 $209 SNCR 0.15 $005 $2,n8 ESP 0.015 $29,E09 WS-FG[j5) 0.15 $486 $1593 scR<.8) 0.11 $1,942 57,127 ESP 0.010 $26 307 scR<.8l 006 $1735 $3.579 Notes 1) Colstnp Average Flnerable EmiSSions ofO.0525lb1MMBtu used as representatIVe of each Unit, FF=Fabric Finer, ESP = Electrostatic Precipitator Ohese costs represent incremental costs only because to attain these emission rates, replacement ofthe current wet scrubbers would be required) 2) Low-NOx Bumers with Close-Coupled Overfire Air· new SOFA is an upgrade to present equipment 3) BOT = "Best Demonstrated Technology"

- From FR Vol. 71, No. 38, Monday, February 27,2007

Final Rule (NSPS for EUSGUs)

- the 2lJ(E re";sed standards were re-.ised to a gross megawatt output basis (equivalent in IblMMBtu input values listed in paren) 4) Wet Scrubber-Flue Gas Desulfurization; actual emissions are 0.40 IbsIMMBtu (per CEMS • :D-day average); adding lime to the scrubberwill reduce emissions by an additional 50% (overall 88% reduction of inlet) 5) Similar to 3 but additional lime added with downtime due to scaling to attain a reduction to 0.15 IbsIMMBtu (overall 91 % reduction); 6) Control options considered separately; incremental cost of S02 scrubbing options compares the cost to the baseline emissions; for NOx, each option compares the cost to the current system 7) Incremental cost ofwet scubbing options reflect the additional cost to attain the lower level of emissions; SNCR incremental cost compares the SNCR cost to the cost of SOFA; both SCR options compare to SNCR 8) This represents control to the new source NSPS level; incremental cost is compared to SNCR 9) This represents a hypothetical maximum control case; incremental cost is compared to SNCR



### ES-4

### Table ES-2: Control Costs Summary

- Maximum 24-Hour Emission Rates

TABLE ES..z

- CURRENT I NSPS I CONTROL OPTIONS COST SUMMARY FOR THE PPL MONTANA, LLC, AVERAGE OF COLSTRIP UNITS 1&2

-24-HR AVERAGE EMISSIONS BASIS Particulate Matter Sulfur Dioxide Nitrooen Oxides Rate I Units Rate I Units Rate I Units Control Current(l) Emission rate COFA(2) 076 IblMMBtu 0.49 IblMMBtu 0.0525 IblMMBtu
B01O) from 

### I 2006 NSPS 0.015 IblMMBtu 1.4 Ibs**S~IM'N** out 1.0 IbIMW out ro.15 IblMM Btu in New Sources ro.ll IblMM Btu inCost Effeciveness Calcs Cost Effeciveness Calcs Option

Control Options Present Added FF Added FF Added ESP Added ESP CElli) CElli) Option Evaluated Incremental Incremental Evaluated Option Evaluated CE(7) IblMMBtu (fromPr_) Rate (from Present) Rate**C~** Rate $lion $lion $lion IblMMBtu $lion $Ilon IblMMBtu Present 0.0525 076 Present 0.49 $24,270 $321 Fuel Switch 0.445 $5,943 SOFA 0.015 0.266 WS-FGO<4) $21,420 0.38 $121 $852 $2,976 0.010 SNCR 0.21**WS-FGO<~)** scRl1') $29,809 0.285 $923 0.154 $1,565 $5,132 0.015 5282 $26 307 $1 412 $2657 0.010 0.084**SC~** Notes 1) Colstnp Average**FI~erable** EmiSSions of0.0525 IblMMBtu used as representatIVe of each umt; FF=Fabric Filter, ESP = Electrostatic Precipitator (these costs represent incremental costs only because to attain these emission rates, replacement ofthe current wet scrubbers would be required) 2) Low-NOx Burners with Close-Coupled Overfire Air

- new SOFA is an upgrade to present equipment 3) BOT= "Best Oernonstrated Technology'

- From FR Vol. 71, No. 38, Monday, February 27,2007

Final Rule (NSPS for EUSGUs)

- the 20E revised standards were revised to a gross megawatt output basis (equivalent in IblMMBtu input values listed in paren) 4) Wet Scrubber-Flue Gas Desulfurization; actual emissions are 076 Ibs/MMBtu (per CEMS

- 24-hr worst-case); adding lime to the scrubberwill reduce emissions by an additional 50% (overall 88% reduction of inlet) 5) Similarto 3 but additional lime added with downtime due to scaling to attain a reduction to 0.15 Ibs/MMBtu (overall 91 % reduction); 6) Control options considered separately; incremental cost of S02 scrubbing options compares the cost to the baseline emissions; for NOx, each option compares the cost to the current system 7) Incremental cost ofwet scubbing options reflect the additional cost to attain the lower level of emissions; SNCR incremental cost compares the SNCR cost to the cost of SOFA, both SCR options compare to SNCR 8) This represents control to the new source NSPS level; incremental cost is compared to SNCR 9) This represents a hypothetical maximum control case; incremental cost is compared to SNCR



### ES-5

### Table ES-3: Estimated Visibility and Visibility Improvements

ESTIMATEDVISIBILITYANDVISIBILITY IMPROVEMENTS 

### T ' J Filterable Particulate 8uWur Dioxide Nitrogen Oxides Estirmted l"1lroverrent (7) Estirmted ! Irrproverrent (7) Estirrated l"1lroverrent (7) f Option**Rat~(1)(22** (lbffv'tlBtu)**~ediction** (3) (deciviews)**f_f~om** _**~esent** Inc (6) Option**f':at~(D~2rcF!~di~ti~n** __ from (lbfMvlBtuj[deciviews**~esent** nc (6) _ Rate(1)(2 Option IbfMvlBtu**~edicti~n** deciviews from f _**~esent** Inc (6)**~esent** 0_0525 2233 nfa nfa**~esent** 0_76 2233 nfa nfa**~esent** OA9 2233

----­ -­ - ------'--f"-"---­ f------' ,,- ,--- ,--­ fESPfFF 0_015 2213 0_042 0_042**~~:~c>~4)** 0_38 2_000 OA22 OA22 SOFA 0266 1-811 IESP/FT­ 0_010 2210 0_048**"_~:006 W~-.F'C>D(5**  0285 1-954 0_5440122 SNCR 021 1_672 Fuel8W OM5 2_04 0_35 0_35 8m 0_ 154 1-591 -"

- ---­ 8m 0_084 1A58 0_535 0_535 0_677 0_142 0792 0_115f0_956 0_164

nfa nfa

1____

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__,_ .. ----.'

- -- --.J.___ ., '­

_ L

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... __ •.
__ . . __ __ " . - ,,'-

.. - . _ .. i _

Notes:, (1) The ennssion rate is the rate corresponding to the rmximumdaily ennssions during the modeling years (2001-2003).


### ....-. -1--, 

### (scaleci"bythe-expeciedconiroll.,-tf;cienCY'iorconirolaliernali

## vesT-:-------;'-'-----­ '--T" :

.**,~--,,-,** -_..}" (2r-Average'eniss'iCin'**"r'ate-s""beiwee'nTif'lts--f&2IfUilli"'-1-'a";;'dTfnif2Eirriss "iO'n-'r~ites-**  

### are"'dffferenffh'ey·**are~in(iic'ated ~s** **-Ul'~-11li1lt** 2rates
. 

## .i -**(3)Ftedic~onlsfrom-aj["itiree** 

### polluiil-nlSalpreseniemssiQ-ns-ex-cepiihe"onebeTngcontroiil.ld'---, T (4)S02ems-sionsreduced-by

### 88%.­ T",

..., 

### T -T--­ --, ,,­ (5) 

### s02enisslonsreducedtly 910/; i ' • -(6) In,;;;in'cren-entaCj ," 1 - 

### i . i , .

- (7) Max'irrum-irilJroverrents show'n rmy occur at different Oasslareas thanthe rrBximum prediction amongall Class Iareas. -'

-­



### ES-6

### TABLE OF CONTENTS

EXECUTIVE SUMMARY ES-I 1.0 INTRODUCTION I-I 2.0 COLSTRIP UNITS 1&2 2-1 2.1 Operation 2-1 2.2 Emissions 2-1 3.0 EVALUATION METHODOLOGY 3-1 3.1 Cost Analyses 3-1 3.2 Visibility Estimates 3-1 4.0 SUPPLEMENTARY S02 EVALUATIONS 4-1 4.1 Maximum S02 Control Level with Present Equipment

. .4-1 4.2 Evaluation ofCoal Cleaning and Fuel Switching Options 4-3 4.2.1 Coal Cleaning 4-3 4.2.2 Fuel Switching 4-4 4.3 Evaluation ofVenturi Scrubber Upgrades for S02 Removal

.4-5 5.0 SUPPLEMENTARY NOx 

### EVALUATIONS 5-1 5.1 SOFA 5-1 5.2 SNCR 5-2 5.3 SCRNOx 

### Control Level. 5-4 5.4 Other NOx 

### Control Options 5-7 6.0 SUPPLEMENTARY PARTICULATE EVALUATIONS 6-1 6.1 Present Venturi Scrubber Operation for Particulate Removal. 6-1 6.2 Evaluation ofParticulate Control to 0.0I Ib/MMBtu 6-1 7.0 SUMMARY OF ALL COST ANALySES 7-1 

### 8.0 SUMMARY OF ALL VISIBILITY ESTIMATES 

### 8-1 9.0 SUMMARY 

### 9-1 10.0 REFERENCES 10-1

### TABLE OF CONTENTS continued

LIST OF TABLES Table ES-I: Control Costs Summary

- Typical30-Day Average Emission Rates ES-4

Table 3-2: Parameters for Interpolation and Extrapolation ofVisibility Estimates

Table 8-1: Maximum Overall 98thPercentile Visibility Estimates Among All Class 1Areas

Table 8-2: Maximum 98th Percentile Visibility Differences Among All Class I Areas Table ES-2: Control Costs Summary

- Maximum 24-Hour Emission Rates ES-5 Table ES-3: Estimated Visibility and Visibility Improvements ES-6 Table 1-1: EPA January 28, 2008 Comments 1-3 Table 2-1: Present (Base Case) SOz and NOx 

### Emissions 2-3 Table 2-2: Colstrip Base Case Particulate Emissions, Type and Size Speciation 2-4 Table 3-1: CALPUFF Visibility Modeling Results from the August 2007 BART Report 3-2
(Approach 1) 3-3 Table 7-1: Control Costs Summary and References 7-2

Evaluated and Corresponding Differences Between Control Cases 8-2

Evaluated 8-3 Table 9-1: Control Costs Summary

- Typical30-Day Average Emission Rates 9-1 Table 9-2: Control Costs Summary

- Maximum 24-Hour Average Emission Rates 9-2 Table 9-3: Estimated Visibility and Visibility Improvements 9-2

APPENDICES
APPENDIX 1 EPA REGION 8 COMMENT LETTER APPENDIX 2 DETAILED COST CALCULAnON TABLES

11

### 1.0 INTRODUCTION OnJanuary 28, 2008 EPA Region 8 provided PPL Montana (PPL) with comments on the Best Available Retrofit Technology (BART) Assessment for Colstrip Units 1&2 that PPL submitted in August 8, 2007. This Addendum to that assessment report(l) responds to those comments andprovides additional analyses as needed. EPA's letter is included as Attachment 1. The Colstrip power plant, located in Colstrip, Montana, isjointly owned by Puget Sound Energy and PPL Montana, LLC and is operated by PPL Montana, LLC. Units 1&2 were determined to be BART-eligible under the Federal Regional Haze Rule by the U.S. Environmental Protection Agency Region 8. They are electrical generation units (333 MW each) that bum sub-bituminous coal. The initial BART analysis by PPL and TRC estimated costs for the control technologies evaluated based on typical emission rates representative ofa 30-day average. Per EPA's request, in this addendum the costs are evaluated for both the typical emission rates and the maximum 24-hour emission rates based on data during the modeling years (2001, 2002 & 2003). Even though PPL believes that the actual cost effectiveness should be based on a longer time basis utilizing typical emission rates (30-day average at a minimum) and that a shorter time basis and maximum emission rates are not representative of site-specific cost effectiveness, we are providing the 24-hour cost calculation as requested. For the initial BART analysis, visibility predictions were made at Class I areas within 300 km ofthe Colstrip plant with the EPA's CALPUFF model. These are the UL Bend National Wildlife Refuge (200 km to the to the northwest), the North Absaroka Wilderness Area (254 km to the west), the Theodore Roosevelt National Park (260 km to the northeast), the Washakie Wilderness Area (278 km to the southwest) and Yellowstone National Park (281 km to the west). For this addendum, visibility impacts were estimated by interpolation and extrapolation ofthose modeling results. Visibility estimates were made for maximum 24-houremissionrates only. In addition to conducting cost analyses for maximum 24-hour as well as typical emission rates, the following analyses were conducted for this addendum.

• Control costs were based on 15 years for S02 and 20 years for NOx, 

### ratherthan 11 years for both. • The maximum NOx 

### control level with SCRwas evaluated at 0.06 Ib/MMBtu. The NSPS level of0.1 1Ib/MMBtu was also evaluated. (Note that PPL believes that the 0.06 Ib/MMBtu control level may not evenbe appropriate for new sources, and that

1-1

### level ofcontrol has not been reliably demonstrated in a retrofit application

- in fact the typical control level specified in the NSR settlement cases was 0.10 Ib/MMBtu.) • The maximumparticulate control level was evaluated at 0.0 1

## aIb/MMBtu. • The NOx 

### control level with SOFA was revised from 0.18 Ib/MMBtu to 0.19 Ib/MMBtu (typical) • The NOx 

### control level with SNCRwas revised from 0.16 Ib/MMBtu to 0.15 Ib/MMBtu (typical) • Fuel switching to lower sulfurcoal was evaluated. • There is an expanded discussion of

- Fuel switching and coal cleaning options for S02 control Transferal ofenergy impacts associated with S02 control from Units 3&4 to Units 1&2.

- How SOFA costs at Units 3&4 were transferred to Units 1&2. Additional NOx 

### technologies.

- Venturi scrubber upgrades and operation.

- Cost documentation is provided is several sections ofthis addendum.
Table 1-1 

### summarizes EPA's comments and references the sections ofthis addendum in which they are addressed. Section 2 of this addendum describes the Colstrip plant operation and Units 1&2 emISSIOns. Section 3 describes the methods used to evaluate costs and visibility impacts. Sections 4, 5 and 6 describe the supplementary S02, NOx 

### and particulate analyses conducted in response to EPA's January 28, 2008 letter. Sections 7 and 8 summarize all cost and visibility results

- those conducted for this addendum as well as those conducted previously. Section 9 presents the conclusions. PPL's originally submitted BART report(l) provides an additional description ofthe Colstrip BART analyses.

1-2

### Table 1-1: EPAJanuary 28, 2008 Comments Category Section(s) EPA Comment 4.1 

### l. Evaluate the Most Stringent Evaluate the Maximum Control S02 Level that the Technology Level with Lime injection General Comments is Capable ofAchieving Evaluate the MaximumNOx Control 5.2 Level with SNCR Evaluate the MaximumNOx Control 5.3 Level with SCR 7.0 2. Provide Proper/Additional Cost Documentation 3. Re-model Control measures Basedon 24-Hour Averages 8.0 4.1, 4.2, 7.0 4. Use a 15 Year Remaining Life for S02 Control Costs S02 5. Evaluate Fuel Switching and Coal Cleaning Options for S02 Control 4.2, Comments Attachment 2 6. Explain How Energy Impacts from Units 3&4 Were Translated to 4.1 Units 1&2 7. Provide an Analysis ofVenturi Scrubber Upgrades for S02 Control 4.3 5.1,5.2,5.3,7.0 8. Use a 20 Year Remaining Life for NOx Control Costs NOx 9. Provide a NOx Control Analysis to the Present NSPS Level 5.3 Comments 10. Provide Additional Information on How SOFA Costs at Units 3&4 5.1 Were Transferred to Units 1&2 

### II. Evaluate AdditionalNOx Control Technologies Such As ASOFA, 5.4 RRI and ROFA. 12. Correct Table 4-8(a) Typographical Error Appendix 2 Particulate 13. Explain Why the Existing 98% Particulate Control Level Cannot be 6.1 Comments Improved. 14 Evaluate Particulate Control to 0.0I Ib/MMBtu 6.2



### 1-3

### 2.0 COLSTRIP UNITS 1&2 2.1 Operation The Colstrip powerplant is a mine-mouth plant with four large electrical generating units that bum low sulfur (0.7% S), sub-bituminous northern Powder River Basin coal. Units 1&2 began commercial operation in 1975 and 1976 and were detennined by EPA Region 8 to be BART eligible. Units 3&4 began commercial operation in 1984 and 1986 and are not BART eligible. Units 1&2 are rated at 333 MW each. The furnaces are oftangential-fired design with a Low NOx 

### Concentric Firing (LNCFS) P2 system with close coupled overfire air (CCOFA). Originally, the units operated with a NOx 

### emission limit of 0.7 Ib/MMBtu, but in 1997 they adopted a 0.45 Ib/MMBtu annual limit as an early reduction under the Acid Rain Program. This level was reduced to 0.4 Ib/MMBtu in 2008. Nonnally, the units operate with a NOx 

### emission rate in the range of0.30 to 0.35 Ib/MMBtu, accomplished with the LNCFS P2 system, which is a 50% reduction from the initial NOx 

### limit. The units have a wet particulate scrubber that controls both particulate and S02 emissions. The design ofthe wet scrubber includes a venturi/plumb bob section with sprays to
remove particulate and S02, followed by a level ofabsorption sprays for additional S02 removal, followed by a wash tray section for both particulate and S02 polishing, followed by mist eliminators. The scrubbers utilize the alkalinity ofthe fly ash collected to remove the S02. The scrubbers are designed to have at least a 98% particulate control efficiency and operation ofthe equipment has shown particulate control efficiencies approaching 99.5%. They achieve a 75% to 80% S02 removal (depending on the alkalinity ofthe ash). The scrubbers are designed to treat 100% ofthe flue gas and there are no provisions for bypassing the scrubbers. There are 3 scrubber vessels per unit and all 3 vessels are required to be in operation for full load
on the unit.

2.2 Emissions The present (base case) sulfur dioxide (S02) and nitrogen oxides (NOx) 

### emissions for Colstrip Units 1&2 are presented in Table 2-1. Presented are both the typical emissions representative ofa 30-day average and the maximum daily emissions during the modeling years (2001,2002 & 2003). The emissions are based on certified CEM data.

2-1

### For this addendum, both the typical and maximum S02 and NOx 

### emissions were used for the cost analyses. As specified in the BART guidelines, the visibility modeling that was presented in the original, submitted BART report was based on the maximum daily emissions. Therefore, interpolation and extrapolation of those modeling results here is also based on the maximum daily emissions. The base case particulate emissions are presented in Table 2-2. They are presented in their filterable and condensable portions and further divided into organic and inorganic (H2S04) condensable fractions and coarse, soil and elemental carbon filterable fractions. The total filterable particulate emissions are based on the highest of the annual stack tests conducted during the modeling years. Speciation into coarse, soil and elemental carbon is based on guidance provided by the National Park Service(2). Stacktests for condensable particulate were not available during the modeling years. The total condensable emissions are based on EPA's AP-42 emission factor using a coal sulfur content of0.68 percent (the highest annual average during the modeling years). Speciation into organic and inorganic fractions is based on guidance provided by the NPS. The base case particulate emissions used for the BART analyses (both cost and visibility modeling) and presented in Table 2-2 are based on the emission rates as just described and the maximum daily average heat input rates during the modeling years. These heat input rates are 3981.8 Ib/MMBtu for Unit 1 and 3897.2 Ib/MMBtu for Unit 2. Since CEM data are not available for particulate, the typical and maximum emissions were not differentiated. The emissions presented in Tables 2-1 and 2-2 are the same as those presented and used in the original BART report.

2-2

### Table 2-1: Present (Base Case) S02 

### and NOx

### Emissions
Typical/30-day Average Maximum 24-HourEmissions Emissions Emissions Pollutant Unit Ib/MMBtu Ib/hr Ib/MMBtu Ib/hr

SOz Unit I 0.40 1592.7 0.72 2612.0 Unit 2 0.40 1558.9 0.80 2828.0 Avg 1&2 0.40 1575.8 0.76 2720.0 NO, Unit I 0.35 1393.6 0.45 1798.0 Unit2 0.35 1364.0 0.53 1955.0 Avg 1&2 0.35 1378.8 0.49 1876.5
NOTE: The maximum emission rates are the highest daily average emissions during the modeling years (2001-2003). These emissions were used for the visibility modeling. Cost analyses were conducted with both typical and maximum emission rates.



### 2-3'

# ... Table 2-2: Colstrip Base Case Particulate Emissions, Type and Size Speciation Category Unit 1 Unit 2 Total PM lb/hr 338.4 374.1 lb/MMBtu 0,085 0,096 Filterable(J) percentage oftotal 55.3% 60.4% lb/hr 187.1 226.0 lb/MMBtu 0.047 0.058 Condensable(2) 44,7% percentage oftotal 39.6% lb/hr 151.3 148.1 lb/MMBtu 0.038 0.038 Filterable(J) Coarse(3) 64,58 lb/MMBtu lb/hr 53.47 0.0166 SoilO) 0.0134 lb/hr 128.73 155.48 lb/MMBtu 0.0323 0.0399 Elemental lb/hr 4.95 5.97 Carbon(3) lb/MMBtu 0.0012 0.0015 Total lb/hr 187.15 226.03 Filterable(4) Ib/MMBtu 0.047 0.058 Condensable(2) Organic(3) 30,26 lb/hr 29.62 lb/MMBtu 0.0076 0.0076 Inorganic(3) lblhr 121.05 118.47 lb/MMBtu 0,0304 0.0304 (1) Based on stacktest data. (2) Based on AP-42. (3) Based onNPS guidance, (4) The average ofthe filterable particulate emissions between the two units are 0.0525 Ib/MMBtu and 206,61b/hr.



### 2-4

### 3.0 EVALUATION METHODOLOGY 3.1 Cost Analyses The control cost determinations were performed in general conformance to the EPA recommendations contained in the EPA Air Pollution Control Cost Manual, Sixth Edition, January 2002 (EPA-452-02-001) (CCM). Both a maximum 24-hr average emission rate and a 30-day average hourly emission rate were used to determine uncontrolled emissions to form the baseline for control technology reductions. Emissions associated with both ofthese averaging periods were also used for each ofthe control levels evaluated. For capital cost amortizations, a 7 percent per annum interest rate and a 15 year life for S02 controls and a 20 year life for NOx 

### controls were assumed. Where costing references are based on referenced dollar values, the costs were corrected to 2008 dollars using cost index calculations. For the determination of capital and operating costs for the PPL BART analysis of control alternatives, both vendor cost estimates and calculated costs were used. The S02 reductions include two levels of wet scrubbing by lime injection. For NOx 

### reductions, both combustion controls within the furnaces, and the add-on controls of Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR) were evaluated. Alstom Power Inc. provided a cost proposal for in-combustion NOx 

### controls that has been included in the option costing analyses. The guaranteed performance for the technology considered the older design of the Colstrip Unit 1&2 boilers with high heat release rates for the Powder River Basin (PRB) coal utilized. For SNCR and SCR control options, Section 4.2, "NOx 

### Post combustion" controls Chapter 1 "Selective Noncatalytic Reduction", and Chapter 2 "Selective Catalytic Reduction" formed the basis for capital and operating cost calculations. Equations from the CCM were used to estimate the costs for these alternate post-combustion chamber controls.

3.2 Visibility Estimates TRC conducted visibility modeling for the years of 200I, 

### 2002 & 2003 with the CALPUFF model to estimate Colstrip Units 1&2 impacts relative to present background levels in each of the Class I areas within 300 km of the Colstrip facility. These are the UL Bend National Wildlife Refuge, the North Absaroka Wilderness Area, the Theodore Roosevelt National Park, the Washakie Wilderness Area and Yellowstone National Park. This modeling
was conducted for present, base case emissions (maximum daily emissions) and each of the

3-1

### control options identified in PPL's BART report that was submitted to EPA Region 8 in August 2007. The methodology is described in detail in Appendix B of the report. The results are presented in the body of the report and in its Appendix B. The Units 1&2 emission levels modeled for that submitted report and the corresponding visibility predictions are presented in Table 3-1.

Table 

### 3-1: CALPUFF Visibility Modeling Results from the August 2007 BART Report

Pollutant Control Case Emission Rate (Ib/MMBtu) Visibility (Deciviews) SOz Base Case 0.76 2.233 Lime Injection (88%) 0.38 2.00 Lime Injection (91%) 0.285 1.954

New Vessel (91%) 0.15 1.832 NO. Base Case 0.49 2.233 SOFA 0.25 1.781 SNCR 0.225 1.713 SCR 0.15 1.584 PM Base Case 0.0525 2.233 ESP/Fabric Filter 0.015 2.213 Visibility estimates are the highest 98th percentile 24-hour CALPUFF predictions among the Class I areas evaluated. Several of the modeled S02 and NOx 

### emission rates for Colstrip Units 1&2 differ because they were based in part on historical CEM data that were not identical between units. The average of the two rates is presented in this table and was used for the interpolation and extrapolation.


### For the additional control levels identified in this addendum, visibility estimates are based on interpolation and extrapolation ofthe modeled estimates presented in Table 3-1. The modeled and interpolated/extrapolated values presented here are based on maximum 24-hour emissions perrecommendations in the BART guidelines. The change in visibility improvement (in deciviews) per change in emission rate (in Ib/MMBtu) between each ofthe modeled control levels (i.e., the slope) has been calculated and is presented in Table 3-2. The slope from the base case emission rate to the lowest emission rate evaluated is also presented in the table.

3-2>­ 

### Table 3-2: Parametersfor Interpolation and Extrapolation ofVisibility Estimates (Approach 1)

Pollutant Control Case Emission Rate Change (lb/MMBtu) Visibility Change (Deciviews) Slope for Extrapolation (Deciview per

Ib/MMBtu) S02 Base Case 0.76

- 0.38 2.233

- 2.00 0.61 mlllUS 

### = = Lime Injection (88%) 0.38 0.233 Lime Injection (88%) 0.38

- 0.285 2.00

­ 1.954 0.48 mlllUS 

### = = Lime Injection (91%) 0.095 0.046 Lime Injection (88%) 0.38

- 0.15 2.00

­ 1.832 0.73 minus 

### = = New vessel (91%» 0.23 0.168 Lime Injection (91%) 0.285

- 0.15 1.954

­ 1.832 0.90 mlllUS 

### = = New vessel (91%» 0.135 0.122 BaseCase 0.76-0.15 2.233

­ 1.832 0.66

minus 

### = = New Vessel (91%) 0.61 0.401 NO, Base Case 0.49

- 0.25 2.233

­ 1.781 1.88 minus 

### = = SOFA 0.24 0.452 SOFA 0.25

- 0.225 1.781- 1.713 2.72 mlllUS 

### = = SNCR 0.025 0.068 SNCR 0.225-0.15 1.713

­ 1.584 1.72 minus 

### = = SCR 0.075 0.129 Base Case 0.49

- 0.15 2.233

­ 1.584 1.91

mlllUS 

### = = SCR 0.34 0.649 PM Base Case 0.0525

- 0.015 2.233

- 2.213 0.53 mlllUS 

### = = ESPIFabric Filter 0.0375 0.020



### For the new control levels evaluated, interpolated visibility estimates are based on the visibility change per emission rate change (slope) for the interval between the closest modeled emission rates to either side the new emission rate being evaluated. For emission rates lower than the lowest emission rate evaluated previously, extrapolated values are based on the greater ofthe slope between the following two alternatives:
(I) slope from the base case emission rate to the lowest emission rate evaluated and (2) slope from the emission rate immediately preceding the lowest emission rate evaluated to the lowest emission rate evaluated.

3-3

### x As can be seen in the Table 3-2, the deciview (dv) change per Ib/MMBtu change varies for the different control level intervals. The interpolated visibility improvement in deciviews for the new control levels evaluated in this addendum will be calculated by the standard formula ofa straight line,

That is: y = 

### m x 

### + b, where
y 

### = the visibility for the new emission rate being evaluated. m = 

### the slope (dv change per emission rate change) for the selected interval as described above. x the emission rate difference between the new emission rate and the emission rate at the upper end ofthe selected interval (negative) b the visibility level at the upper end ofthe selected interval
The extrapolated (beyond the lowest modeled emission rate) visibility improvement will be estimated by the same method. But in this case,
the emission rate difference between the new emission rate and the emission rate at the

lowest previously modeled emission rate. b the visibility level associated with the lowest previously modeled emissionrate. y and m have the same meanings as above. Interpolation or extrapolation was conducted using the deciview and deciview per Ib/MMBtu values presented in Table 3-2 that are based onthe maximum 98th 

### percentile visibility predictions for the base case and control levels modeled among all Class I areas evaluated. This method was previously described to EPA. An alternative approach to obtain deciview and deciview per Ib/MMBtu values was also conducted based on the maximum differences between predicted 98th 

### percentile predictions for the base case and control alternatives from among all Class I areas evaluated. This approach generally provided larger deciview differences than the other approach. The visibility estimates and cumulative and incremental differences are presented for both approaches in Section 8 and the higher levels of visibility improvement between the two approaches are used in the discussions and summary tables ofthis addendum. The deciview per Ib/MMBtu values for the interpolation and extrapolation visibility estimates by the first approach are provided in Table 3-2 and provide a demonstration of the approach used. The values by the second approach are more voluminous because there are separate values for each Class I area, but are available upon request. The 98th 

### percentile modeled

3-4

### visibility levels for each Class I area from which the interpolation/extrapolation values are based

are presented Appendix B ofthe originally submitted BART report(I).

3-5

### 4.0 SUPPLEMENTARY**SO~** 

### EVALUATIONS 4.1 Maximum 

## sal. Control Level with a New Lime Injection System PPL evaluated installation ofa lime injection system for Units 1 and 2. While it is not clear from the BART guidelines (July 2005 pg 39171) that installation ofa lime injection system is an upgrade that should be evaluated for units that already have better than 50% reduction S02 controls, PPL evaluated this option nonetheless. Based on the performance ofthe Colstrip Units 3&4 wet scrubbers, which are similar to the Colstrip 1&2 wet scrubbers, once lime is added to the 1&2 scrubbers PPL would expect the S02 removal efficiency of the Units 1&2 scrubbers could approach 95% removal (i.e. 0.10 lb/MMBtu) but not on a continuous basis. The limiting factor would be the absence of a spare scrubber vessel on Units 1&2 compared to Units 3&4. The spare scrubber vessel helps allow for maintenance that is needed due to the scaling caused by the additional lime. Without the spare vessel, the unit must be shut down to perform the maintenance. The greater the lime injection, the more down time is required. An emission limit that can only be achieved with extensive down time is not considered feasible. PPL's original submittal identified the need for a spare scrubber vessel to reach a S02 emission level below 0.15 on a consistent basis. This emission level represents an S02 emissions reduction of 91%. PPL believes that 91% is appropriate reduction level to evaluate as a maximum average control level with present equipment. Higher efficiencies would not be attainable on a continual basis due to the extensive downtime for such higher levels. We note that PPL did in fact evaluate in its original BART submittal the addition ofa spare scrubber vessel as a potentially more palatable option to reduce S02 emissions to the presumptive level of0.15 lb/MMBtu (by having a spare vessel for de-scaling) than to attain that level with existing equipment only. PPL has since concluded thatbecause the units have existing equipment that is attaining greater than 50% removal efficiency the BART guidelines only require that upgrades to existing equipment be evaluated and that purchase of an additional scrubber vessel is beyond BART requirements. Cost and visibility analyses were conducted for the maximum controlled emissions level of0.15 lb/MMBtu (91% control) for typical/average emissions and a rate of0.285 lb/MMBtu for maximum 24-hour emissions. These analyses were also conducted for an 88% control level (0.2 lb/MMBtu typical and 0.38 lb/MMBtu maximum 24-hour). The 88% control level would result in only minor adverse plant impacts from scrubber downtime, increased scaling, and additional disposal costs.

4-1

### However, the cost oflime injection equipment, O&M on that equipment, and lime costs would be significant. The energy costs associated with sprays and pumps associated with lime injection

are a small part of the O&M costs and were estimated based on prorating the Units 3&4 experience to Units 1&2.


### CostEvaluation Two scrubber modifications were evaluated for improvement ofthe performance ofthe present venturi scrubbers. Current performance provides some control due to the alkaline nature of PRE coal fly ash, however, this can be improved by the addition of lime to the scrubber liquid. Based upon PPL experience for Units 3&4, the estimated cost ofthe injection equipment is estimated to be $1,500,000 per unit. Additionally the cost for the additive lime is estimated to be $375,000 per unit with additional maintenance costs of $125,000 per unit. Using a 15 year amortization schedule and assuming money is available at 7% per annum, appendix Table 4.1-1 shows a cost effectiveness of $209/ton of S02 controlled based on a 30-day average S02 emission rate of

### 0040 Ibs/MMBtu. While this represents a 50% reduction ofthe 30-day average "uncontrolled" emissions, this level of control actually represents an 88% estimated control efficiency over the uncontrolled emission rate based on the fuel sulfur content that would be present if the alkalinity of the PRB coal did not provide some control in and of itself. If calculated on the basis ofthe maximum 24-hour average emission rate, the cost effectiveness is $121/ton. Both ofthese cases are presented in Appendix 2, Tables 4.1-1 and 4.1-2. To extend the absorption capability to 91%, additional costs are expected based on the experience gained from Units 3&4. In addition to added outages for descaling, and additional lime consumption, an additional absorption pump and sprays are required. These additional costs for the pump and sprays is an additional $3,000,000 as well as an estimate of the costs associated with the added descaling time are listed in Appendix 2, Tables 4.1-3 and 4.1-4 for 30­ day and 24-hour average emission rate bases respectively. The amortization ofcapital costs over 15 years, and the assumption of money availability at 7% results in the cost effectiveness of $486/ton and $282 perton for the 30-day and 24-hour averaging times respectively.



### Visibility Evaluation

4-2

### The maximum improvement of 98th 

### percentile visibility estimates at any ofthe Class I

areas evaluated for an S02 reduction from the present to the 88% control level is 0.422 deciviews and a reduction from the present to 91% control is 0.544 deciviews. These values are based on maximum 24-hour emission rates.

4.2 Evaluation ofCoal Cleaning and Fuel Switching Options 4.2.1 Coal Cleaning The coal utilized at Colstrip is of sub-bituminous rank from the Powder River Basin (PRB). The coal mined in the PRB is shipped as a raw product. There is no "traditional" coal cleaning performed on the PRB coals ofthe nature that is conducted on bituminous coals. There have been and continue to be some coal processing procedures conducted on PRB coals with the primary purpose oflowering the moisture content ofthe coal. The PRB coals are generally low in ash and very low in sulfur, explaining why there has been and continues to be no need for any additional cleaning. The forms of sulfur contained in different coals are also important regarding coal cleaning. When sulfur is removed from coal through a cleaning process, the pyritic sulfur is the form that is removed. A general rule ofthumb estimates that about 35% to 55% ofthe pyritic sulfur can be removed when coal is 'washed'. The other forms ofsulfur present in coal, sulfates and organic sulfur, are not removed through coal washing. Although pyritic sulfur often makes up a significant percentage of the total sulfur in bituminous coals, the sulfur in PRB subbituminous coals is predominately organic, which will not be removed in a coal cleaningprocess. Forthese reasons, PPL believes that there is no reliable commercial cleaning process presently in effect to lower the sulfur content of PRB coal, and the application of a coal cleaning process would be ineffective. PPL did investigate a specific coal cleaning process called K-Fuel. This uses a process to lower the moisture content in PRB coal. K-Fuel also claims to reduce S02 and NOx 

### emissions, but they provide little detail on how that is accomplished (part of their patented process). Limited testing has been conducted on K-Fuel (by others, not PPL). A blend with bituminous coal was recently tested, but those results are not applicable to Colstrip Units 1&2 that bum subbituminous coal entirely. PPL's review of this coal cleaning process indicates that it may be beneficial to plants burning eastern bituminous coals, but it has not been demonstrated as a beneficial process for lowering S02 or NOx 

### at plants like Colstrip that bum sub-bituminous coal.

4-3

### 4.2.2 Fuel Switching The Colstrip Plant bums mine mouth Rosebud sub-bituminous northern PRB coal with a sulfur content ofapproximately 0.7%. The coal is conveyed from the mine to the plant. There is presently no outside fuel handling capability at the plant. A fuel switching alternative was evaluated based on the assumption that burning 0.3% sulfur coal would be a possibility ifnecessary plant upgrades were performed. PPL is concerned that coal transported to the plant may have a lower alkalinity than the present coal being burned and therefore lime injection would be required to maintain the S02 removal rate presently attained with the venturi scrubbers. Lime injection to achieve removal rates beyond those being presently attained was not evaluated because ofthe detrimental effects it would have on scaling ofthe scrubber vessels. The costs associated with fuel switching would include:

1. Construction ofa rail car unloading facility, a coal storage facility and an associated conveyor system as well as rail line upgrades. 2. Rail transportation costs. 3. Possible boiler upgrades to handle coal ofa higher sodium content than the present Rosebud coal. 4. Possible purchase of a spare scrubber vessel if lime injection were required to maintain the same S02 removal efficiency as is presently attained by the alkalinity of the Rosebud coal. The lime injection would present a scaling concern and more vessel down time for de-scaling.

A description ofthe cost analysis conducted is provided in Confidential Attachment 2. The overall cost is estimated at $10,258/ton based on typical, 30-day average emission rates and $5,943/ton based on maximum 24-hour emission rates. These costs are based on transportation costs and construction of an unloading facility only. Boiler upgrades and purchase of an additional scrubber vessel are additional concerns but because oftheir present uncertainty are not included in the cost estimate. Detailed cost estimates are provided in Confidential Attachment 2, Tables 4.2-1 and 4.2-2.

4-4

### The maximum improvement of 98th 

### percentile visibility estimates at any ofthe Class I

areas evaluated for an S02 emissions reduction by reducing the fuel sulfur content from 0.7% to 0.3% is 0.350 deciviews. This is based on maximum 24-hour emission rates

4.3 Evaluation ofVenturi Scrubber Upgrades for S02 Removal PPL has evaluated upgrades to the wet scrubbers in terms of both improving design removal efficiency and improving O&M practices to improve reliability. The Units 1&2 wet scrubbers are designed so that there is no bypass of flue gas. If a scrubber is taken off for maintenance, the plant load is reduced so the remaining scrubbers are treating the full flue gas flow. With this design, the improvement ofscrubber system reliability orreduction ofdowntime has no effect on reducing emissions. All flue gas leaving the furnace is being treated 100% of the time. Operational improvements by adjusting scrubber chemistry were evaluated by adding lime to enhance S02 removal efficiency. In addition, auxiliary equipment redundancy was evaluated by adding another set of absorption pumps and sprays to improve S02 removal efficiency. These improvements are included in the analysis to attain a maximum S02 removal of91% (Subsection 4.1). Othercommon scrubber upgrades and their status are reviewed below.

• Elimination ofBypass Reheat. The Colstrip Units do not have the capability ofbypass reheat, so essentially this upgrade is already included in the scrubber design.

• Installation ofLiquid Distribution Rings. This upgrade is considered in the evaluation to achieve 91% S02 removal efficiency.

• Installation ofPerforated Trays. This upgrade is already part ofthe existing scrubber design in form ofthe wash tray.

• Use ofOrganic Acid Additives. PPL's review ofthis upgrade indicates it is effective for limestone scrubbers to enhance the effectiveness ofthe limestone. But, the current Colstrip scrubbers do not use limestone, they rely on the alkalinity ofthe fly ash to achieve current S02 removal rates of75% to 80%. PPL does not believe addition of acid to the existing scrubbers will improve removal efficiency currently achieved. A review of acid additives indicates that they do not enhance the performance ofquick lime scrubbers because ofthe reactivity oflime. The reactivity oflime is much greater than limestone and explains why acid additives are helpful for limestone scrubbers, but not lime scrubbers. As discussed in Subsection 4.2, PPL has evaluated the addition of lime to the scrubbers to improve S02 removal efficiency.

4-5

### • Improve or Upgrade Scrubber Auxiliary System Equipment. This has been discussed above in terms ofupgrades to the wet scrubbers to improve design removal efficiency, O&M practices, adjusting scrubber chemistry and auxiliary equipment redundancy.

• Redesign Spray Header or Nozzle Configuration. This upgrade is considered in the evaluation resulting in 91% S02 removal efficiency.

4-6

### 5.0 SUPPLEMENTARY NO!

### EVALUATIONS 5.1 SOFA Units 1&2 at Colstrip are currently operated with Close Coupled Overfire Air combustion technology to reduce NOx emissions. PPL has investigated upgrading the NOx control by installation of Separated Overfire Air (SOFA) and has obtained a proposal from Alstom Power Inc for their proprietary LNCFS Level III w/SOFA system. The proposal contains a NOx emission rate guarantee of0.19 Ib/MMBtu. This rate is the "average value obtained overthe test period at plant steady state conditions." Normally, the test period is over a few days. This rate is used as the typical or 30-day average emission rate in the analyses conducted for this BART Addendum. The costs from the Alstom proposal are now used for the cost analysis rather than estimates based ontransferring cost experience from Units 3&4 to Units 1&2. Alstom has had the LNCFS Level III w/SOFA system perform better than 0.19 Ib/MMBtu at other Units, but there are unique issues with the Colstrip 1&2 furnace that have them put the performance guarantee at this level. Specifically, these are:

• Furnace size. Colstrip 1&2 are among ALSTOM's first efforts with PRB coal. As such, they found that they sized the furnace too small, resulting in a hot furnace. Colstrip 1&2 have a high "heat input to furnace area ratio" and a short "substoichiometric residence time," resulting in more NOx formation when compared to other Units.

• Coal type. Colstrip coal has more sodium which results in more fouling and slagging issues in the furnace. This reduces the effective furnace size which makes the furnace hotter, resulting in more NOx formation. Furthermore, Colstrip coal is less reactive than other PRB coals. Colstrip coal is classified as a borderline sub-bit 

### Bcoal. This is less reactive than sub-bit C coals, which are typical PRB coals. A more reactive coal has earlier devolatilazation and earlier combustion in the absence of O2, 

### resulting in less NOxformation.

• Experience on Colstrip Unit 3. PPL's experience with the LNCFS Level III 

### w/SOFA system on Colstrip Unit 3, which has a larger furnace and better "heat input to furnace area ratio" and longer "sub-stoichiometric residence time" than Colstrip Units 1&2, shows a 0.17 Ib NOx/MMBtu level.

Cost

### Evaluation The costs of the upgraded LNCFS air system include the costs of the hardware and installation costs in 2008 dollars. The cost includes costs ofthe air flow and coal measurement equipment required to operate the new Level III 

### system. Tables 5.1-1 and 5.1-2 present the cost
5-1

### effectiveness (C/E) calculations based on a cost of money at 7% per annum and a 20 year amortization. Table 5.1-1 is based on the maximum heat input and a 30-day average emission rate projected to be 0.19 Ibs/MMBtu with SOFA. Table 5.1-2 is based on the maximum actual 24-hour base case mass emissions as measured by the CEMS and adjusted for the improved NOx 

### control efficiency that would be obtained with the SOFA. Both tables assume a constant percent NOx 

### reduction from the baseline 30-day or 24-hour NOx 

### emission rate. The C/E for the 30-day and 24-hour average bases is $437 and $321 respectively. Cost effectiveness Tables 5.1-1 and 5.1.2 are presented in Confidential Attachment 1. Visibility Evaluation 

### The maximum improvement of 98th 

### percentile visibility estimates at any ofthe Class I

areas evaluated for a NOx 

### emissions reduction from the base case emission rate to the SOFA emissionrate is 0.535 deciviews. This is based on maximum 24-hour emission rates

5.2 SNCR PPL estimates that with the addition of SNCR an additional NOx 

### reduction of 20% beyond the SOFA emission rate could be obtained. This would result in a NOx 

### emission rate of 0.15 Ib/MMBtu. This estimate is based on anecdotal information from Alstom Power, Inc. that they had observed an additional 20% to 25% reduction by installing an SNCR system at another facility that bums PRB coal after a LNCFS Level III 

### w/SOFA system was installed. Actual performance ofSNCR on Colstrip 1&2 

### would need further review to evaluate the effects oftheir small furnaces and the type ofPRB coal being burned. Alstom has done extensive evaluation of SOFA on Units 1&2, but not SNCR. This 20% reduction with SNCR is PPL's best estimate at this time. SNCR is a technology which injects an ammonia based reagent into the post combustion
zones ofa boiler where NOx 

### reacts with the reagent to chemicallyreduce NO (the major oxide of nitrogen in NOx) 

### to nitrogen and water. Either urea or an ammonia-water solution are the typical

sources ofreducing agent. The analysis presented herein is based on the discussions included in the EPA Control Cost Manual (the CCM) from January 2002. The relatively simple process of injecting the active agent into the boiler involves delivery and preparation ofthe chemical agent, nozzles, pumps, and equipment to properly inject the reagent, and source-specific analysis of the boiler fire box to locate the optimal injection

5-2

### points for injection. With regard to the application of SNCR to existing boilers, EPA states on page 1-4 ofSection 4.2: 

### "There is little difference between the cost of SNCR retrofit of an existing boiler andSNCR installation on a new boiler. Therefore, the cost estimatingprocedure is 

### suitablefor retrofit or new boilerapplications on all types of coal-firedelectric utility andlarge industrial boilers. " However, EPA goes on to state on page 1-21 ofthe same section:



### "SNCR system design is aproprietary technology. Extensive details of the theory and correlations that can be used to estimate design parameters such as the required NSR are not published in the technical literature. Furthermore, the design is highly site-specific. In light of these complexities, SNCR system design is generally undertaken byproviding all ofthe plant and boiler specific data to the SNCR system supplier, who specifies the required NSR and other design parameters based on prior experience and computationalfluid dynamics and chemical kinetic modeling. "

In the discussion above, the "NSR" is an acronym for the Normalized Stoichiometric Ratio which is the ratio of the moles of ammonia equivalent injected to the amount of uncontrolled NOx. 

### For this study level analysis, it is assumed that the CCM costing techniques for the necessary boiler modifications to install SNCR equipment on Colstrip 1&2 are applicable. It 

### is further assumed that Alstom, the SOFA vendor, has estimated that SNCR can reduce NOx 

### by an additional 20% overthat attained by the modifications to combustion air injection. As EPA notes, SNCR is highly source specific. Also, as noted in previous sections, Colstrip I&2 are old boilers with high heat release rates making furnace temperatures higher than in newer units initially designed for low NOx 

### emissions. Furthermore, the lowered NOx 

### emissions to 0.19 Ib/MMBtu provide an "uncontrolled" starting point that limit the additional reductions attainable.



### CostEvaluation 

### The CCM includes detailed cost analysis calculation methods on page 1-30 through page 1-44. The basic components for application of SNCR technology are listed in Appendix 2, Tables 5.2-1 and 5.2-2 which are the result ofapplication ofthe CCM cost analysis techniques to Colstrip Units I&2. Regardless ofthe basic cost ofequipment, performance will be dictated by the source specific characteristics of the boilers to which it is applied. For control to 0.19 Ibs/MMBtu attained with the Alstom SOFA techniques, a cost effectiveness of$905 per ton of 5-3

### NO controlled would apply to attain 0.15 Ib/MMBtu based on the 30-day average emission rate. x 

### For the maximum 24-hour average emission rate case, a cost effectiveness of$852/ton applies. Also, on a basis ofincremental costs, the difference in cost to attain the additional control from the level attained with SOFA to 0.15 Ib/MMBtu is $2,778/ton and $2,976/ton for a 30-day and maximum 24-hremission rate basis respectively.


### Visibility Evaluation The maximum improvement of 98th 

### percentile visibility estimates at any ofthe Class I

areas evaluated for a NOx 

### emissions reduction from the base case maximum 24-hour emissions level to the emissions level with SNCR is 0.667 deciviews. The maximum incremental visibility improvement from the SOFA control level to the SNCR control level is 0.142 deciviews. These

are based on maximum 24-hour emission rates

5.3 SCR NO1\. Control Level The lowest NOx 

### emission rate evaluated for Colstrip Units 1&2 is 0.06 Ib/MMBtu through application of SCR post-combustion controls. It 

### is being evaluated as a suggested control level by EPA Region 8. PPL is not sure that the maximum SCR control level of0.06 Ib/MMBtu is achievable from a retrofit technology on a continuous basis at Colstrip Units 1&2. PPL believes that the 0.06 Ib/MMBtu control level may not even be appropriate for new sources, and that level ofcontrol has not been reliably demonstrated

- in fact the typical control level specified in the NSR settlement cases was 0.10 Ib/MMBtu.) An emission rate of0.11 Ib/MMBtu attained with SCR was also evaluated as the New Source Performance (NSPS) level for new boilers ofthe size ofUnits 1&2. A site-specific engineering study ofColstrip Units 1&2 would be required to accurately ascertain what performance level SCR could achieve at Colstrip Units 1&2. A Selective Catalytic Reduction (SCR) add-on control device employs a highly porous honeycomb type catalyst bed impregnated with catalytic metals or metal oxides. Upstream of the catalyst bed, the ammonia based reagent is intimately mixed with the flue gas, the reagent, and NOx, 

### which contacts the reactive surface ofthe honeycomb and reacts to form N2 and H

### 2 0 

### and continues to the exhaust stack after significant reductions in uncontrolled NOx 

### concentrations. SCR differs from SNCR in that the catalyst allows the reduction reactions to

5-4

### occur at lower temperatures than must be utilized in the SNCRprocess which relies onthe higher temperature portions ofthe boilerand economizer to foster the reduction reactions. The description provided herein is based on the EPA Control Cost Manual, Section 4.2 "NOx 

### Post-Combustion". This reference provides descriptions ofthree possible locations for the SCR module as well as detailed cost estimation procedures for estimation ofthe SCR system and ancillary equipment. Installation ofthe SCR module may be upstream ofthe particulate control device in what is termed the "high dust SCR location". Such installations typically require lower quantities ofcatalysts, however, the beds are subject to more rapid deterioration and activity loss due to exposure to metals in the uncontrolled particulates. A "low dust SCR" is placed downstream of a hot-side ESP (in boilers that use such PM controls) but upstream of the air preheater and requires a larger volume ofcatalyst. A third option, the "tail-end SCR" is typical ofmany retrofit applications where the SCR is installed downstream of all boiler/air preheater components. In such cases, the flue gas has cooled to such an extent that reheating of the exhaust to the minimum SCR operating temperature is required. From the EPA Control Cost Manual, Section 4.2, page 2-30:



### "SCR system design is aproprietary technology. Extensive details ofthe theory and correlations that can be used to estimate design parameters such as the required catalyst volume are not published in the technical literature. Furthermore, the design is highlysite-specific. In light of these complexities, SCR system design is generally undertaken by providing all ofthe plant and boiler specific data to the SCR system supplier, who specifies the required catalyst volume and other design parameters based on prior experience and computational fluiddynamics andchemicalkinetic modeling.
This section presents a step-by-step approach to estimate design parameters based on aprocedure developed in the EPA report Selective Catalytic reduction for NOx 

### Control on Coal-Fired Boilers. 3 

### This procedure assumes SCR system size and cost are based on three mainparameters: the boiler size or heat input, the requiredlevel of NO, reduction, andthe catalystvolume. "
CostEvaluation The calculations applicable for estimating the cost of an SCR system include the estimation ofdesign parameters as described on pages 2-30 to 2-40 ofthe Control Cost Manual. The cost analysis method is described from pages 2-40 to 2-49. Tables 5.3-1 through Table 5.3­ 4 show the step-by-step calculations which are taken directly from the Control Cost Manual. The cost estimations are based on reduction ofthe base NOx 

### level of0.35 Ibs/MMBtu, 30-day
5-5

### rolling average, to 0.11 Ibs/MMBtu, 30-day rolling average as well as to 0.06 Ibs/MMBtu, 30­ day rolling average. Two sets ofcost analyses were performed for each averaging time. The first set ofresults
was based on an uncontrolled emission rate equal to the 30-day average NOx 

### emission rate for SCR controls with control to the NSPS level of0.1 

### Ib/MMBtu. These results are presented in Tables 5.3-1 and 5.3-2 for 30-day and maximum 24-hr averaging times respectively. The second tables use as a basis the theoretical maximum SCR control to 0.06 Ib/MMBtu for both averaging times. These results are presented in Tables 5.3-3 and 5.3-4. The cost effectiveness numbers for SCR are as follows:

• SCR 30-day rolling average basis 

### $1,942/ton based on

### 0.111b/MMBtu • SCR 30-day rolling average basis 

### $1735/ton based on 0.06 Ib/MMBtu • SCR 24-hr average basis $1

### ,565/ton based on 0.154 

### Ib/MMBtu • SCR 24-hr average basis 

### $1,412/ton based on 0.084 

### Ib/MMBtu

For SCR, four calculation options are presented, however only one value, i.e., 

### $1,942/ton is realistic. The 24-hour average emission rate basis is unrealistic insofar as the calculation

assumes that this value characterizes operations for the entire year. The 0.06 Ibs/MMBtu (30­ day average) value also may be unrealistic because the already low uncontrolled NOx 

### emissions with the existing LNCFS II burner technology, and the old hot furnace design that applies to Units 1&2. The cost tables ES-I and ES-2, applicable to the 30-day averaging and 24-hour averaging times respectively, also show the incremental cost effectiveness of SCR as compared to SNCR.
Visibility Evaluation Visibility improvement was estimated for both SCR control levels (0.11 

### Ib/MMBtu and 0.06 Ib/MMBtu, 30-day averages). As with all visibility estimates, the calculations are based on the maximum actual 24-hour emissions during the modeling years rather than on 30-day averages. These maximum emissions correspond to emission rates of 0.154 Ib/MMBtu and 

### 0.084 Ib/MMBtu relative to the present base case emissions of 0.49 

### Ib/MMBtu (two unit average). The maximum improvement of98th 

### percentile visibility estimates among all Class I 

### areas evaluated corresponding to NOx 

### emissions reductions from the base case to the two SCR control levels are 0.792 and 0.956 deciviews. The maximum incremental visibility improvements from 5-6

### the SNCR control level to the less controlled SCR control level (i.e., 0.154 lb/MMBtu which corresponds to 0.11 lb/MMBtu typical) is 0.115 deciviews. The maximum incremental visibility improvements from the less controlled SCR level to the more controlled SCR level is 0.164 deciviews. These are based on maximum 24-hour emission rates

5.4 OtherNOx 

### Control Options The BART guidelines state that all possible control technologies do not need to be evaluated. PPL feels that the most appropriate NOx 

### control technologies to evaluate for Colstrip Units 1&2 are SOFA, SNCR and SCR and these were evaluated. Several other technologies for which it was decided that detailed cost analyses were notjustified are briefly discussed below.



### AdvancedSeparated OverjireAir(ASOFA) The design of the SOFA system (evaluated in Subsection 5.1) with individual sets of control dampers by comer and nozzle control both vertically and horizontally (see Alstom proposal) in coordination with the existing Closed Couple Overfire Air system on Units 1&2 are in effect very similar to Advanced Separated Overfire Air (ASOFA).


### Rotating OverfireAir(ROF A) This is a different suppliers' Low NOx 

### system that is somewhat similar to the SOFA system being proposed by Alstom. ROFA uses more ports and a significantly bigger fan to accomplish similar results of getting air into the upper portion ofthe furnace. ROFA uses a rotating overfire air process whereas Alstom's system uses both horizontal (yaw) and vertical nozzle tip controls. PPL's review ofdata indicates that ROFA will get about the same results as Alstom's LNCFS Level III w/SOFA, but at a much higher cost. In one example PPL reviewed, the cost ofROFA was about 5 times the cost ofAlstom's LNCFS Level III w/SOFA. PPL talked with Mobotec, the supplier of ROFA, and they indicated that NOx 

### reduction at Colstrip 1&2 would be at levels similar to Alstom's LNCFS Level III w/SOFA. PPL did not pursue a proposal for ROFA because ofthis review and the good experience with Alstom's system on Colstrip Unit 3. Additionally, PPL's review of lowest NOx 

### emitting units across the country showed significantly more Alstom systems than ROFA. As EPA has stated in its July 2005 BART guidance: 

### A possible outcome of the BART procedures discussed in these guidelines is the evaluation ofmultiple control technology alternatives which result in essentially equivalent 5-7

### emissions. It is not our intent to encourage evaluation of unnecessarily large numbers of control alternativesfor every emissions unit

...For example, 

## iftwo or more control techniques result in control levels that are essentially identical, considering the uncertainties ofemissionsfactors andotherparameterspertinent to estimatingperformance, you may evaluate only the less costly of these options. In PPL'sjudgment, pursuant to the foregoing guidance, a further evaluation ofROFA is notnecessary.



### RichReagentInjection (RRI) PPL took the same approach regarding RRI. PPL's review ofRRI indicates it is similar to SNCR and achieves similar results. The results reviewed were on cyclone units which are different than the tangential fired furnaces at Colstrip I&2. The review indicated that RRI was used in combination with overfire air and SNCR to achieve NOx 

### reduction. Additional review would be needed to quantify what benefit RRI brings to Colstrip I&2. Since PPL's review indicated similarresults and costs to SNCR, RRI was not evaluated any further.

5-8

### 6.0 SUPPLEMENTARY PARTICllLATE EVALUATIONS 6.1 Present Venturi Scrubber Operation for Particulate Removal The particulate scrubbers at Colstrip Units 1&2 are designed to have at least a 98% particulate control efficiency. Operation of the equipment has shown particulate control efficiencies approaching 99.5%. The wet scrubbers utilize a venturi/plumb bob section that

causes a high pressure drop (delta P) at this location and forces the particles to mix with the water. The wash tray section then acts as a final polisher for particulate removal. Increasing the plumb bob delta P has resulted in slight improvements in opacity, which can be an indicator of particulate emissions. Currently the Units 1&2 scrubbers operate with a plumb bob delta P of 17 inches wg. Increasing this delta P may improve particulate removal, but our experience indicates that improvement would be less than 10%. Increasing delta P would result in more times ofload limitations due to ID Fan air flow limits. Typically these load limitations are in the 10-20 MW range. Currently the wash trays utilize the sprays to allow water to be on the tray to help polish the flue gas. Increasing the level ofthe wash tray could possibly improve particulate removal, but experience at Colstrip indicates this improvement would be less than 5%. Additional testing would have to be performed to quantify any improvements to particulate removal from plumb bob delta P increase or wash tray level increases.

6.2 Evaluation ofParticulate Control to 0.01 Ib/MMBtu While the venturi scrubbers in operation at Colstrip perform well to reduce particulates by at least 98%, higher removal efficiencies are attainable using other post combustion equipment. In view of the average present filterable particulate emission rate from Colstrip Units 1&2 of 0.0525 lbs/MMBtu, the analysis of the cost of the additional PM control technology was estimated as the cost ofnew ESP or FF add-on controls applied to the current average emission rate to reduce this value to 0.010 Ibs/MMBtu. No additional cost for dry injection technology has been added to the cost ofthe new PM control device for this study. Control to a level of0.015 lb/MMBtu (the filterable NSPS level) that had been evaluated in the original BART submittal was re-evaluated here for consistency.



### CostEvaluation The EPA Control Cost Manual cost methodologies for ESPs and FFs are appropriate for moderately sized units to a few hundred thousand ACFM. To estimate the cost ofutility sized
6-1

### units, the capital cost ofthe ESP was estimated at $60/kW and that ofa FF at $50/kW.4 

### Using the equipment cost as typical for coal-fired utility boilers, and using the procedure in the Control Cost manual, Section 6, Chapter 3, page 3-57 for an ESP, and Chapter 1, page 1-45 for a FF, the total annual costs ofa new ESP and FF for Colstrip 1&2 was estimated as shown in Tables 6.2-1 through and 6.2-4. These costs for an ESP or FF are presented as incremental costs only and the costs reflect the additional cost to attain levels beyond 98% control already attained by the venturi scrubbers. The cost ofeither an ESP or a FF is a function ofthe basic size ofthe electrical generating unit. The only cost difference between the assumption ofa 0.015 or a 0.010 Ibs/MMBtu emission rate of filterable PM, is the difference in ash disposal costs for the more stringent control case. Regardless ofthe alternative chosen, a requirement to provide additional PM control to the NSPS level or below is not cost effective at between $21,000 to $29,000 per ton ofadditional control. While PPL has included a basis of 0.010 Ib/MMBtu as one of the costing cases, this actual emission rate may not be ultimately attainable.


### Visibility Evaluation The maximum improvement of98th 

### percentile visibility estimates among all Class I areas evaluated for a filterable particulate emission reduction from the base case level of 0.0525 Ib/MMBtu to 0.015 Ib/MMBtu is 0.042 deviviews and from the base case to 0.010 Ib/MMBtu is 0.048 deciviews. The maximum incremental improvement to go from an emission rate of0.015 Ib/MMBtu to 0.010 Ib/MMBtu is 0.006 deciviews. For the filterable particulate evaluation, there
was no distinction between the typica1.30-day average and maximum 24-hour emission rates

.

.

# ­

6-2

### 7.0 SUMMARY OF ALL COSTANALYSES Table 7-1 summarizes the cost effectiveness results in terms ifdollars per ton ofpollutant removed for all of the control levels evaluated for each pollutant. The table also provides the references for the cost data. These references are also provided in the respective sections ofthe addendum and in the cost tables. The tables itemizing the costs (cost tables) are provided in Appendix 2. For NOx 

### control with SOFA, the cost tables are provided in Confidential Attachment 1.

7-1

### Table 7-1: ControlCosts Summary and References

Pollutant Control Technology Emission Rate Averaging Time Emission Rate (lb/MMBtu) $/Ton Reference


### S02 Fuel Switching 30-day 0.23 $10,258 PPL Estimate 24-hour 0.0.445 $5,943 Lime Injection (88% Control) 30-day 0.2 $209 Plant estimate based oncost oflime and equipment 24-hour 0.38 $121 Lime Injection (91 % Control) 30-day 0.15 $486 Plant estimate based on cost oflime and equipment and cost ofincreased outages 24-hour 0.285 $282 NOx SOFA 30-day 0.19 $437 Confidential Alstom Proposal
24-hour 0.266 $321 SNCR 30-day 0.15 $905 OAQPS Control Cost Manual (2002)
24-hour 0.210 $852 SCR 30-day 0.11 $1,942 OAQPS Control Cost Manual (2002)
24-hour 0.154 $1,763 SCR 30-day 0.06 $1,735 OAQPS Control Cost Manual (2002)
24-hour 0.084 $1,412 Particulate ESP both 30-day and 24-hour 0.015 $29,809 AWMA utility $/KW &OAQPS CCM ESP both 30-day and 24-hour 0.010 $26,307 AWMA utility $/KW &OAQPS CCM Fabric Filter both 30-day and 24-hour 0.015 $24,270 AWMA utility $/KW &OAQPS CCM Fabric Filter both 30-day and 24-hour 0.010 $21,420 AWMA utility $/KW &OAQPS CCM



### 7-2

### 8.0 SUMMARY OF ALL VISIBILITY ESTIMATES Visibility estimates are based on Calpuff modeling results for the years 2001, 2002 & 

### 2003 as described in PPL's original BART submittal(l). For control levels different than those for which the modeling was conducted, visibility estimates are based on interpolation or extrapolation of those results as described in Section 3.2. The visibility estimates are for maximum actual and projected 24-hour emission rates. The deciview values are presented as 98th 

### percentile levels. Table 8-1 presents the maximum deciview levels among all Class I 

### areas evaluated for the base case and each control alternative. For the control alternatives, all emission rates are at the base case levels except the pollutant for which the control is being applied. Table 8-1 also presents the cumulative visibility improvement from the base case to each control alternative and the incremental improvement from the immediately preceding control alternative in terms ofthe level ofemissions reduction attained. An exception is that the S02 coal switching alterative was not included in the incremental calculations for either ofthe lime injection control alternatives. The cumulative and incremental differences in Table 8-1 are based on the differences between the maximum 98th percentile deciview estimates among all Class I 

### areas. Table 8-2 presents the same information as Table 8-1 except that the maXImum differences between visibility estimates for the base case and control alternatives among all Class I 

### areas evaluated are presented. These values are equal to or higher than the values presented in Table 8-1. The originally submitted BART report(l) presents Calpuffmodeling results for each Class I 

### area in Appendix B.

8-1

### Table 8-1: Maximum Overall 98th Percentile Visibility Estimates Among All Class 1 Areas Evaluated and Corresponding Differences Between Control Cases

Pollutant Control Technology Emission Rate (lb/MMBtul



### lb/hour)

0.761 2720.0 

### Max 98th 

### Percentile Estimate (deciviews)
2.233 

### Deciview Difference Cumulative Incremental
S02 Base Case 0 0
Lime Injection (88% Control) 0.381 1360.0 2.000 0.233 0.233

Lime Injection (91% Control) 0.2851 1020.0 1.954 0.279 0.046

Fuel Switching 0.4451 1592.6 2.040


### NO, Base Case 0.491 1876.5 2.233 0 0
SOFA 0.2661 1018.7 1.811 0.422 0.422

SNCR 0.2101 804.2 1.672 0.561 0.139
SCR 0.1541 589.8 1.591 0.642 0.081
SCR 0.0841 321.6 1.458 0.775 0.133



### Filterable Particulate Base Case 0.05251 206.6 2.233 0 0 ESP/FF 0.0151 59.1 2.213 0.020 0.020 ESP/FF 0.0101 39.4 2.210 0.023 0.003 

### Notes: The maximum 98th percentile estimates occur at the Theodore Roosevelt NP Class I area for the S02 control alternatives. For the base case and the NO, and PM control alternatives the maximum 98th percentile visibility estimates occur at the UL Bend Class I area.,



### 8-2Table 8-2: Maximum 98th Percentile Visibility Differences Among All Class I Areas Evaluated

Pollutant Control Technology Emission Rate (lb/MMBtul

Ib/hour) Max 98th Percentile Estimate (deciviews) Deciview Difference

Cumulative Incremental

S02 Base Case 0.76 2.233 0 0 2720.0
Lime Injection 0.38 1.811 0.422 0.422 (88% 1360.0 Control) Lime Injection 0.285 1.698 0.544 0.122 (91% 1020.0 Control)
Fuel 1.883 0.350 0.350 Switching
NO. Base Case 0.49 2.186 0 0 1876.5 SOFA 0.266 1.651 0.535 0.535 1018.7 SNCR 0.210 1.509 0.677 0.142 804.2 SCR 0.154 1.394 0.792 0.115 589.8 SCR 0.084 1.230 0.956 0.164 321.6
Filterable Base Case 0.0525 2.186 0 0 Particulate 206.6 ESP/FF 0.015 2.144 0.042 0.042 59.1 ESP/FF 0.010 2.138 0.048 0.006 39.4 Notes: (l)The maximum cumulative and incremental differences for the S02 cases occur at the ULBend Class I area. (2) The maximum cumulative and incremental differences for the NOx andPM cases occur at the Theodore Roosevelt NP Class I area. (3) Maximum 98th percentile base case levels are presented perpollutant for the Class I area for which the differences between control alternatives and the base case were the maximum.



### 8-3

### 9.0 SUMMARY The results ofthe cost and visibility analyses for the BART control options evaluated are presented in the following three tables. Table 9-1 presents the cost analyses based on typical, 30­ day base case and projected emissions rates for each ofthe control levels evaluated. Table 9-2 presents the same cost data for actual maximum 24-hour emission rates. Table 9-3 presents a summary ofthe visibility estimates based on maximum actual 24-hour base case and projected emission rates. The visibility estimates presented are the highest 98th 

### percentile estimates among all Class I areas evaluated. Emission rates in the tables are the average ofthe emission rates for Units 1&2.

Table 9-1: ControlCosts Summary

- Typical30-DayAverage Emission Rates

TABLE 9-1
- CURRENT I NSPS I CONTROL OPTIONS COST SUMMARY FOR THE PPL MONTANA, LLC, AVERAGE OF COLSTRIP UNITS 1&2 •30.oAY AVERAGE EMISSIONS BASIS

Current(l) Emission rate Particulate Matter Sulfur Dioxide Nitroaen Oxides Rate I Units

0.0525 IblMMBtu Rate I Units
0.4 IblMMBtu I Rate I Units
0.35 IblMMBtu Control COFA(J)**BD~)from** 

### I 2006 NSPS 0.0151b/MMBtu 1.4 Ibs S021MW out 1.0 IblMW out New Sources lIl15 IblMM Btu in 1011 IblMM Btu in Cost Effeciveness Cales Cost Effeciveness Cales Option Evaluated Option Evaluated CE(lI) Incremental Option Evaluated**C~)** Incremental Rate Rate (from Present) cE0 Rate (from Present) CE(7) IblMMBtu $/ton IblMMBtu $/ton $/ton Ib/MMBtu $/lon $lion Control Present 0.0525 Present 0.4 Present 0.35 Options FF 0.015 $24,270 Fuel Switch 0.23 $10,258 SOFA 0.19 5437 FF 0.010 $21,420 WS-FG[J<4) 0.2 $209 SNCR 0.15 $9J5 $2,778 ESP 0.015 $29,809 WS-FG[J<6l 015 $486 $1593 scRl'l) 0.11 $1,942 $7,127 ESP 0.010 $26 307 scRI'Il) 006 $1735 53579 Notes 1) Colstnp Average Flkerable EmiSSions of0.0525 IblMMBtu used as representatllle of each uM; FF=Fabric Filter, ESP = Electrostatic Precipitator (these costs represent incremental costs only because to attain these emission rates, replacement ofthe current wet scrubbers would be required) 2) Lo

......NOx Burners with Close-Coupled O't'erfire Air· new SOFA is an upgrade to present equipment 3) BDT = "Best Demonstrated Technology'

- From FR Vol. 71, No. 38, Monday, February 27,2007

Final Rule (NSPS for EUSGUs) •the 2lIE revised standards were revised to a gross megawatt output basis (equivalent in IblMMBtu input values listed in paren) 4) Wet Scrubber-Flue Gas Desulfurization; actual emissions are 0.40 IbsIMMBtu (per CEMS • 3D-day average); adding lime to the scrubberwill reduce emissions by an additional 50% (overall 88% reduction ofinlet) 5) Similar to 3 but additional lime added with downtime due to scaling to attain a reduction to 0.15 IbslMMBtu (overall 91% reduction); 6) Control options considered separately; incremental cost of S02 scrubbing options compares the cost to the baseline emissions; for NOx, each option compares the cost to the current system 7) Incremental cost ofwet scubbing options reflect the additional cost to attain the lower level ofemissions; SNCR incremental cost compares the SNCR cost to the cost ofSOFA; both SCR options compare to SNCR 8) This represents control to the new source NSPS level; incremental cost is compared to SNCR 9) This represents a hypothetical maximum control case; incremental cost is compared to SNCR



### 9-1

### Table 9-2: ControlCosts Summary

- Maximum 24-HourAverage Emission Rates

TABLE 9-2
- CURRENT i NSPS f CONTROL OPTIONS COST SUMMARY FOR THE PPL MONTANA,llC, AVERAGE OF COLSTRIP UNITS 1&2

-2UlRAVERAGE EMISSIONS BASIS Nitroaen Oxides Sulfur Dioxide Particulate Matter Control Rate Units Rate I Units Rate I Units Current(1) COFA(2) 0.49 IblMMBtu 0.76 IblMMBtu 0.0525 IblMMBtu Emission rate
BD"(O) from 

### I 1.0 IblMW out 1.4 Ibs SO:!fMW out 0.015 IblMMBtu 2006 NSPS !D.ll IblMM Btu in1 !D.15 IblMM Btu in New Sources Cost Effeciveness Cales Cost Effeciveness Cales Option

Control Options Present Added FF Added FF Added ESP Added ESP cEtlI) cEtlI) Incremental Evaluated Evaluated Incremental Option Evaluated Option cE<7) cE<7) from Present) Rate from Present Rate Rate $!ton $!ton $/lon IblMMBtu $!ton $/lon IblMMBtu IblMMBtu Present 0.49 Present 0.76 0.0525 $321 SOFA 0.266 $24,270 Fuel Switch 0.445 $5,943 0.015 WS-FG(14 ) $852 $2,976 $121 SNCR 0.21 $21,420 0.38 0.010 scRl'8) W8-FG(jI) $1,565 $5,132 $923 0.154 0.015 $29,809 0.285 $2B2 scRl'8) $1412 $2657 0.084 0.010 $26 307 Notes 1) Colstrip Average Flnerable EmiSSions ofO.05251b1MMBtu used as representative of each unrl, FF=Fabric Finer, ESP = Electrostatic Precipitator (these costs represent incremental costs only because to altain these emission rates, replacement ofthe current wet scrubbers would be required) 2) Low-NOx Burners with Close-Coupled Overfire Air

- new SOFA is an upgrade to present equipment 3) BDT = "Best Demonstrated Technology"

- From FR Vol. 71, No. 38, Monday, February 27,2007

Final Rule (NSPS for EUSGUs)

- the 2006 revised standards were revised to a gross megawalt output basis (eqUivalent in IblMMBtu input values listed in paren) 4) Wet Scrubber-Flue Gas Desulfurization; actual emissions are 0.76 IbsIMMBtu (per CEMS

- 24-hr worst-case); adding lime to the scrubberwill reduce emissions by an additional 50% (overall 88% reduction of inlet) 5) Similar to 3 but additional lime added with downtime due to scaling to altain a reduction to 0.15 IbsIMMBtu (overall 91 % reduction); 6) Control options considered separately; incremental cost of S02 scrubbing options compares the cost to the baseline emissions; for NOx, each option compares the cost to the current system 7) Incremental cost ofwet scubbing options reflect the additional cost to altain the lower level of emissions; SNCR incremental cost compares the SNCR cost to the cost of SOFA; both SCR options compare to SNCR 8) This represents control to the new source NSPS level; incremental cost is compared to SNCR 9) This represents a hypothetical maximum control case; incremental cost is compared to SNCR


### Table 9-3: Estimated Visibility and Visibility Improvements

ESTIMATB>VISIBILITY AND VISIBILITY 1M PROVEMerrs
Filterable Particulate**Su~ur** Doxide Nitrogen Oxides Estirmted irTl>rovement (7) Estirmted' Improvement (7) Estirmted Improvement (7) Rate(1)(2) A"ediction (3) from Rate (1)(2): A"ediction

.,._,**,.~** ..., M·'. • from Rate (1)(2 A"ediction from Option (lbiMMBtu) (deciview s) A"esent**~c** (6) Option (lbiWM3tu)tdecOliews A"esent hc (6) Option IbiWM3tu deciviews A"esent Inc (6) A"esent 0.0525 2.233 nia nia A"esent 0.76 2.233 nia nia A"esent 0.49 2.233 nia nfa ESPiFF 0.015 2.213 0.042 0.042 WS-FGD(4) 0.38 2.000 0.422 0.422 SOFA 0.266 1.811 0.535 0.535 ESPiFF 0.010 2.210 0.048 0.006 WS-FGD(5) 0.285 1.954 0.544 0.122 SNCR 0.21 1.672 0.677 0.142 FuelSW 0.445 2.04 0.35 0.35 SCR 0.154 1.591 0.792 0.115 SCR 0.084 1.458 0.956 0.164
Notes: (1) The errission rate is the rate corresponding to the maximum daily errissionsduringlhe rmdeling years (200f-2003). (scaled by the expected control eificiency for control alternatOles) (2) A"verage'errisslon'atesbetWeenUrli!s**1&i~'uriitl** and Unit 2errission rates**"red~ferent,** they are**~indicated** 'asl.JnitliUnit2 rates. (3) PreddiQnis from allthreepoilui"nts "fpresenterrissions except the one beingcontrCllled'

. (4) S02erris sions rSducedby 88%.

. (5) 802 errissiCln sreduced by 91%. (6)**Inc~incre.re';tal** ....­ (7)M8ximum Improvements show n rmy occur at**d~ferent** O"ss Iareas than the m8xirrum prediction among "IfOass Iareas.

9-2

### 10.0 REFERENCES


### 1. TRC, Best Available Retrofit Technology (BART) Assessment Colstrip Generating Station, August 2007.
2. NPS, http://www2.nature.nsps

.gov/air/permits/ect/ectOilFiredBoiler.cfm
3. Selective Catalytic Reduction for NOx 

### Control on Coal-fired Boilers, Draft Report, prepared for the U.S. Environmental Protection Agency by the Cadmus Group, Inc., Bechtel Power Corporation, and Science Applications International Corporation, May 1998
4. AWMA, Air Pollution Engineering Manual, Air & Waste Management Association, Anthony J. Buonicore and Wayne T. Davis, eds., Van Nostrand Reinhold, 1992.

10-1

# » "C "C CD :::s 

### c. )C'
...a.

# APPENDIX 1 EPAREGION 8 COMMENTLETTER January 28, 2008UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGIONS 1595Wynkoop Sireet DENVER, CO 80202·1129 Phone 800-227-8917 hllp:/Iwww.epa.gov/region08 

## JAN 282008 Ref: 8P-AR
James Parker Manager. Compliance Services PPLMontana·Colstrip P.O. Box 38 Colstrip, MT 59323
Re: BestAvailableRetrofit Technology (BART) Assessment Colstrip GeneratingStation
DearMr. Parker:
On February 28,2007,EPARegion 8 sent a letter to PPL Montana

- Colstrip (PPL) that provided the results ofour "subjectto" modeling for Best Available Retrofit Technology (BART) and requested thatColstripperform a BARTanalysis for Units 1&2andsubmit it to EPA Region 8. OnAugust 8,2007, Colstrip submitted a BART analysis to EPAthat wasperformed by TRC. We would like to thankyou for submittingthe BARTanalysis and recognizetheeffortthat has gone into developing thisdocument.
We have completed ourinitial reviewofthe August 8, 2007 submittal and have determinedthatthere is additional information andanalysis needed from Colstrip in orderfor us to completeourreview. Following are EPA Region 8's comments on the analysis. In addition, we are attaching a copy ofcommentsonthe BARTanalysis for Colstrip Units 1&2 submitted to EPA onNovember 5, 2007 from theNational Park Service

.. Visibility Improvement and Impacts Throughoutyour analysis. youstate thatthc amotmt ofvisibility improvementresulting from a reduction in emissions, based on your current BARTanalysis, would not be discernible and therefore additional controls are notjustified. The visibility improvementfor S02,NOx, and PM in youranalysis are all below 1.0 deciviews. and this is used as a reason not to implement more stringent control measures. EPA disagrees with yourassertion. EPA states in the preamble to its BARTGuidelines that, "Even though the visibility improvement from anindividual source may not be perceptible, it should still be considered in setting BARTbecause thecontribution to haze may be significantrelativeto other source contributions in the Class I areas." (see 70 FR 39129,July 6,2005). Visibilitymodeling shows that for Class I areas in Montana, andin particularU.L. BendNational Wildlife Refuge, Colstrip Units 1&2 have the largest impact of any single stationary source in Montana.Failing to consider less-than-perceptible contributions to visibility impairmentwould ignore the Clean AirAct's (CAA) intent to have BARTrequirements apply to sources that contribute to, as well as cause, suchimpairment (see 70 FR39129, July 5,2006). The BART Guidelines indicate that for purposes ofdetermining which sources are subject to BART, "A single source that is responsible for a 1.0 dec.iview change ormore should be considered to "cause" visibility impairment; a sourcethatcauses less than a 1.0 deciview change may still contribute to visibility impairment and thus be subjectto BART." (see 70 FR 39161,July 5, 2006). The BARTGuidelines further state that "As a general matter, any threshold that you use for detenniningwhether a source "contributes" to visibility impairment should not behigherthan 0.5 deciviews" (see 70 FR39161, July 5,2006). Giventhat EPAhas said that sources are subject to BARTbased ona contributionthreshold ofno greater

### than 0.5 deciviews, it would be inconsistentto automatically rule out additional controls wherethe improvement invisibility may be lessthan 1.0 deciview oreven0.5 deciviews. TheColstripBARTanalysis showsthat a 0.5 or greaterdeciview reduction is achievablefor bothNOx and S02 as individualpollutants at one ClassI area, U.L. Bend, and demonstrates thatwithreductions inNOxand S02combined, there is the potential for a 1.0 deciviewormore improvement. General Comments
1. PPL's analysis is based on adding control technology to meetwoot it tenns "best demonstrated technology." PPL assumes recently updated NSPS emission limits for particulates, S02, and NOx represent bestdemonstrated technology and does not take into account the highest efliciency many ofthese control technologies arecapable of achieving. However, the BARTGuidelines statethat "It is not our intent to require analysis ofeach possible level ofefficiency for a control technique as such an analysis would resultin a largenumberofoptions. Itis important, however, that in analyzing the technology you take into accountthe most stringent emission control level thatthe technology is capable ofachieving. You should considerrecent regulatory decisions and performance data (e.g

.. manufacturer'sdata, engineering estimates and the experience of other sources) when identifying anemissions performance level or levels to evaluate." (see 70FR39166, July 6, 2005). Throughoutyour analysis,you have not evaluated control technologies with the most stringentemission control level,resulting in inflated calculated costeffectiveness values. PPL needs to redo the analysis for control technologies using the most stringent emissioncontrol level that thetechnology is capable ofachieving. Specificexamples ofthis include: PPL should re-evaluate the costs and benefits ofreducing S02based on a higher removal efliciency. For S02, PPL only estimates a 91% removal efficiency with additional control technology, but in the EPA Control Cost Manual, EPA states that most absorbers have removal efficiencies in excess of90%, and packed tower absorbers have removal efficiencies as high as 99.9% ("EPAAirPollution Control CostManual", Sixth ed., EPA-452·02·001, January 2002, Section 5.2, Chapter 1, pg 1-3). The BARTanalysisassumedthatthe addition ofselective non-catalytic reduction (SNCR) to separated overfire air (SOFA) could reduceNOxemissions by about 11% over SOFA. However, EPAestimatesthat SNCRcanreduce NOx by40%­ 250% for aboilerthis size (EPA 2002, Section4.2, Chapter 1, pg 1-3). PPL should re-evaluate SNCR at these higher efficiencies. PPL has assumed that the addition ofselective catalytic reduction (SCR) would reduce NOx, by 17% to 0.15 Ib/MMbtu. However, EPA estimates that SCR can reduceNOx, by 70%

- 90%+ for a boiler this size (EPA 2002, Section 4.2, Chapter2, pg 2-3). IfSCRis capable ofreducing emissions belowPPL's target, then the amount ofthe reductions and consequent visibility improvements will increase. PPL should re-evaluate SCR at these higherefficiencies. 2. The cost analysis for the control technologies included in the analysis does not contain the properdocumentation to supportthe costs contained in the appendices. The BART Guidelines state that "Once the control technology alternatives and achievable emissions performance levels have been identified, you then develop estimatesofcapital and annual costs. The basis for'equipment cost estimates also should be documented, either withdata supplied by an equipmentvendor

### (i.e., budget estimates orbids) or by areferenced source (such as the OAQPS 

### Control CostManual. Fifth Edition, Febrwuy 1996, EPA 453/B-96­ 00 1). In orderto maintain and improve consistency, costestimates should be based on the OAQPS 

### Control CostManual, where possible." (see 70 FR 39166, July 6,2005). PPL needs to provide the proper documentationto supportthe costs used in the analysis. Pleasenote that the "OAQPS Control Cost Manual", Fifth Edition, referenced above has been replaced by the "EPAAir Pollution Control CostManual", Sixth Edition, January 2002. 3. There is a discrepancy between the emission rates discussed in the text and those presented in tables 4-7 and 4-9. Forexample, the text on page 4-19 discusses reaching 0.18 IblMMBtu ofNO

### xthrough the application ofSOFA, howevertable 4-9 shows that the application ofSOFA would achieve only 0.23/0.27 IbIMMBtu. Itappears that the loweremission numbers in the textreflect 24-hour averaging times, while those in the table reflect 30-day rollingaverages. Since the EPNWRAPmodelingthat was conducted to detennine that Colstrip is subject-ta-BART was based on 24-hour actual emission rates, we believe thatmodeling conducted to show the visibility improvement from applying controls should also be based on 24-houraverages. In addition to the modelingthat has been provided. PPL needs to remodel the control measures based on 24-houraverages. S02 Emissions and Controls 4. The analysis used 11 years for the remaining useful life for all ofthe control technologies. However, the typical useful life ofthese control technologies is expected to be 15 years based oninfonnation from the EPA Control Cost Manual (EPA 2002, Section 5.2, Chapter I,pg. 1-28). The boilers are expected to have a useful life beyond 20 years, and therefore do nothave any effect on the useful life detenninations. PPL needs to reanalyze the annualized costs for the control technologies using fifteen years as provided in the EPA Control Cost Manual.

35. In yourBART analysis, you did not analyze aI!f fuel switching options for S02 control. Fuel substitution to lowerthe fuel sulfurcontent can be a very cost effective means for reducing S02 emissions and should be analyzed. The analysis does statethat coal cleaning would not result in sulfurreductions; however there areno calculations or documentation that supports this. PPL needs to provide an analysis for fuel switching options andprovide an analysis to show what emissionreductions coal cleaning would result in.
6. In the portion ofthe analysis pertaining to energy impacts, you state that cost estimates are based on experience from Colstrip Units 3&4. PPLneeds to provide additional information and documentation 

### to explain how ittranslated theenergy impacts atUnits 3&4to Units 1&2.
7. The BARTGuidelines indicate that EGUs with pre-existing post-combustion controls achieving removal efficiencies ofat least 50% should considerupgrades to the current scrubbers. PPL currently has pre.-existing post-combustion controls with venturi wet scrubbers achieving atleast 50% control efficiency. In the BART analysis, PPL only considers the addition oflimeto the scrubbers as a possible upgrade. The BART Guidelines provide additional information on what upgrades and improvements sources should consider to existing wet scrubbers. The Guidelines state "Forthose BARTeligibleEGUs withpreexisting post-combustion S02 controls achieving removal efficiencies ofat least 50percent, your BARTdetermination should consider cost effective scrubberupgrades designed to improve the system's overall S02removal efficiency. There are numerous scrubberenhancements available to upgrade the average removal efficiencies ofall types ofexisting scrubber systems. We recommend thatas you evaluate the definition of"upgrade", youevaluate options that not only improve the design removal efficiency ofthe scrubber vessel itself, but also consider upgrades that can improve the overall S02removal efficiency ofthe scrubbersystem. Increasing a scrubber system's reliability, and conversely decreasing itsdowntime, by way ofoptimizing

. operationprocedures, improving maintenance practices,adjusting scrubber chemistry, and increasing auxiliary equipmentredundancy, are all ways toimproveaverage 802 removal efficiencies. We recommendthat as you evaluatetheperformance ofexisting wet scrubber systems, you consider some ofthe following upgrades,in no particular order, as potential scrubberupgrades that have beenproven in the industry as cost effective means to increase overall S02 removal ofwet systems: (a) Elimination of BypassReheat; (b) Installation ofLiquid Distribution Rings; (c) Installation ofPerforated Trays; (d) Use ofOrganic Acid Additives; (e) Improve orUpgrade Scrubber Auxiliary SystemEquipment; (f)Redesign Spray Header orNozzle Configuration." (see 70 FR 39171, July 6,2005). PPL needs to provide an analysis for upgrades to the current scrubbers that includesthe upgrades suggestedby the BARTGuidelines and any other improvements to this control equipmentthatmay be appropriate.

4NOx Emissions andControls 8. The analysis used 11 years for the remaining useful**Iif~** for all ofthe control teclmologies. However, the typical useful life ofthese control teclmologies is expected to be 20 years based0(1 information from the EPA Control CostManual (EPA 2002, Section 4.2, Chapter I,pg. 1-39). The boilers are expected to have a useful life beyond 20 years, and therefore do nothave any effect on the useful life determinations. PPL needs to reanalyze the annualized costs for the control technologies using twenty years as provided in the EPA Control CostManual. 9. You state inthe BART analysis thatthe new NOxNSPS level is below the presumptive BARTlevel and therefore 

### was not analyzed. The BART Guidelines require an analysis ofalevel ofcontrol equivalentto NSPS, even ifit is below the presumptive limits. Specifically, the BART Guidelines state that "Where aNSPS exists for a source category (which is the case for most ofthe categories affected 

### by BART), you should include a level ofcontrol equivalent to the NSPS as one ofthe control options. TheNSPS standards are codified in40 CFRpart60. We note that there are situations where NSPS standards do not require the most stringent level ofavailable control for all sources within a category. Forexample,postcombustionNOx controls (the most stringent controls for stationary gas turbines) are notrequired under subpart GG ofthe NSPS for Stationary Gas Turbines. However, such controls must still be considered available technologies forthe BART selectionprocess." (see 70 FR 39164). PPL needs to provide an analysis forNOx that is equivalentto the current NSPS. 10. In your analysis for adding Separated Overfue Air (SOFA), you state that you based COlt estimates on recentupgrades to the burners in Units 3&4. PPL needs to provide additional information and documentationto explain how ittranslated the costs ofadding SOFA atUnits 3&4 to Units 1&2. II. Units 1&2, currently controlled by 10w-NOx burners (LNB), are subject to the presumptive limits in the BART Guidelines, which are .15 IbIMMbtu for tangential-fired, sub-bituminous fired boilers. The BARTGuidelines state "MostEGUs canmeetthese presumptive NOx limits through the use ofcurrentcombustion control technology, i.e. the careful control ofcombustion air and 10w-NOxburners. Forunits thatcannot meet these limits using such technologies, you should considerwhetheradvanced combustion control technologies such as TOtating opposed fire air should be uscdto meetthcse limits." (see 70 FR 39172, July 6,2005). In addition to the analysis for SOFA, SNCR, and SCR, PPL should analyze newcontrol technologies than can achieve highercontrol levels than LNB and SOFA. Some ofthe technologies PPL should analyze include advanced separated overfire air (ASOFA), richreagent injection (RRI), and rotating overfire air (ROFA). 12. Table A4-8(a) contains an error. The value for uncontrolled annual emissions is 5,166.50 tpy, which should be 5,616 tpy, as itis inTable A4-8(b) andTable A4-8(c). The 5

### incorrect value was carried forward in 

### the cost effectiveness calculations. PPL needs to revise Table A4-8(a) and well as any cost effectiveness calculations that 

### are affected by this. ParticulateMatterEmissions and Controls 

### 13. Onpage 4-10 ofthe BART analysis, you state that "Wet scrubbers are currently operating to control particulate and S02emissions on Colstrip Units 1&2. While enhancements to particulate collection efficiency are potentially possible, the filterable emission rates of 0.047 and 0.058 IbIMMBtu, as determined from stacktesting, are already very low and indicative ofexcellentcontrol efficiency for this technology. Furthermore, enhancement ofthe wet scrubbers would not be 

### expected to result in 

### additional particulate removal. Accordingly, ESP and FF controls werethe applicable and available control technologies to enhancethe already 98% particulate control efficiency ofthe Colstrip Units 1&2 boilers." PPL needs to provide an analysis or information for the basis ofthe statement that 98% control efficiency can notbe enhancedto perform better. 14. ThePPL PM10 BART analysis assumes that the lowest emission rate achievable by either afabric filter (baghouse) or an Electrostatic Precipitator(ESP) is 0.Ql5 IbIMMBtu. However, EPA has proposed that the DesertRock powerplant will meet afilterable PMIO limit of0.010 IblMMBtu (see DesertRock Energy CenterProposed Permit, AZP 04-01, http://www.epa.gov/region09/air/pemitldeserocdesert-rock-proposed-permit.pd). PPL should re-evaluate the costs and benefits ofreducing PMIO to the level that EPA has said represents BestAvailable Control Technology usingtechniques developed inthe EPA Control CostManual. In orderto move forward with the BARTprocess, we ask that you submitthe requested information and analysis to our office withinthirty 

### days from the date ofthis letter. Onceagain, we would like to thankyou for submitting the BARTanalysis and acknowledge the work thathas gone into preparing this analysis. Ifyou have any questions, please contact Laurel Dygowski at (303) 312-6144. 

# ',.....**~RC~** ./

# "--~J?~

# ~VidetiCh, Director Airand Radiation Program

6

# APPENDIX 2 Detailed Cost Calculation Tables

## .. Table 4.1-1 

### PPL !SART CO!tt**~~lysls 'N~!~~!~~I:)I~g_~.!I_~rJ;~I~!CI(J~~~mr~11Q.ptJ~~** **~)** 330 ",egawatt Coal**Fi!ec:l~eam** Electric lJnit Tangentially Fired**SUb-bltumlrlous~()al Combustl()~~t**  Colstrip Unit 1or Unit 2**J.ID1~~c:lc:I~lon_ !()l!x.lstJrlg~C:!l.I~!>~!!t:.Q.~~!~I!~~IltrOI**  by 

### 880/0 30-dayAverage El11lsslon Rates Stack ExhaustVolumetricFlowrate, (adm) Q 1,233,748 tyiaximum**Gro~s H~Cl!lnpllt.**  MMBtulhr AvgofUnits1&2 

### 3,.9:lQ Design Percent Load % 92 Uncontrolled S02**Emi~sions** (withlowScoal) IbsIMMBtu 30-dayavg OAOO**~()ntrolle.cJ SQlED}i~~i9IlS(wittl**  ClcJcjecjlirneL IbsIMMBtu

___• --_-'_0'. _. __ ", •• _. 30::(jaYavg 0.200 E:)(hClLJsfrelllRElrature, 

### eFL T 314 Stearn l"LJrblnePOVierQutput (TMW) M'N 330 !-iours()!Qpe.ration hr 8,059 !,J.Ilf.9n!rQJLecLSQlE:fTlissiolls•.**(1~1I1!)** 1575.8 Unc;ontrolled$Q2 Emissions, (tonslyr) 6350**COntrollecl~Q2** E:missioni;, (tonlyr) 3175 Value of Power Generated $IkW-hr 0.08 Annual Interest Rate, (%) 7 Depreciation SChedule (yrs) 15 Capital Recovery Factor, CRF CRF 01098

Unit Item Cost Item Suggested Factor Cost Cost

Costof Lime Inlection Equipment<l) Equi**PITl~lltCost** Total,(EC) (2007 dollars) $1,500,000 Total Capital Costs, TCC $1,500,000 DirectAnnual Costs, DCC

Operations and Maintenance Costs Lime Cost $375,000 Miscellaneous O&M Costs $,year

.- - ..... _. --- $125,000 Total O&M Cost $500,000 IndirectAnnual Costs

Capital Recovery CRF'TCC $164,692

Total IndirectAnnual Costs, lAC $164,692 Total Annual Costs, TAC· DAC + lAC $664,692
.cost E:"ectlvenesli ($ltonpollutant Removed) $209

Cost data references: 1) Includes lime injection equipment based on the cost of similarequipmentfor units 3&4Table 4.1-2 PPL BART CostAnalysis**W~1~C:;I!I~_I?IlJg_~':I",,!rJ~'-~,!I~~C::~r1tr~IJQptt~!1** 

## J}

.. 330**~~gfl\YClt!** Coal Fired Steam Electric 

### lJrllt**TangentiallyF.lred~ub~ItuI11Ir10u!j** Coal ComblJstlonatColstrlp Unit 1or Unit 2**L~I11~.~~cllt.l~1J .~~.E;)(I!jnlJg~.~rll~~er:s.-.9veraJIC::~n.tr01**  

### byS'%

Maximum 24-hr Average Emission Rates
Sta.ck ExhaustVolumetric Elowrate, (acfm)**.t\:1i3,l(irnu.m.~r()sslj~atlnQut** Design PercentLoad**Uncontrolled$O~Emissions** (with low § coal)**(::()ntr()IIEjQ§Q~E:mi!)sions (~ith** **eldQ~cilirT1e)** B<helustTemperi3ture, eF) §tei3rnTlJrbinepower Output (Tt\:1W) rl()lJrsQfQpera.tiQn.**LJ_n.c()mrQII~ci§Q~E:.ml!)!)i** on!)L(lgJbr)

..**Ul1comron~(j** §02E:rnission!)!.(tons,yr) C::ontrQUEjQ.SQ2.E:missions, (ton/yr) Value of Power Generated ,A,nnuallnterestRate, (%) Depreciation Schedule (yrs) Capital Recovery Factor, CRF

Cost Item

Cost of Lime Injection**Equipmen~l)** E:Cluipment CostTotal, (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
<:ost Effectiveness ($lton pollutant Removed)

Cost data references: Q MMBtulhr % IbsJMMBtu IbsJMMBtu T MW

hr

$/kW-hr

CRF

Suggested Factor

Lime Cost

$,year

CRF'TCC Avg of Units1&2 24-hr avg 24-hr avg

Unit Cost

(2007 dollars) 1,233,748**~c94Q** 92 0.760 0.380

314 330 8,059 2720.0 10961 5480 0.08 7 15 01098

Item Cost

$1,500,000 $1,500,000

$375,000 $125,000 $500,000
$164,692 $164,692 $664,692 $121

1

### J Includes lime injection equipment based on the cost of similar eqUipmentfor units 3&4

### TangentialI}' Fired**SUb-bltumlno Stack~hi:JlJ§t** **V()lu_n1~tri** cFIOWT(jte,tacfm) MaximumGross Heat Input Design Percent Load**Uncor1tr()lI~d~Q2~n1issi()ns{~thlo~ ~f()aIJ**  Controlled S02 Emissions{with added lime) ExhaustTemperarure, (OF) SteamTUrbinepower Output (TMW) Hours of9peration**lJncol1trolled~()2Emissions,{lblbrl. lJnc(mtrollecJ~Q2**  Emissions, (tonsNr)**C()rJlroUed~02Emi** ssions, ttonfyT) Value of Power Generated**~~,** u**~~** w, .,_ .'

__, _ _ _ __ ,Annual InterestRatE;l, (,*,) [)epreciationSchEldule (yr§) Capital Recovery Factor, CRF**u~~~~Cl~**

Cost Item

Costof Lime Injection Equipment<l) Basic lime injectionequipment Additional sprays and absorption pump Totalc:al>ital Costs, TCC DirectAnl"lual Costs,I)CC

Operations and Maintenance Costs Additional fresh water 35% increase in scrubber downtime 

### Table 4.1-3 PPI.BART Cost Analysis Wet 

### Scrubbing Sulfur Dioxide Control (Option 2)

330 Megilwiltt**~oill** 

### Flre<l**St~al1l** 

### Electric Unit Combustion

## Cit**Col~tJ:lp** 

### Unit 1or Unit 2**Ma)(ll!!lI!"I..II1!~A<I<I~t1~I1.~~Y~I1!l1-rJ~~Lub~~LUP9~Ci~<I~~-~910f0~Ft~moval** 

### 30-day Average Emission Rates
Q 1,233,748 MMBtulhr Avg of Units1&2 3,940 % 92 Ibs/MMBru**~O-daYavg** 0.400 IbsIMMBtu 30-dayavg 0.150 T 314 MW 330 hr 8,059 1575.8

6350 2381 $/kW-hr 0.08 7 15 CRF 0.1098

Unit Item Suggested Factor Cost Cost

(2007 dollars) $1,500,000 $1,500,000



### --- $3,000,000

Lime Cost $550,000 $10,000 (Lost revenue per unit) $525,000 35% increase in scrubber O&M

.,,- ---
-- ----- -- .- ,­**~.** . , -,- ,_.- ---_., '.

- $390.000 Miscellaneous O&M Costs $fy'ear $125,000 Total O&M Cost $1,600,000 IndirectAnnual Costs

Capital Recovery CRF'TCC

--- $329,384

Total IndirectAnnual Costs, lAC $329,384 Total Annual Costs, TAC • DAC + lAC $1,929,384 Cost Effectiveness ($/ton pollutant removed) $486

Cost data references: 111nclugeslime injection equipment based on the cost ofsimilEir eqUipmentf()r units 3&4Table 4.1-4 PPL BART CostAn"lysls Wet Scrubbing Sulfur Dioxide c:ontrol (Opdon 2)



### 330 Mt!gawatt Coal Fired**~eam** Electric Unit Tangendallyi=lred**~~tJ~IttJ~I** 

## ...**()~~** Coal Combusd011 ilt Colstrip I.Inlt 1 or Unit 2 Maximum**LI~t!~~~~()I1~ ,,~e**  

### ....**~!!~~r,,!b~t!rl.lJ.lg!Cl.~t!~·.~10/0~t!l1lo~al** Maximum 24-hrAverage Emission Rates
Stack Exh8LJstVolumetric Flowrate, (acfm1 Q 1,233,748 Maximum Gross Heat Input MMBtulhr Avg of Units1&2 3,940 Design Percent Load % 92**UncontroUeejSQ2I::mis?ion?(~~low ~oal)**  IbsiMMBtu**24-hr~g** 0.760 Controlled S02 Emissions (With added lime) IbsiMMBtu 24-hr avg 0.285 ExhaustTemperature, eFJ T 314 SteamTurbine Power Output (TMW) MW 330 HoursofOperation hr 8,059 Uncontr()lIeej S02 Emissions, (Iblhr) 2720.0 Unc;ontrolleej ?()2 Emissi()ns, (t()nsfyr1 10961 (;ontroliedS02E::rnis?ions, (tontyr) 4110 Value of Power Generated $/kW-hr 0.08 AnnuallnterestRate, {,*,1 7 Depredation Scheejule (yrs) 15 Capital Recovery Factor, CRF CRF 01098

Unit Item Cost Item Suggested Factor Cost Cost

Costof Lime Injection Equipment<tl Basic lime injection equipment (2007 dollars) $1,500,000 Additional sprays and absorption pump $1,500,000 Total Capital**C~sts,** TCC $3,000.000 DirectAnnual**C~sts.** DCC

Operations and Maintenance Costs Lime Cost $550,000 Additional fresh water $10,000 35% increase in scrubber downtime (Lost revenue per unit1 $525,000 35%**increaseiQscrLJ~ber** O&M $390,000 Miscellaneous O&M Costs $fy'ear $125.000 Total O&M Cost $1,600,000 IndirectAnnual Costs

Capital Recovery CRF"TCC $329,384

Total IndirectAnnual Costs, lAC $329,384 Total Annual Costs, TAC • DAC + lAC $1.929,384 Cost Effectiveness ($/ton pollutant removed) $282

Cost data references:
11 Includeslime injectionequiprnent ba?ed onthe cost of similar equiRment for units 3&4Table 5.2-1: SNCR CostAnalysis for Colstt1p units 1&2 (each) 30· dey average emission rate case·contol to 0.151b1MMBtu Maximum Heat Input (MM Btulhr) CI, Annual Average Heat Input (MMBtulhr) 0... NOx Emission Rate (Uncontrolled,lbslMMBtu) NOx Emission Rate (Controlled,lbslMMBtu) Nomnahzed Stoichometric Ratio (NSR) from Figure 1.8 (of EPA CCM) Capacity Factor (hrstyr attuliload) O<erall No,. Reduction Efficiency. (%) eff Uncontrolled NO, Emissions, (lbIIlr) Uncontrolled NO, Emissions, (tonslyr) Controlled NO, Emissions, (tonlyr) Annual Interest Rate, (%) Coal Cost ($/MMBtu) Water Cost ($lgallon) Electricity Cost ($ikWhr) Urea Cost for a 50% Solution ($/gallon) SNCR Life, (yrs) Capital RecoveIY Factor, SNCR CRF(20yr) Design Parameters Suggested Fac10r SNCR Capital Equipment Cost SNCR System, including ( PerControl Cost Manual, Equation 1.19) • Urea unloading skid Includes equipment, instrumentation, sales tax - Centrigugal pumps for unloading freight, math modeling, urea pumps, etc.
- Vertical insulated fiberglass urea storage tank • Pumps, heaters,valves, pressure, temp, flow instrumentation • InJection zone meteringfor five zones •Water booster pumps • Urea solution distribution module • Valved connectors for urea and atomizing air

- Flowmonitoring for each injector- wall and lorlance type injectors • NOx momtorWIth feedback controls for urea Injection control

- Foundationfortank

- EqUipment skids,

- Platfomns, stralrways to access injectors Urea consumption (as CON,I-4,lblhr) (EPAiEPRI equation 115) Urea consumption (as 50% aqueous solution, gaVhr) Water consumption (dilute to 10% aqueous solution, gaVhr) Total Olrec1 Capital Costs, TOCC (See cost reterences notesl Indlrec1 Costs Indlrec1lnatallatlon Costs

General Facilities Cost 005xIDCC Engineering and Home Office Fees 010xIDCC Process Contingency 005xIDCC Total Indirect Installation Costs, TIlC Olher Capital Coate

Project Contingency 015x(IDCC + TIle) Preproduction Cost 0.02 x(IDCC +TIIC + Project Contingency) Total OtherCapital Costs, TOCC IDCC + TIIC + Proj Contingency Total Capital Costs, TCC IDCC +TIIC +TOCC Olrec1 Annual Costs Urea cost (50% aqueous solution) 50% solution @ $0.85/gal Dilution water cost Electricity (added cost due to SNCR) CCM, Equation 123 Added coal cost Increased coal consumption forvaporization Annual maintenance cost 0015xTCC Total Direct Annual Costs, IDAC Indirec1 Annual Costs

Administrabve 002xTCC PropertryTaxes 001xTCC Insurance 001xTCC Capital RecoveIY

- SNCR System CRFxTCC Total Indirect Annual Costs, TIAC Total Annual Coate, TAC·TOAC +TlAC Costerectlveness ($/ton pollutant Removed)

Cost data references: OAQPS Control Cost Manual (CCM), Sixth Edition. EPA-452-02-001, JanuaIY 2002 IDCCAdjusted using CI=96.089 (1998) to CI=121303 (2008) Equation 119from OAQPS CCM DCC =$950xQ,x[2375/CI,f'" x[0.66 + 085xeft] 3,940 3,663 3D-day average 0.35 3D-day average 0.15 1.50 8,059 571% 1,378.8 5,556 2,381

7% 1.60 00001

008 0.85

20 0.094 Value Costtaken from EPA Cost Manual Equation 1.19 (See notes for equation)

1,255 265 1,355 $4,056,968

$202,848 405,697 202848 $811,394
$730,254 $111,972 $842,226 $5,710.588
$1,812,057 1,201 $0081kwhr 61,346 HV=900BtuI1b 145,675 85659 $2,105,937

$114,212

57,106 57,106 539,039 $767463 $2,873,399 $905Table 5.2·2: SNCR Cost Analysis for Colstrip Units 1&2 (each) Maximum 24hr·Aver.ge Eml••lon RlIlo C••e·Control to 0.211blMMBtu Maximum Heat Input (MM Btulhr) Annual Average Heat Input (MMBtulhr) 

## a.... NO>: Emission Rate (Uncontrolled, IbsIMMBtu) NO>: Emission Rate (Controlled, IbsIMMBtu) Normalized Stoichometric Ratio (NSR) from Figure 1.8 (of EPA CCM) Capacity Factor (hrs./yr at full load) Overall NO, Reduction Efficiency. (%) eft Uncontrolled NO, Emissions, (Iblhr) Uncontrolled NO, Emissions, (tons./yr) Controlled NO, Emissions, (tonlyr) Annual Interest Rate, (%) Coal Cost ($IMMBtu) Water Cost ($Igallon) Electricity Cost ($/kWhr) Urea Cost for a50% Solution ($Igallon) SNCR Life, (yrs) Capital RecOYeIY Factor, SNCR CRF(20yr) De.lgn Paramot.rs Sugg.st.dFactor SNCR Capital Equipment Cost SNCR System, including (PerControl Cost Manual, Equation 1.19)
- Urea unloading skid Includes eqUipment, instrumentation, sales tax - Centrigugal pumpsfor unloading freight, math modeling, urea pumps, etc.
- Vertical Insulated fiberglass urea storage tank

- Pumps, heaters. val¥es, pressure, temp, now instrumentation

- Injection zone metenng for five zones

- Water booster pumps

- Urea solubon disDibution module

- Val¥ed connectors for urea and atomizing air

- Flow monitonng for each injector- wall and lor lance type injectors

- NO>: monitorwith feedbackcontrols for urea injection control

- Foundationfortank

- EqUipment skids,

- Platforms, strairways to access injectors. Urea consumption (as CON,I-4, Iblhr) (EPAIEPRI equation 115) Urea consumption (as 50% aqueous solubon, galll1r) Water consumption (dilute to 10% aqueous solution, galll1r) TolliDirectCapital Coata,TOCC (S.ecootrererencea notes, Indlr.ctCoata Indlr.ctIn818l1atlon Coata

General Facilities Cost 005xTDCC Engineering and Home Office Fees 010xTDCC Process Conbngency 0.05xTDCC Total Indirect Installation Costs, TIIC Other Capital Coata

Project Contingency 015x (llDCC +TIIC) Preproduction Cost 0.G2 x (TDCC + lllC + Project Contingency) Total Other Capital Costs, TOCC TDCC +TIIC + Proj Contingency Tol8l Capital Coata,TCC TDCC +TIIC +TOCC Dlr.ctAnnual Co.ta Urea cost (50% aqueous solution) 50% solution @$0.851gal Dilution water cost ElecDicity (added cost due to SNCR) CCM, Equation 123 Added coal cost Increased coal consumption forvaporizabon Annual maintenance cost 0015xTCC Total Direct Annual Costs, TDAC Indlr.ctAnnual Coata

Administrative 002xTCC PropertryTaxes 0.01 xTCC Insurance 0.01 xTCC Capital RecOYeIY

- SNCR System CRFxTCC Total Indirect Annual Costs, llAC Tol8I Annual Coata,TAC·TOAC +TlAC CootEft'eetlv.n...(S/ton poUut.ntRemov.d)

Cost data references' OAQPS Control Cost Manual (CCM), Sixth Edition, EPA-452-02-001, JanualY 2002 TDCC Adjusted using CI=96 089 (1998) to CI=121303 (2008) Equation 1.19 from OAQPS CCM Dee =$950 x Q.x[2375/a"f.m x[O 66 + 0.85 xeft] 3,940 3,663 24-hr average 0.49 24-hr average 0.21 1.50 8,059 571% 1,8765

7.562 3,241

7% 1.60 0.0001

0.08 085

20 0094 Value Costtaken from EPA Cost Manual Equation 1.19 (See notes for equation)

1,757 370 1,896 $4,056,968

$202,848 405,697 202848 $811,394
$730,254 $111,972 $842226 $5,710,588
$2,536,880 1,681 $0081kwhr 85,884 HV=900 Btullb 203,945 85,659 $2,914,048

$114.212

57,106 57,106 539,039 $767463 $3,681,511 $852Table 5.3-1: SCR Cost Analysis for Colstrip Units 1&2 (each) 3O....y Av".goCOlO· Comrolto NSPS Eml..lon Rolo (O.11Ib/MMBtu) Maximum Heat Input(MMBtulhr) a" 3,940 Annual Average Heat b1put (MMBtulhr) a""" 3,663 NO>< Emission Rate (Uncontrolled, IbslMMBIlJ) NOxin 3D-dayavg 0.35 NO>< Emission Rate (Uncontrolled,**~slMMBI!J)** NOxin 3D-dayavg 0.11 Normalized Stoichometric Ratio (NSR) from Figure 18(of EPA CCM) 1.50 Hours of Operation SCR NO, Reduction EffiCiency, (%) 

## e" 8,059 68.6% Uncontroled NO, Emissions, (Iblhr) 1,378.8 UncontroHed NO, Emissions, (tons/1f) 5,556 Controned NO, EmiSSions, (tonlyr) 1,746 Fw(we! sctlMMBI!J) 10,640 BdlaUSl Gas VelOCitytIlrough SCR (ft/min) 960 Percent0,at SCR inlet 4% BdlaustGas Temp atSCR Inlet(deg F) T 700 Ammonia slip (ppmv) slip 5 Ammonia Solution Concentration 29% Sulfur content In coal S 1% Annual Interest Rate, (%) 7% Electricity Cost ($/kWhr) 008 Ammonia Costfor a 29% Soiullon ($/gallon) 085 Catalyst Amortization Period, ("5) 3 SCR Amortization Period, (\<S) 20 Capital Recovery Factor, Catatyst CRF(3,.) 0.381 Capital Recovery Factor, SCR CRF(20 ,.) 0094 D..lgn P.r.mot"o Suggoo1od F.ctor V.lu, ACFM 1,233,278 Catatyst Volume Base Volume 281 xa" 11,070 wINO>< Efficiency Adjustment Factor 0.2869 + (1.058 xe",100) 1.012385714 11,207 wIInlet NO>< Adjustment Factor 0.8524 • (0.3208x NOx,") 096468 10,811 WIAmmonie Slip Adjustment factor 12835
- (0 0567< slip) 1000 10,811 wlSulfur in Fuel Adjustment o9636 • (0 0455xS) 10091 10,910 wiTemperallJre Adjustment Factor 15.16
- (0.03937 x1).2.74xW'xT' 1027 11,204 Area Catatyst (A) Based on velocity 01960 fpm 1,285 Area 01 SCR (tt') 115xA 115 1,477 Lengtll and Width of SCR (ft) Square Bed 3844 N layers V,,,/3.1IA 2.81 Number of Layers (to nearest Integervalue) 30 Height of a Layer (ft) (11.,..) (V",", Nlayersl A) + 1 391 Number of Empty Layers (For cata/ySl management) 1 SCR Height Per b1dustry Standards (ft) hsc. : """X(7 +11.,..) • 9 526 Ibslhrammonia as NH, Noxin xa." xNSR xeff< 17/46 488 gallonslhr of aqueous ammonia 225 Total Dlroct Capital Cooto. TOCC (S..coot"',,onc

..not..) $20,407,368 IndirectCom Indlroct "',tallotlon Co,to General Faciliaes Cost 0.05 x10CC $1,020,368 Engineering and Home Office Fees 0.10x1OCC 2,040,737 Process Contrngency 0.05x1OCC 1020368 Totallndlrectlnstallaoon Costs, TIIC $4 081474 Oth" C.pltalCom

Project Contingency o15 x[TOCC +TIIC) $3,673,326 Preproduction Cost 0.02 x[TOCC ,TIIC 'ProjectContingency) $563243 Total OtIler Capital Costs, TOCC 10CC + TIIC • Pro) Contingency $4 236 570 Total Capital Com.TCC 10CC +TIlC +TOCC 528.nU11 DirectAnnual Co,to

Annual Ammonia Cost $0.85/gal $1,540,340 Electricily (Added Cost due to SCR)' CCM, Equation 248 $008/m-hr 636,076 Annual Maintennace Cost o015xTCC 430881 Total Direct Annual Costs, TDAC $2607297 In<lrectAnnual Costo

Administrative o 02xTCC $574,508 Propel1JY T axes 001 xTCC 287,254 Insurance 0.01 xTCC 287,254 Capital Recovery

- Catatysr CRF(3,.)xCatatyst Cost 1,238,121 Capital Recovery

- SCR System Less Catatyst CRF(20 ,.)x(TCC

- Catatyst Cost) 2404 772 TotallndireC! AnllJai Costs, TIAC $4 791 910 Total Annual Com.TAC·TOAC +TlAC $7.399,207 Coo1Ell'actlvona..(SIlon pollulanlR,mo.ad) Cost data references OAQPS Control Cost Manual (CCM), Sixtll Edltion, EPA-452-02-001, January2002 IDCC Adjusted using 0:96.089 (1998) to CI:121.313 (2008) Notes: 1. Electricitycost includes ammoma vaporization heaters 2. Assumes replacement of all catalyst at lIle end of 3years witll replacement catatyst@$290 cubiC Inot 51.942Table 5.3·2: SCR CostAnalysis for Colstrip UnItS 1&2leachl Maximum24./lrAvorage C... MaxJmum Heat Input (MMBtulhr) Annual Average Haat Input (MMBtulhr) NOx Emission Rate (Uncontrolled,lbSiMMBnJ) NOx Emission Rate (Uncontrolled,lbSiMMBnJ) Normalized Stoichometric Ratio (NSR) Hours or Operation SCR NO, Reduction Efficiency. I'll.) Uncontrolled NO, Emissions. (Iblhr) Uncontrolled NO, Emissions, (lonslyr) Controlled NO, Emissions. (to"""" Fw (wet scfIMMBnJ) Exhaust Gas VeloCl!)'through SCR (Il/min) Percent 0, at SCR inlet Exhaust Gas Temp at SCR Inlet (deg F) Ammonia slip (ppmv) Ammonia Solution Concentration Sulfur content In coal Annual Interest Rate. (%) Electrici!)' Cost ($lkWhr) Ammonia Costfor a29% SolUllon ($Igallon)**Cata~** Amortlzation Penod, (yrs) SCR Amortization Period, (yrs) Capital Recovery Factor, Catatyst Capital Recovery Factor, SCR D

••lgnParamll... ACFM Catatyst Volume Base Volume wlNOx Efficiency Adjustment Factor wIInlet NOxAdjustment Factor wlAmmoniaSlip Adjustmentfactor wlSulfur in Fuel Adjustment wITemperature Adjustment Factor Araa Catatyst (Al Area of SCR (11') Length and Width of SCR (n) Nlayers Numberof Layers Height of aLayer (n) (tI.,...) Numberof Emp!)' Layers SCR Height Per .,duslry Standards (n) Ibslhrammonia as NH, gallonslhr of aqueous ammonia -Conlrollo NSPS EmI
..lon RIllt (O.llIbIMMBtul a..., NOlcin NOlcin from Flg

...e 18 (of EPA CCM) aff

T slip S

CRFI3 yr) CRFI20 yr) Sugg••t.dFactor**281x~** 02869 +(1.058 xeff/l00) 08524 +(0.3208 xNOlcin)

12835
- (0 0567 x slip) 09636 +(0 0455 xS) 15.16
- (0.03937 xT) +2.74 X 10'5x T 2 Based on veloic!)' of 960 fpm 115xA Square Sed V",,1311A (to nearest integervalue,

(Voa/ Nlayers! A) + 1 (For catatyst management) hsao= 'I

.... x (7 + 110,...1 + 9 No";n xa...,xNSR xeff x 17146

Total DIr.ctCapitol Com,TDCC (S..coil,,'..anc.snotasl Indlr.ctCosta IndlractInstallation Com General Facilities Cost Engineering and Home Office Fees Process Contingency Total Indirect InstaUation Costs, TIIC othar Capita' Com

Project Contingoncy Preproduction Cost Total Other Capital Costs, TOCC Total Capital Costa.TCC DlractAnnual Colllt

Annual Ammonia Cost Eleclnci!)' (Added Cost due to SCR)' Annual Mainrennace Cost Total Direct Annual Costs, IDAC IndlractAnnual Costa Administratlve PropertryTaxes Insurance Cap,tal Recovery

- Catatyst' Capital Recovery

- SCR System Less Calatyst T otallndirect Annual Costs, TIAC Total Annual Colllt, TAC • TDAC +TlAC CostEffactlvan...(SltonpollutantRamovad) Cost data references: 0.05 xIDCC o10xIDCC 0.05 xIDCC

0.15x[IDCC+TIIC) 0.02 x[IDCC +TlIC + Project Contingency) IDCC +TIIC + Pro] Contingency IDCC +TIIC +TOCC

CCM, Equation 248

0015xTCC

002xTCC 0.01 xTCC 0.01 xTCC CRF(3 yr) xCatatyst Cost CRF(20 yr) x (TCC

- Catalyst Cost) 24-hr average 24-hr average 3,940 3,663 0.49 015 1.50 8,059 686% 1,876.5 7,562 2,377 10,640

960 4% 700

5 29% 1% 7% 008 085

3 20 0.381 0094 Valu. 1,233,278

1.012364122

1009592

1000 10091 1.027
115 11,070 11,207 11,314 1'.314 11,417 11}26 1,285 1,477 38.44 294 30 404

1 532 683 315 $20,678,344

$1.033.917 2.067,834 1,033,917 $4135669
$3,722,102

$570722 $4 292 824 $29,106,837
$0.85/gal $0 08Jl<w.hr $2,156,412 636,314 436,603 $3,229,329

$582.137 291.068 291.068 1,295.736 2426504 $4,886,513 S8.11U42 $1.56l1

OAQPS Control Cost Manual (CCM). Sixth Edition, EPA-452-02-001, January 2002 IDCCAdjusted using CI=96.089 (1998) to CI=121 313 (2008) Notes: 1. Electrici!)' cost includes ammonia vaporization heaters 2. Assumes replacemart of all caratysrallhe end of 3years with replacement Calatysl@$290 cubiC footTable 5.3-3: SCR CostAnalysis for Colstrip Units 1&2 leach) JO-d-vAv.rag.c.... MulmumControlto0.06 IblMMBtu M"",mum Heat Input (MMBlIl/hr) Annual Average Heat Input (MMBtulhr) NO>: Emission Rate (Uncortroled, tlsiMMBtu) NO>: Emission Rate (UncOfllJ'oled, tlsiMMBtu) Normalized Stoichometric Ratio (NSR) Hours of Operation SCR NO, Reduction Efficiency, (%) Unconboled NO, Emissions, (Iblhr) Uncontrolled NO, Emissions, (tons/yr) Controled NO, Emissions, (to""",) Fw (wet sclIMMBtu) Exhaust Gas Velocity through SCR (ftimin) Percent 0,at SCR inlet Exhaust Gas Temp at SCR Inlel (deg F) Ammonia slip (ppmv) Ammonia Solution Concentration Sulfur content In coal Annual Interest Rate, (%) Electricity COSI ($lkWhr) Ammonia Coslfora29% Solution ($Igalon) Catetyst Amortizetion Penod, (yrs) SCR AmortizaDon Penod, (yrs) CaPital Recovery Factor, Catetysl Capital Recovery Factor, SCR
D ••lgn P.r

....ot

... ACFM Catatysl Volume Base Volume wlNOx EffiCiency Adjustment Factor wIInlet NOxAdjusnnent Factor wlAmmonia Slip Adjustment 'actor wlSulfur in Fuel Adjusnnent wrremperaDJre Adjusnnent Factor Area Catatyst (A) Area 01 SCR (tt2) Length and Width of SCR (ft) Nlayers Numberof Layers Height 01 a Layar (ft)**(~)** Numberof Empty Layars SCR Height Per Industry Slandards (ft) Ibsihrammonia as NH, gallonslhr of aqueous ammonia C\, 0

... NOxin NOxin from Figure 1.8 (of EPA CCM) eff

T slip S

CRF(3yr) CRF(20yr) Suggllt.dF.ctor

2,81 xC\, 0.2869. (1 ,058 x eff1100) 0,8524 • (03208 x NOxin)

12835· (00587 xslip) o9838 • (0 0455xS) 15,16
- (0,03937xT). 2 74 x 10" xT' Based on velOCity of 960 rpm 115xA Square Bed V,.13,lIA (to nearest Inlegervalue)

(V",; Nlayars!A). 1 (For catatysl management) hsao**="".x(7.~).** 9 Nox," xA

...xNSR xeffx 17/46

Tot.1 DIr.ctCopltllCom,rocc (5••cootr.foronc.snot.s) Indlr.ctCom Indlr.ctInstallation Com

General Faciities Cost Engineering and Home Office Fees Process Contingency Totallndlrect InstalaDon Costs, TUC
Olhsr C.pM.1 Com

Project Contingency Preproduction Cost Total Other Capital Costs, TOCC
Tot.1 C.pM.'Costs,TCC DirectAnnuliCom

Annual Ammoma Cost ElectriCity (Added Cost due to SCR)' Annual Maintennace Cost Total DllectAnnual Costs, TDAC
IndirectAnnu.1 Costs

Administrative PropertryTaxes Insurance Capital Recovery

- Catatyst' Capital Recovery· SCR System Less Calatyst Totallndlrect Annual Costs, TIAC
Totol Annual Co.ts,TAC • TDAC +TlAC
CostE1rtcttvtnts. (Slton pollut.ntR.movtd) Cost data references: 0,05xTDCC 0,10xTDCC 005xTDCC

0,15x [IDCC .TIIC) 002 x(IDCC • TIIC • Project Contingency) TDCC • TIIC • Pro) Contingency TDCC • TIIC • TOCC

CCM, Equation 248

0015 xTCC

o02xTCC 0.D1 xTCC 0,01 xTCC CRF(3 yr) xCatalyst Cost CRF(20 yr) x(TCC

- Cata",!Cost) 30-dayavg 30-dayavg

1.163528571

098468 1000 10091 1027
115

$0 851gal $008f1<w.hr

OAOPS Control Cost Manual (CCM), Sil<!h Edition, EPA-452·02·001, January 2002 TDCC Adjusled using CI=96 089 (1998) to CI=121 313 (2008) Notes: 1 Electricity cost includes ammonia vaporizaDon heaters 2. Assumes replacement ot all Carat,<sl atthe end 013yearswith replacement catatysl@$290cubic foot 3,940 3,883 035 006 150 8,059 82.9% 1,378.8 5,556

952 10,840

960 4% 700

5 29% 1% 7% 0.08 085

3 20 0.381 0094 Vllu. 1,233,278

11,070 12,880 12,425 12,425 12,538 12,877 1,285 1,477 38.44 323 3.0 434

1 544 590 272 $21,015,533

$1,050,777 2,101,553 1050777 $4 203107
$3,782,796

$580029 $4,362,825 529,581,466
$1,861,245

636,200 443722 $2,941,166

$591,829 295,815 295,815 1,422,965 2439789 $5046012 $7,987,179 51,735Table 5.3-4: SCR CostAnalySis 'orColstripUn.s 1&2 leach) Miximum**~r** Avorllgl CII'•Moxlmum Conlrolto0.06 IblMMBtu MaxJmum Heat Input (MMBtulhr) Annual Average Heat Input (MMBtulhr) NO>: Emission Rate (Uncontrolled.lbsJMMBtu) NO>: Emission Rate (Uncontrolied, Ibs!MMBUJ) Nomnalized Stoichometric Ratio (NSR) Hours of Operabon SCR No,. Reducbon Efficiency. (%) Uncontrolied No,. Emissions, (lb/hrJ Uncontrolied No,. Emissions, (tonslyr) Controlied NO, Emissions. (tonlyr) Fw (wet sctIMMBtu) E:<haust Gas VelOCity through SCR (ft/min) Percent 0,at SCR inlet ExhaustGas Temp atSCR Inlet (deg F) Ammonia slip (ppmv) Ammonia Solution Concentration Sulfur content Incoal Annual Interest Rate, (%) Electricity Cost ($!kWhr) Ammonia Costfor a29% Solubon ($lgalionJ CatattstAmortizabon Pehod. (\'f5) SCR Amortizabon Penod. (\'f5) Capital Recovery Factor. Catattst Capital Recovery Factor, SCR D.IlgnPar"",.t

..1 ACFM Catat,-sl Volume Base Volume wiNOx EfficiencyAdjustment Factor wnnlet NOxAdjustment Factor w/AmmoniaSlip Adjustmentfactor wlSulfur in Fuel Adjustment wlTemperature Adjustment Factor Area Catattst (A) Area of SCR (fI') Length and Width of SCR (ft) Nlayers Numberof Layers Height of a Layer (ft)**(tI.,~)** Numberof Empty Layers SCR Height Per IndUstry Standards 1ft) Ibslhr ammoniaas NH, gallonslhr of aqueous ammonia a" a..., NOxin NOxin from Figure 1.8 (of EPA CCM)
eff

T slip S

CRF(3yr) CRF(20yr) Suggtlt.dFlctor

281xa" 0.2869 +(1.058 x eff/l00) 0.8524 +(0.3208 xNOxin)

12835
- (0.0567 xshp) o9636 + (0 0455 xS) 15.16. (0 03937 xT) +2.74 x 10-'xT' Based on velOCity of 960 !pm 115xA Square Bed V,

../3.1/A (to nearest Integer

....Iue)**(V~** Nlayers!A) + 1 (For catattst managementJ hsat=

.......**x(7+~)+9** Noxm x**Q~,x** NSR xeffx 17146

TotllDIr.ctCapilliCostl,TOCC (5••costreterenc,"not.l) IndirectCostl IndlrectlnstllllUonCostl

General**Faci~ties** Cost Englneenng and Home Office Fees Process ConMgency Total Indirect Instanabon Costs, TIiC Othor ClpllilCostl

Project Contingency Preproduction Cost T otai Ot!1er Capital Costs, TOCC Totl'ClpilitCOlts,TCC DIr.ctAnnual Costl

Annual Ammonia Cost Electricity (Added Cost due to SCR)' Annual Maintennace Cost Total Direct Annual Costs, TDAC Indlr.ctAnnual COlts

Adminjstratlve PropertiyTaxes Insurance Capital Recovery

- Catattst' Capitel Recovery. SCR System Less Catalyst Total IndirectAnnual Costs, TlAC TotalAnnual Costl.TAC·TOAC +nAC CostElr.ctIv.n

...(Slton pollullntR.mov.d) Cost data references· 0.05xTIDCC 0.10xTIDCC 0.05xTIDCC

0.15 x (TlDCC +TlIC) 002 x(TOCC +TIIC + Project Contingency) TDCC +TIIC + ProJ Conbngency TDCC +TlIC +TOCC

CCM, Equanon 248

0015xTCC

002xTCC 0.01 xTCC 0.01 xTCC CRF(3 yr) xCatattst Cost CRF(20 yr) x(TCC· Catattst Cost) 24·hr average 24-hr averaga

1.163528571

1009592

1000 10091 1027
115

$0 851gal $0.08I1<w-hr 3,940 3,663 0.49 0.084 1.50 8,059 82.9% 1,876.5 7,562 1,296 10,640

960 4% 700

5 29% 1% 7% 008 085

3 20 0.381 0.094 Vllu. 1,233,278

11,070 12,880 13,004 13,004 13,122 13,476 1,285 1,477 38.44 3.38 3.0 450

1 550 826 380 $21,332,811

$1,066.641 2,133,281 1066.641 $4 266 562
$3,839,906

$588786 $4.428,691 SJO,028,064
$2.605,742

636,488 450421 $3692651

$600.561 300.281 300.281 1,489,213 2465534 $5155869 $8.848,520 $1,412

OAQPS Control Cost Manual (CCM). Sixth Edition. EPA-452-02-001. January 2002 TlDCC Adjusted using CI=96.089 (1998J to 0=121 313 (2008) Notes: 1 Electricity cost includes ammonia vaporizabon healers 2. Assumes replacement of allcatat;statthe end of 3years WIth replacement catattst@$290 cubiC footTable 6.1·1 PPL BART CostAnalysis Electr!>statlc Preclplta_torParticulate Control 330 Megawatt Coal Fired steam Electric Unit Dry-Bottom Combustion In Colstrip Unit 1and Unit 2 (each) 0.015 Ibs/MMBtu Emission Rate

Stack Exhaust Volumetric Flowrate, (adm) Q 1,233,748 Maximum Gross Heat Input MMBtuihr 3,940 Uncontrolled**Fi~erable** PM Emissions IbslMMBtu 0.0525

- -- .- ..-. ­ Controlled Filterable PM Emissions IbslMMBtu 0.0150 ExhaustTemperalure, ("F) T 314 SteamTurbine Power Output (MVV) M'N 330 Hours of Operation hr 8,059 Overall PM Re(juction Efficiency, (%) % 7143% Uncontrolled PM Emissions, (Ibihr) 206.8 Uncontrolled PM Emissions, (tonslyrl 833 Controlled PMEmissions, (tonlyr) 238 Annual Interest Rate,J%) 7 DepreciationSchEldule, (yrs) 20' Capital Recovery Factor, CRF CRF 0.0944**Cost~em** Capital Equipment Cost (1988 EPRI Study) EquiRment CostTotal, (EC) Retrofit Factor Direct Capital Costs Purchased Equipment Costs

ESP 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 Dlr.ctCapital Costs, DC Indlr.ct Capital Costs

Engineering Construction and Field Expenses Contractor Fees Start.Up Performance Test Model Study Contingencies

Totallndlr._ct Capital Costs,IC Total Capital Costs, TCC • DC + IC Suggested Factor

CaRital Cost ($/KW) EC (Adjusted by Cost Index Calcs) New Equipment Costx 1.4

(Factors for ESPs from OAQPS Manual) EC 0.10EC 0.03 EC 0.05EC PEC=1.18EC

O.04PEC 0.50PEC 0.08 PEC 001 PEC 0.02 PEC 0.02 PEC DIC =0.67 PEC As Required, SP As Required, BLDG DC = 1.67 PEC + SP + BLDG

0.20 PEC 0.20PEC 0.10PEC 001 PEC 001 PEC 0.02 PEC 0.03 PEC IC =0.57PEC TCC =224 PEC + SP + BLDG Unit Cost

60 (2008 dollars) (2008 dollars) Item Cost
$19,800,000 $32,201,314 $45,081,839

$45,081,839 $4,508,184 $1,352,455 $2,254,092 $53,196,571
$2,127,863 $26,598,285 $4,255,726 $531,966 $1,063,931 $1,063,931 $35,641,702 $0 $0 $35,641.702
$10,639,314 $10,639,314 $5,319,657 $531,966 $531,966 $1,063,931 $1,595,897 $30,322,045 $119,160,318Table 

### 6.1-1 continued PPL BART**Co~t** Analysis r:lectrostatlc. Preclpl!ator Particulate Control 

### 330 Megay/att COill FlrecJ Steam r:lectrlc:.Unit

. Dry-BottomCombw;tlonlllColstrlp Unit 

### 1 and Unit 2(each) 

### 0.015 Ibs/MMBtu Emission Rate
DirectAnnual Costs

Utilities

Fan Power1) TR Set and Rapping Power2) Ash [Jispos€l1**Cos~** Fp =(181 x 1O-4)(Q)(delta P)(hrsfyT) Transportation notincluged (O.linw.c assumed) $0.08/kwhr

$401l0n $143,975 $19,213 $23,812 Operating Labor

Operator Supervisor 10hrlshift 150/0 of Operator $22861hr $30,222 $4,533 Maintenance

Labor Materials Total Direct Annual Costs, DAC 0.01 PEC**1~~!$** 2008 $ 1987 $ 2008 $ 

### "**~1?M6** $42,586 $531,966 $890,289 $1,154,630 IndirectAnnual Costs

Overhead Administrative

,**--~** ._..._----,.,--< PropertryTaxes Insurance Capital Recovery 60% of Operating Labor and Maintenance Costs 0.02TCC 0.01 TCC 0.01 TCC CRF*TCC $580,578 $2,383,206 $1,191,603 $1,191,603 $11,243,871 Total IndirectAnnual Costs,IAC $16,590,862 Total Annual Costs, TAC
.. DAC + lAC $17,745,492 Cost Effectiveness ($/ton pollutant removed) $29,809

Cost data references: Control Technologies for Hazardous Air Pollutants, Govemment Institutes, Inc, Office of Research and Development CentElrforEnvironmental Research Information, June 1992. OAQPS Cost Manual, Sixth Edition, EPA-452-02-001, January 2002 Cost data assumptions:

Costs adjusted by cost indices for 2008 CI=121313, 1987 CI=72.487, and 1988 CI=74.587 1. ESP's have low pressure drop (0 1"w.e. assumed)

- Electricity cost at $008il<\lVHr is typical 2 Transformer/RectifierandRapping power isa function ofthe Specific Collecting Area(SCA)

The OAQPS Control CostManual extimates P= 1.94x 10-3x SCAx hrs,yr as the total of electrification and rapping electiciitypower consumption in kVVhrsfyT SCA is based on aSCAof 250 tr-/1,OOO ACFM and amigration velocity of 10 crn/sec characterisitc of coal fly-aSh 3. Collector area= 250 tr-/1,OOO ACFM x Q = 308,437 

## tr­Table 6.1-2**PPkB~~T** CostArIalysls Electrostatic Precipitator Pl1rt1clJlate Colltrol 330 MegawattCoal Fired**St~"Ille:lectrlc** UIlIt Dry-Botto",**Combl:ls~onJIlColstrlp** Y1l1t1i1lld Unit 2(each) 0.010 IblMMBtu Emission Rate

Stack Exhaust Volumetric Flowrate, (acfm) Maximum Gross Heat Input

,Uncontrolled FilterablePM Emis?ions Controlled Filterable PM Emissions ExhaustTemperature, ("F) SteamTurbine Power Output (MVV) Hours ofOperaton Overall PM Reduction Efficiency, (%) LJncontrolled pM Emissions, (Iblhr) Uncontrolled PM Emissions, (tonSJ'yr) ,Controlled PM Emissions, (tonlyr) Annual Interest Rate, (%)**[)~preciation** SchedUle, (yrs) Capital Recovery Factor, CRF Q 1,233,748 MMBtulhr 3,940 IbslMMBtu 0.0525 IbslMMBtu 0.0100 T 314 MN 330 hr 8,059 % 80.95% 206.8

833 159

7 20 CRF 0.0944

Cost Item
Capital Equipment Cost (1988 EPRI Stucly) Equipment Cost Total, (EC) Retrofit Factor Direct Capital Costs Purchased Equipment Costs

ESPand Auxiliary Equipment Instrumentation Sales Tax Freight

Purchased Equipment Costs, PEC Direct Installation Costs

Foundati.ons and Supports Handling and Erection Electrical Piping Insulation for Ductwork PalnMg

Direct Installation Cost, DIC Site Preparation Building Total Direct Capital Costs, DC IndirectCapital Costs

Engineering Construction and Field Expenses Contractor Fees Start:Up Performance Test Model Stucly Contingencies

Total IndirectCapital Costs, IC Total Capital Costs,TCC· DC + IC Suggested Factor
Capital Cost ($Jl<W) EC (Adjusted by Cost Index Cales) New Equipment Costx 1.4

(Factors for ESPsrrom OAQPS Manual) EC 0.10 EC 0.03 EC 005EC PEC 

### =1.18 EC

004 PEC 0.50 PEC 0.08 PEC 001PEC 0.02 PEC 002PEC DIC 

### = 0.67 PEC As ReqUired, SP As Required, BLDG DC

### =1.67 PEC + SP + BLDG

0.20PEC 020 PEC 0.10 PEC 001 PEC 001 PEC 002 PEC 003PEC IC

### = 0.57 PEC TCC =2.24 PEC + SP + BLDG Unit Cost

60 (2008 dollars) (2008 dollars) Item Cost
$19,800,000 $32,201,314 $45,081,839

$45,081,839 $4,508,184 $1,352,455 $2,254,092 $53,196,571
$2,127,863 $26,598,285 $4,255,726 $531,966 $1,063,931 $1,063,931 $35,641,702 $0 $0 $35,641,702
$10,639,314 $10,639,314 $5,319,657 $531,966 $531,966 $1,063,931 $1,595,897 $30.322,045 $119,160,318Table 6.1-2 condnued PPL BART Cost**Analy~i~** Electrostadc Precipitator Pardculate Control 330**Meg~watt** Coal Fired**~eamElectr~c** Uilit**[)ry~ottOf!l~C:()f!1!lI.lStl~~I1JI1. C:()I~t!lpJ.I.I}ltt~I1<1YI1-'!.~~** **(t!~c::h)** 0.010 Ib/MMBtu Emission Rate

DirectAnnual Costs

Utilities

Fan Power1) Fp =(1.81 x 10-4 )(Q)(delta P)(hrs¥) (O.1inwc.assulTied) $143,975 TR Setand Rapping Power2) $0.08/kwhr $19,213 Ash Disposal Costs Transportation not included $40lton $26,987**QR~rati.ngLabor** Operat()r 10hr/shift $22.86/hr $30,222 Super\'isor 15"10 of Operator $4,533 Maintenance

Labor**$0.0825~** Collector Area(3) 1987 $ $25,446 Materials 001 PEC 2008 $ 

### 1987$ 

## .,**$:I~~~?~** $531,966 2008 $ $890,289 Total DirectAnnual Costs, DAC $1,157,805 IndirectAnnual Costs

Overhead 60"10 of Operating Labor and $580,578 Maintenance Costs Administrative 0.02TCC $2,383,206 PropertryTaxes 0.01 TCC $1,191.603 Insurance 0.01 TCC $1,191,603 Capital Recovery CRF*TCC $11,243,871

Total IndirectAnnual Costs, lAC $16,590,862 Total Annual Costs, TAC • DAC + lAC $17,748,667 Cost Effectiveness (S/ton pollutant removed) $26,307

. Cost data references:

Control Technologies for Hazardous Air Pollutants, Govemment Institutes,lnc., 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:

Costsadjusted by cost indices: for 2008 CI=121.313, 1987 CI=72487, and 1988 CI=74.587 1. ESP's have low pressure drop (0.1 "w.c. assumed)

- Electricity cost at $0081kW'Hr is typical 2 Transformer/Rectifier and Rapping power is afunction ofthe Specific Collecting Area (SCA)

The OAQPS Control Cost Manual extimates P= 1.94x 10-3xSCA x

### hrs¥ as the total of electrification and rapping electiciity power consumption in kVIIhrS¥. SCA is based on a SCAof 250 tr/1,OOO ACFM and a migration velocity of 10 em/sec characterisltc of coal fty-ash 3. Collector area= 250 tr/1,000 ACFM x Q = 308,437 tr-- Table 6.1-3 PF'L BART CostAnalysis Pulse Jet- Fabric Filterfor Addmonal Particulate Control**~-~** 330 Megawatt Coal Fired Steam Electric Unit**PUlverlzed~oal** -**[)ry~C)tt()111 C0I11l)us11()~!~_~C)lstrlp**  Unit 1 or Unit 2(each)

Stack Exhaust Volumetric Flowrate, (acfm) Maximum Gr()ss Heatlnput Uncontrolled merable PM Ernlssions Controlled Filterable PM Emissions _.-- .

__ . --_.- - - - ...._-- - -- .- - ExhaustTemperature, ("F) Steam Turbine POwer Output(MW) Capacity Factor(hrsJorrat Fuilioad) Overall PM Reduction Efficiency, (%) Uncontrolled pM Emissions, (Iblhr) UncontroUedPM Emissions, (tonslyr) ControliEldPt:>:1 Emissions, (tonlyr) AnnuallnterestRate, (%) Depreciation $_chedule,(yrsL Capital RecoveryFactor, CRF 0.015 IbsJMMBtu Emission Rate

Q MMBtulhr IbslMMBtu IbslMMBtu T MW hr %

CRF 1,233,748 3,940 0_0525 0_0150 314 330 8,059_ 71A3%

206_8

833 238

7 20 00944

Unit Item Cost Item Suggested Factor Cost Cost
Capital Equipment Cost (1988 EPRI Study) Equipment CostTotal, (EC) Direct Capital Costs Purchased EqUipment Costs

FF and Auxiliary Equipment Instrumentation Sales Tax Freight

Purchased EqUipmentCosts, PEC Direct Installation Costs

Foundations and Supports Handling and Erection Electrical PiPing Insulation for Ductwork Painting

Direct Installation Cost, DIC Site Preparation Building
Total Direct Capital Costs, DC Indirect Capital Costs

Engineering Construction and Field Expenses Contractor Fees Start-Up Performance Test Contingencies

Total Indirect Capital Costs, IC
Total Capital Costs,TCe • DC + IC Capital Cost ($lKWJ EC (Adjusted by Cost Index Calcs)

(Factors for FFs from OAQPS Manual) EC 0_10 EC 0_03 EC 0_05 EC PEC 

### =118 EC

0_04 PEC 050 PEC 0_08 PEC 0_01 PEC 007 PEC 0_04 PEC DIC

### = 0-74PEC As Required, SP As Required, BLDG DC = 1_74 PEC + SP + BLDG

0_10 PEC 020 PEC 0_10 PEC 0_01 PEC 0_01 PEC 0_03 PEC IC

### = 0_57 PEC TCC 

### = 2_19 PEC + SP + BLDG 50 (2008 dollars) $16,500,000 $26,836,640

$26,836,640 $2,683,664 $805,099 $1,341,832 $31,667,236
$1,266,689 $15,833,618 $2,533,379 $316,672 $2,216,706 $1,266,689 $23,433,754 $0 $0 $23,433,754
$3,166,724 $6,333,447 $3,166.724 $316,672 $316,672 $950,017 $14,250,256 $69,351,246Table 6.1-3 continued PPL BART CostAnillysls Pulse Jet - Fabric Filterfor Additional Particulate Control 330**M~gawatt** Coal Fired**Stea~** Electric**U~it f»1J1~~I1:2:~(I~9il!**  

### ..**~~.1S9~()I!1C_()1!11!1I~tl()!lJI!~()~~rrtp** 

### .

# 1mit 1or Unit

..**(~Clcll}** 0.015 Ibs/MMBtu Emission Rate

DirectAnnual Costs

Utilities

Fan Power1) Compressed AirCost2) Ash Disposal Costs OJ)eratil1gL(jbor

Operator SUJ)ervisor Maintenance

Labor**MCl!~riCl!!),r~pl(jcElmenJ~Clgsl** Total DirectAnnual Costs, DAC IndirectAnnual Costs

Overhead Administrative PropertryTaxes Insurance Capital Recovery

Total IndirectAnnual Costs, lAC Total Annual Costs, TAC • DAC + lAC Cost Effectiveness (Slton pollutant removed) Fp =(1.81 x 10·4)(Q)(deltaP)(hrsfyr) 2scfm/1 ,000 acfm (each minute)

Transportation not included

10hrlshift 15"10of Operator
$037I

## tr assumed 15"10 of PEC assume<f3)

60"10 of Operating Labor and Maintenance Costs 0.02TCC 0.01 TCC 0.01 TCC CRFoTCC (7 inw.c assumed) $0.2511,000 scf $40lton
$22.86/hr $1,007.825 $60.311 $23,812
$30,222

$4,533
$49,794 $2,590,697 $3,767,193
$1,605,147 $1,387,025

$693,512 $693,512 $6,301,724 $10,680.921 $14,448.114 $24,270

Cost data references Control Technologies for Hazardous Air Pollutants, Government Institutes, Inc, Office of Research and DevelopmentCenterfor Environmental Research Information, June 1992. OAQPS Cost Manual, Sixth E:dition, EPA-452-02-001, January 2002 Cost data assumptions: Costs adju?ted by cost indices: for 2008 CI=121.313,and 1988 CI=74.587 1. FF'shave**high~** variable pressure drops (7.0"w.c. assumed)

- Electricity cost at $0.08/kW-ir is typical 2. Compressed air cost is calculated as suggested bythe OAQPS Control Cost Manual; 2 scfm of compresseclairis assumed to be requiredJor each 1,000 acfm per minute of operation the cost of such compressed air is estimated tobe $025 per 1,000 scfm 3. Bag replacementc0st**canvarylNide~from** 15%to 1QO% ofthe PEC(15% assumed);

the bag life is assumed to be 2years and acapital rec(Jl{eryfactorof 0.5454 has been appliedto the annual bag replacement cost 

### NG ratio of assumed. $O.ytt2 labor cost assumed for bag replacementTable 6.1-4 PPLJSART Cost**~nalysls** Pulse Jet·Fabric Filterfor Addmonal Particulate Control 33() f!'Iegilwatt**~oala=lr.,dSt.,il",_a;I~ctI"lt; lJl1~** **PUlverlze~** Coal·

### Dry**Bo~om C:~I1l~l1stl~l1ln~olstl"lp**  Unit 1or Unit 2(each)

Stack Exhaust Volumetric Flowrate, (actm) Maximum Gross Heat Input Uncontrolled**Fi~erable** PM Emissions Controlled Filterable PM Emissions ExhaustTemperature, (OF) Steam Turbine POwer OutputlMW) C<:lpacity Factor (hrsfy'rattuUload) Overall pM Reduction Efficiency, (%) UncontrolledPfv1 Em.issions, (Iblhr) Uncontrolled Pfv1 Emissions, (t()IlW) Controlled PMElllissions, (ton,yr) Annual Interest Rate, (%) Depreciation SchedulE!,**(~?)** _ Capital RecoveryF<:lC!or, CRF 0.010 Ib/MMBtu Emission Rate

Q MMBtulhr IbsIMMBtu IbsIMMBtu T MW hr %

CRF 1,233,748 3,940 0.0525 0.0100

314 330 8,059 80.95%

206.8

833 159

7 20 0.0944

Unit Item**Cost~em** Suggested Factor Cost Cost
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

TotalIndirect Capital Costs. IC Total Capital Costs, TCC • DC + IC Capital Cost ($/KW) EC (Adjusted by Cost Index Cales)

(Factors for FFs from OAQPS Manual) EC 0.10 EC 0.03 EC 0.05 EC PEC= U8EC

0.04 PEC 0.50PEC 0.08 PEC 0.01 PEC 0.07 PEC O.04PEC DIC 

### = 0.74 PEC As Required, SP As Required, BLDG DC = 1.74 PEC + SP + BLDG

010 PEC 0.20PEC 0.10PEC 0.01 PEC 0.01 PEC 0.03PEC IC =0.57 PEC TCC = 2.19 PEC + SP + BLDG 50 (2008 dollars) $16,500,000 $26,836:640

$26,836,640 $2,683,664 $805,099 $1,341,832 $31,667,236
$1,266,689 $15,833,618 $2,533,379 $316,672 $2,216,706 $1,266,689 $23,433,754 $0 $0 $23,433,754
$3,166,724 $6,333,447 $3,166,724 $316,672 $316,672 $950,017 $14,250,256 $69,351,246Table 6.1-4 condnued PPL BAIlT Cost Analysis Pulse Jet·Fabric Filterfor AddltlonalPardculate Control 330**M~g~watt C()ClIFIJ~<I~eam**  Electric Unit**I'lJlv~rl:z:~(j~oal ·[)ry~()tt()rrI** **c;_()rrI~lJ~~()~_ln~~()I~~lp~nlt** 1or Unit 2(eacm 0.010 Ib/MMBtu Emission Rate

DirectAnnual Costs

Utilities

Fan Powef1 l Compressed Air Cosf2l Ash Disposal Costs Operating_L.abor

Operator Supel\lisor Maintenance

Labor**M~!e!i~l§ (rElplacElrrleI1L~~g?)**  Total Direct Annual Costs, DAC IndirectAnnual Costs

Overhead Administrative PropertryTaxes Insurance Capital Recovery

Total IndirectAnnual Costs, lAC Total Annual Costs, TAC • DAC + lAC Cost Effectiveness (Slton pollutant removed) Fp =(1.81 x 1O-4)(Q)(delta Pj(hrsi{r) 2sCfm/l,OOO acfm (each minute)

Transportation not included

10hrlshift 15% of Operator
$0.37Itrassumed 15% of PEC assumecf3l

-**"~** "."._

.. -,'-,-­**-~** -



### _ ... ,',

_..• .. " .

60%of**OJ)er~tingLab()r** and Maintenance Costs 0.02TCC 001 TCC 0.01 TCC CRF'TCC (7 in w:c, assumed) $0.25/1,000 scf $40lton
$2286/hr $1,007,825 $60,311 $26,987
$30,222

$4,533
$49,794 $2

__590,697 $3,770,368
$1,605,147 $1,387,025

$693,512**$69~,512** $6,301,724 $10,680,921 $14,451,289 $21,420

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: Costsadjusted by costindicEls for2008 CI=121313, and 1988 CI=74.587 1. FF's have**high~** variable pressure drops (70"w.c. assumed)

- Electricity cost at $0.08IkV\iHris typical 2 Compressed air cost is calculated assuggested bythe OAQPS Control Cost Manual; 2scfm of <:ompress§ld air isassumEld to be required for each 1,000 acfm per minute of operation the cost of such compressed air is estimatedtobe $0.25 per 1,000 scfm 3. Bagreplacement costcan**varywide~from** 15% to 100% ofthepEC (15% assumed):

the bag life is assumed tobe 2years and acapital recoveryfactor of 0.5454 has been applied to the annual bag replacementcost A/C**r~io** of 5 assumed. $0.31fi2labor c()sta?sumed for bagreplacement

# Subjectto ConfidentialityClaim 

# Confidential Attachments 1

# and2 Attaclnnentsto: AddenduDlto PPLMontana's ColstripBARTReport

Prepared for



# PPL Montana, LLC Billings, Montana

Preparedby 

# C)TRC
21 Griffin Road North Windsor, Connecticut 06095

Telephone 860-298-9692 Facsimile 860-298-6399

TRC Project No. 160158



### June 2008

### 3



## ,......­

n 

### :::r CD ::::J 

# ­ ..Jo.

## CONFIDENTIAL BUSINESS INFORMATION

ConfidentialAttachment 1

SOFA Cost Effectiveness Tables 

# Subjectto ConfidentialityClaim

Attachmentto

Addendum to PPL Montana's Colstrip BART Report

June 12, 2008
Prepared by 

### TRC Environmental Corporation and PPL Montana

## CONFIDENTIAL BUSINESS INFORMATION

Cost Effectiveness Tables for the evaluation of Separated Overfire Air (SOFA) for Colstrip Units 1&2 are presented in Tables 5.1-1 and 5.1-2. This support information for PPL Montana's Colstrip Bart submittal is provided as Confidential Business Information (CBI) and entitled to protection against release to the public pursuant to 40 C.F.R. Section 2.203(b). This document should not be distributed beyond its intended recipients (U.S. EPA Region 8 and any other regulatory agency involved in the Colstrip BART determination) without providing notice to PPL and an opportunity to object. Upon request, PPL Montana could provide as CBI the Alstom, Inc. proposal from which this informationis based.

## ~UbJect to 

# LOJllUlentIaUty 

# Claim.

# Subjectto 

# ContidentialHvCl!J.JI( CONFIDENTIAL BUSINESS INFORMATION " 0./'''1,).,

Table 5.1-1 PPL BART CostAnalysis LNCFS Level III NOx Burner Controlswith SOFA

330..,egaYiatt**Coalp:lr~~ ~~iII11l!!ectrlc**  Unl! Tangentially Fired Sub-bltumlnous Coal Combustion In Colstrip Units 1&2 (Each) 30-dayAverage Emission Rates

Stack ExhaustVolumetric Flo

......rate, (acfm) Maximum Gross Heatlnput Annual**Capaci~** Factor (hrsiyT atfull load) UncontrolledNOX EmIssions Gontrolled**~OXE:missions** E:xhaustTernperature, ("F) $teEirn Turbinepo

......er Output (TMVV) Hours()f**Qp~erati** ()n

.. OvElra11 NOXBeducti()nE:fficiency,('ro) lJncontroIIEldNOXE:l1li!>si()n.!>,(Ib.lhr) Ul1controlle(jNOXE:mISslons, (tonsiyT) Gontrolleej NQXE:l1lissions, (torVyr] Annual Interest Rate, (%) DepreciEitiOI1**~che~dule** (yT!») Capital RecoveryFactor, CRF

Cost Item
Capital EqulpmElnt Cost(2008] Equipment CostTotal, (Ee)

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

Capital Recovery

Total IndirectAnnual Costs, lAC
Total Annual Costs,TAC· DAC + lAC Q MMBtulhr % IbslMMBtu IbslMMBtu T MVV hr %

CRF 3D-day average 3D-day average 1,233,748 3,940 92 0.350

0.19 314 330 8,059 45.71 1378.8

5556 3016 7 20 0.0944

Suggested Factor Unit Cost Item Cost

Cost From March 2008 Alstom Quote Installation Cost SOFAActuators and Controls Air Flo

...... Mods for LNCFS Level III

Coal Flo

...... Measurement Mods $1,968,245 $2,000,000

$200,000 $365,600 $175,000



### -­ $4,708,845 0.25 milllkW-hr $664,884

CRF*TCC

--­ $444,482 $444,482 $1,109,366 CostEffectiveness ($lton pollutant removed) $437

Cost data references: 1] Alstom Proposal Number43033682-01

## CONFIDENTIAL BUSINESS INFORMATION 

# Subjectto (oniideuthmiY**\.J~C]~"**
Table 5.1·2 PPL BART CostArlalysls LNCFS Level III NOx Burner c:ontrolswhh SOFA

330 MegawattCo21IFlred**~4'clll\Elec:trlc** UIlIt Tangentially Fired SUb-bltumlnous Coal Combustion In Colstrip Units 1&2 (Each) Maximum 24-hr Average Emission Rates

Stack Exhaust Volumetric Flowrate, (acfm) Maximum Gross Heat Input Annual Capacity Factor (hrslyr atfull load) Uncontrolled NOx Emissions Controlled NOx Emissions ExhaustTemperature,("F) $tearnTUrbine power Output(TMW)**I-iour~** of**()per<l~()n** OverallNOx RedlJctionEJficiency,**~%)** Uncontrolled N()x r=mi!;sions, (lb.1lr) Uncontrolled N()x E:rnlssions, (tonsNi"l C0i1trolle(j NOxErnissiOns, (tontyr) Annual Interest Rate, (%) Depreci€ltion Schedule (yrs) Capital Recovery Factor, CRF 

### a MMBtulhr % IbslMMBtu IbslMMBtu T MN hr %

CRF 24-hr average 24-hr average 1,233,748 3,940 92 0490 0266

314 330 8,059 45.71 1876.5

7562 4105 7 20 0.0944

Cost Item Suggested Factor Unit Cost Item Cost
Capital EqUipment Cost (2008) EqUipment CostTotal, (EC) Cost From March 2008 Alstom Quote Installation Cost SOFAActuators and Controls Air Flow Mods for LNCFS Level "'

Coal Flow Measurement Mods $1,968,245 $2,000,000

$200,000 $365,600 $175.000 Total CapitalCosts,TCC·DC +IC



## - $4,708.845 Total DirectAnnualCosts,DAC 

### o .25 mllllkW-hr $664,884 IndirectAnnual Costs

Capital Recovery CRF'TCC

--­ $444,482

TotalIndirectAnnual Costs.lAC $444,482 Total Annual Coats,TAC • DAC +lAC $1,109,366 Costerectlvenen ($lton pollutantremoved) $321

Cost data references: 1) A/stom Proposal Number43033682-01

# ­ (') 

### 3

N ::::T CD ::::J

## CONFIDENTIAL BUSINESS INFORMATION 

# Subjectto Coniidentmul,J'**\A~1U~,** ConfidentialAttachment2
Supplemental Fuel Switching Discussion

Attachment to

Addendum to PPL Montana's Colstrip BART Report

June 12,2008
Prepared by 

### TRC EnvironmentalCorporation and PPL Montana

# .**~\y** 

# Claim

• t 

## "'0

# ConfldentlaI t:ONFIDENTIAL BUSINESS INFORMATION 

# Sublec\,"
This support information for PPL Montana's Colstrip Bart submittal is provided as Confidential Business Information (CBI) and entitled to protection against release to the public pursuant to 40 C.F.R. Section 2.203(b). This document should not be distributed beyond its intended recipients (U.S. EPA Region 8 and any other regulatory agency involved in the Colstrip BART determination) without providing PPL notice and an opportunity to object. Upon request, PPL Montana could provide as CBI the Coal Unloading Facility Siting study referenced here.

Supplementation information to Section 4.2.2 Fuel Switching is provided below.

PPL Montana has identified four major cost items ifColstrip Units 1&2 were to switch from burning present, mine mouth coal to burning coal that is transported to the facility by rail.

I. Construction of a Coal Unloading and Storage Facility and Upgrades to the Existing Rail Lines. There is presently no coal unloading and storage infrastructure at the plant. A coal unloading facility siting study was conducted for PPL Montana by Stanley Consultants, Inc. The purpose ofthe study was to investigate the feasibility ofupgrading rail access and constructing a rail car unloading facility and associated coal storage, blending and conveying capability. The study was completed in 2007. The construction costs for Units 1&2 alone were projected to be approximately $39,700,000. For Units 3&4 (not BART affected) the construction costs were projected to be approximately $22,700,000. Annual operating costs were projected at approximately $4,000,000 for Units 1&2 and $2,400,000 for Units 3&4. This study, "Colstrip SES Coal Unloading Facility Siting Study," Stanley Consultants, Inc., September 2007, can be provided to EPA Region 8 as CB upon request.

2. Rail Transportation Costs. Rail transportation costs are estimated here based
on coal transportation costs to PPL's Corette powerplant from the Wyoming PRB region.

# '." c\a\\\\

_ .

# "O~\~~\\\\~\~ CONFIDENTIAL BUSINESS INFORMATION 

# '.**;~\,\** \.\)\;.
.,

# J\\~~ Corette bums coal wIth a sulfur content close to 0.3%. The rall costs are approxImately $10 per ton. Based on this, PPL estimates that the transportation cost to Colstrip, a further distance, would be $15/ton. Colstrip Units 1&2 bum approximately 3 million tons per year of coal. Therefore, the annual transportation cost would be $30 million. This cost assumes that transportation would be on PPL rail cars, which would need to be purchased. The rail car cost would be approximately be $100,000 per car and it is estimated that 270 cars (two train sets) would be required at a cost of$27,000,000.

3. Boiler Upgrades. Alstom, Inc. identified boiler modifications that may be required ifa different coal than the present Rosebud coal is burned in Units 1&2. This is based on a preliminary engineering review by Alstom, not a detailed engineering study, which is what would be needed to evaluate a specific coal source and associated impacts to existing boiler equipment. The concern identified is that the alternative coal may have sodium levels in the 1.5% to 2.5% range or higher which could cause fouling or slagging with the present boilers. As a result, unless there were boiler upgrades to address fouling, the units would suffer reduced capacity. Alstom's estimated boiler modification costs Per Unit are

• Additional wallblowers, retracts, H20 cannons: $8.75 million. • Resurfacing LT/HT superheaters: $21 million. • Redesigned/resurfaced economizer/headers: $10.5 million. • Seven week outage lost time lost for outage: $18.1 million. • Total perunit cost: $58.35 million.

4. Additional Scrubber Vessel. PPL has speculated that a different coal would have a lower alkalinity than the presently burned Rosebud coal. Ifthis were the case, lime injection would be required to maintain the S02 removal rate presently attained with the venturi scrubbers. An additional scrubber vessel could be required to maintain the present Units 1&2 capacity levels because ofincreased vessel down time to remove scale that would result from the lime injection. The cost for lime injection would likely be similar to that identified in the lime addition system as part ofthe S02 evaluation. The capital cost for a new scrubber vessel is estimated to be $50 million. Additional engineering would be needed to better define these costs.

## CONFIDENTIAL BUSINESS INFORMATION 

# Subjectto COnfidentiality

# Claim Only costs for items I, 2 and 3 above (infrastructure costs, rail costs and boiler upgrade costs) were included in the cost analyses that were conducted and are presented in the attached tables. Item 4 above (additional scrubber vessel) is considered too speculative at this time and is presented as an uncertain cost. Additional engineering studies and test bums would be required to ascertain its need and cost.

Based on the infrastructure and rail costs, the cost to switch from burning the present coal with a sulfur content of0.7% to coal with a sulfur content of0.3% would be 

### $10,238/ton for S02 emissions corresponding to a 30-day average emission rate and 

### $5,943/ton for emissions corresponding to a maximum 24-hour emission rate. This

assumes the same level ofsulfur removal as is presently attained with the existing venturi scrubbers. Lime injection beyond this level for further S02 reduction was not evaluated because ofthe detrimental effects it would have on scaling ofthe scrubber vessels.

## CONFIDENTIAL BUSINESS INFORMATION 

# Subjectto ConfldentiaJity Claim

Table 4.2-1 PPL BART CostAnalysis Coal Switching to Lower Sulfur PRB Coal 330 Megawatt Coal Fired Steam Electric Unit Tangentially Fired Sub-bituminous Coal Combustion at Colstrip Unit 1 or Unit 2 30-day Average Emission Rates
Stack Exhaust Volumetric Flowrate, (acfm) Maximum Gross Heat Input Design Percent Load Uncontrolled S02 Emissions (with 0.70% S coal) Controlled S02 Emissions (with 0.30% S coal) ExhaustTemperature, (OF) Steam Turbine Power Output (TMW) Hours of Operation 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

Cost Item

Cost of Modifications(1) Equipment Cost Total, (EC)

Total Capital Costs, TCC
Direct Annual Costs, DCC

Coal Handling Annual Operating Costs Operations and Maintenance Costs
Total O&M Cost
Indirect Annual Costs

Capital Recovery

Total Indirect Annual Costs, lAC
Total Annual Costs, TAC = DAC + lAC
Cost Effectiveness ($/ton pollutant Removed)

Cost data references: Q MMBtu/hr % Ibs/MMBtu Ibs/MMBtu T MW hr

$/kW-hr

CRF

Suggested Factor

Rail system and coal unloading

storage and infrastructure Additional Wallblowers, Retracts Water Canons Resurfacing LT/HT Superheaters Redesigned/Resurfaced Economizers Cost of a 7 Week Outage
Total for coal unloading and handling

and Boiler Modifications/Outage

Fuel Delivery Charges

CRF'TCC

1) Confidential information from Stanley Consultants, Inc. Avg of Units1&2 30-dayavg 30-dayavg 1,233,748 3,940 92 0.400 0.234

314 330 8,059 1575.8

6350 3721 0.08 7 15 0.1098

Unit Cost Item Cost
$19,850,000

$4,375,000 $10,500,000

$5,250,000 $9,050,000



### -­ $49,025,000

$15/ton $2,000,000 $19,586,998 $21,586,998



### -­ $5,382,681 $5,382,681 $26,969,680 $10,258

## CONFIDENTIAL BUSINESS INFORMATION 

# Subjectto

# LonHdentJaHty Claim
Table 4.2-2 PPL BART Cost Analysis Coal Switching to Lower Sulfur PRB Coal 330 Megawatt Coal Fired Steam Electric Unit Tangentially Fired Sub-bituminous Coal Combustion at Colstrip Unit 1 or Unit2 Maximum 24-hr Average Emission Rates
Stack Exhaust Volumetric Flowrate, (acfm) Q 1,233,748 Maximum Gross Heat Input MMBtu/hr Avg of Units1&2 3,940 Design Percent Load % 92 Uncontrolled S02 Emissions (with 0.70% S coal) Ibs/MMBtu 24-hr avg 0.760 Controlled S02 Emissions (with 0.30% S coal) Ibs/MMBtu 24-hr avg 0.445 ExhaustTemperature, (OF) T 314 Steam Turbine Power Output (TMW) MW 330 Hours of Operation hr 8,059 Uncontrolled S02 Emissions, (Ib/hr) 2720.0 Uncontrolled S02 Emissions, (tons/yr) 10961 Controlled S02 Emissions, (ton/yr) 6423 Value of Power Generated $/kW-hr 0.08 Annual Interest Rate, (%) 7 Depreciation Schedule (yrs) 15 Capital Recovery Factor, CRF CRF 0.1098

Unit Item Cost Item Suggested Factor Cost Cost

Cost of Modifications(1) Equipment Cost Total, (EC)

Total Capital Costs, TCC
DirectAnnual Costs, DCC

Coal Handling Annual Operating Costs Operations and Maintenance Costs Total O&M Cost IndirectAnnual Costs

Capital Recovery

Total IndirectAnnual Costs, lAC
Total Annual Costs, TAC = DAC + lAC Cost Effectiveness ($/ton pollutant Removed) Rail system and coal unloading storage and infrastructure Additional Wallblowers, Retracts Water Canons Resurfacing LT/HT Superheaters Redesigned/Resurfaced Economizers Cost of a 7 Week Outage
Total for coal unloading and handling

and Boiler Modifications/Outage

Fuel Delivery Charges

CRF*TCC $19,850,000 $4,375,000 $10,500,000

$5,250,000 $9,050,000 $49,025,000

$2,000,000 $15/ton $19,586,998 $21,586,998

$5,382,681 $5,382,681 $26,969,680 $5,943

Cost data references: 1) Confidential information from Stanley Consultants, Inc.