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 

0ubject to C· f" Laurel Dygowski on Identiality Claim Air Quality Planning and Management Unit 

US EPA - Region 8 

1595 Wynkoop Street 

Denver, CO 80202-1129 

Re: Best Available Retrofit Technology (BART), Colstrip Generating Stations 

Dear Ms. Dygowski: 

Enclosed please find a revised paper version of PPL Montana's submittal of a supplement to our 

August, 2007 BART Analysis for Units 1&2 of the Colstrip Steam Electric Generating Station. I 

Per my recent voice mail, the hardcopy report we previously sent you contained errors. Please 

discard the previous hard copy version of this report. The electronic version we sent you on June 

12,2008, is correct and matches this corrected paper version. 

Please contact me at 406-237-6932 or Reid 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 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 and the Alstom, Inc. proposal referenced 

here. 
Addendum to
 

PPL Montana's
 

Colstrip BART
 

Report
 

1

8.,h.;,;)111 \"0 ConHdtntiality Claim

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 of a 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 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 of the 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 of those 

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, rather than 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 of control 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 of energy 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 of this 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 of 91 %, increased scaling of the 

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 

BART requirements. 

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 of a 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 of control to the next. The visibility impacts of the 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 of further controls is not warranted. 

ES-3
 
Table ES-l: Control Costs Summary - Typical30-Day Average 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/MW out 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 of the 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 scrubber will 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 of wet 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 076 COFA(2) 0.0525 IblMMBtu IblMMBtu 0.49	 IblMMBtu

B01O) from I 

2006 NSPS 0.015 IblMMBtu 1.4 Ibs S~IM'N out 1.0 IbIMW out 

New Sources ro.15 IblMM Btu in ro.ll IblMM Btu in 

Cost Effeciveness Calcs Cost Effeciveness Calcs

Option 

Control 

Options 

Present 

Added FF 

Added FF 

Added ESP 

Added ESP	 

Option Evaluated CElli) CElli) Evaluated Incremental Option Evaluated Incremental

CE(7) 

IblMMBtu 

Rate Rate (from Present) C~ Rate (fromPr_)

$lion IblMMBtu $lion $Ilon IblMMBtu $lion $lion

0.0525 Present 076 Present 0.49 

0.015 $24,270 Fuel Switch 0.445 $5,943 SOFA 0.266 $321

0.010 $21,420 WS-FGO<4) 0.38 $121 SNCR 0.21 $852 $2,976

0.015 $29,809 WS-FGO<~) 0.285 5282 $923 scRl1') 0.154 $1,565 $5,132

0.010 $26 307 SC~ 0.084 $1 412 $2657

Notes	 1) Colstnp Average FI~erable EmiSSions of 0.0525 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 of the 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 scrubber will 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 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 of wet 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 

ESTIMATED VISIBILITY AND VISIBILITY 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_115 f0_956 0_164 

nfa nfa 

1____ ----" f "-"-- -"-_. " L __ ,_ .. ----.' - -- --. J.___ ., '­ _ L __ ..' ... __ •. __ . . __ __ " . - ,,'-.. - . _ ..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'iorconirolaliernalivesT-:-------;'-'-----­'--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-nlSalpreseni emssiQ-ns-ex-cepiihe"one beTngcontroiil.ld'-- -, T (4)S02ems-sions reduced -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 Oass lareas than the rrBximum prediction among all Class I areas. 

-' 

-­

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 of Coal Cleaning and Fuel Switching Options 4-3
 

4.2.1 Coal Cleaning 4-3
 

4.2.2 Fuel Switching 4-4
 

4.3 Evaluation of Venturi 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 SCR NOx 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 of Particulate Control to 0.0 I 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 of Visibility Estimates
 

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

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 

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 in August 8, 2007. This Addendum to that assessment report(l) responds to those 

comments and provides additional analyses as needed. EPA's letter is included as Attachment 1. 

The Colstrip power plant, 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. 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 of the 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 of those 

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, rather than 11 

years for both. 

•	 The maximum NOx control level with SCR was evaluated at 0.06 Ib/MMBtu. The 

NSPS level of 0.1 1 Ib/MMBtu was also evaluated. (Note that PPL believes that the 

0.06 Ib/MMBtu control level may not even be appropriate for new sources, and that 

1-1 
level of control 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 maximum particulate control level was evaluated at 0.0 1aIb/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 SNCR was revised from 0.16 Ib/MMBtu to 0.15 Ib/MMBtu 

(typical) 

•	 Fuel switching to lower sulfur coal was evaluated. 

•	 There is an expanded discussion of 

- Fuel switching and coal cleaning options for S02 control 

Transferal of energy 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 of this addendum. 

Table 1-1 summarizes EPA's comments and references the sections of this 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 of the Colstrip BART analyses. 

1-2
 
Table 1-1: EPA January 28, 2008 Comments
 

Category
 EPA Comment Section(s)

l. Evaluate the Most Stringent Evaluate the Maximum Control S02 4.1

General Level that the Technology Level with Lime injection 

Comments is Capable of Achieving Evaluate the Maximum NOx Control 5.2 

Level with SNCR 

Evaluate the Maximum NOx Control 5.3 

Level with SCR 

2. Provide Proper/Additional Cost Documentation 7.0

3. Re-model Control measures Based on 24-Hour Averages 8.0 

4. Use a 15 Year Remaining Life for S02 Control Costs 4.1, 4.2, 7.0 

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 of Venturi Scrubber Upgrades for S02 Control 4.3 

8. Use a 20 Year Remaining Life for NOx Control Costs 5.1,5.2,5.3,7.0

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 Additional NOx 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 0.0 I Ib/MMBtu
 6.2 

1-3
 
2.0 COLSTRIP UNITS 1&2 

2.1 Operation 

The Colstrip power plant 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 of tangential-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 of 0.30 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 of the wet scrubber includes a venturi/plumb bob section with sprays to 

remove particulate and S02, followed by a level of absorption 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 of the fly ash collected to remove the S02. 

The scrubbers are designed to have at least a 98% particulate control efficiency and 

operation of the equipment has shown particulate control efficiencies approaching 99.5%. They 

achieve a 75% to 80% S02 removal (depending on the alkalinity of the ash). The scrubbers are 

designed to treat 100% of the 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 of a 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). 

Stack tests 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 of 0.68 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-Hour Emissions 

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 of total 55.3% 60.4% 

lb/hr 187.1 226.0 

lb/MMBtu 0.047 0.058 

Condensable(2) percentage of total 44,7% 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) lb/hr 30,26 29.62 

lb/MMBtu 0.0076 0.0076 

Inorganic(3) lblhr 121.05 118.47 

lb/MMBtu 0.0304 0,0304

(1) Based on stack test data. 

(2) Based on AP-42. 

(3) Based on NPS guidance, 

(4) The average of the 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 of these averaging 

periods were also used for each of the 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 200 I, 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 of the modeled estimates presented in Table 3-1. The 

modeled and interpolated/extrapolated values presented here are based on maximum 24-hour 

emissions per recommendations in the BART guidelines. 

The change in visibility improvement (in deciviews) per change in emission rate (in 

Ib/MMBtu) between each of the 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: Parameters for Interpolation and Extrapolation of Visibility 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 

Base Case 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 

of the 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 of a 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 of the selected interval (negative) 

b the visibility level at the upper end of the 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 emission rate. 

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 on the 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 of a lime injection system for Units 1 and 2. While it is not 

clear from the BART guidelines (July 2005 pg 39171) that installation of a 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 of the 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 of a 

spare scrubber vessel as a potentially more palatable option to reduce S02 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 BART requirements. 

Cost and visibility analyses were conducted for the maximum controlled emissions level 

of 0.15 lb/MMBtu (91 % control) for typical/average emissions and a rate of 0.285 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 of lime 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. 

Cost Evaluation 

Two scrubber modifications were evaluated for improvement of the performance of the 

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 of the 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 of the 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 of the maximum 24-hour average emission rate, the cost effectiveness is 

$121/ton. Both of these 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 of capital costs over 

15 years, and the assumption of money availability at 7% results in the cost effectiveness of 

$486/ton and $282 per ton for the 30-day and 24-hour averaging times respectively. 

Visibility Evaluation 

4-2 
The maximum improvement of 98th percentile visibility estimates at any of the 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 of Coal 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 of the 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 of lowering the moisture content of the 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 of thumb estimates that about 35% to 55% of the pyritic 

sulfur can be removed when coal is 'washed'. The other forms of sulfur 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 cleaning process. 

For these 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 of approximately 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 if necessary 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 of the detrimental effects it would have on scaling 

of the scrubber vessels. 

The costs associated with fuel switching would include: 

1.	 Construction of a 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 of a 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 of the cost analysis conducted is provided in Confidential Attachment 2. 

The overall cost is estimated at $1 0,258/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 of their 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 of the 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 of Venturi 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 of scrubber system reliability or reduction of downtime 

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 

of 91 % (Subsection 4.1). 

Other common scrubber upgrades and their status are reviewed below. 

•	 Elimination of Bypass Reheat. The Colstrip Units do not have the capability of bypass 

reheat, so essentially this upgrade is already included in the scrubber design. 

•	 Installation of Liquid Distribution Rings. This upgrade is considered in the evaluation 

to achieve 91 % S02 removal efficiency. 

•	 Installation of Perforated Trays. This upgrade is already part of the existing scrubber 

design in form of the wash tray. 

•	 Use of Organic Acid Additives. PPL's review of this upgrade indicates it is effective 

for limestone scrubbers to enhance the effectiveness of the limestone. But, the current 

Colstrip scrubbers do not use limestone, they rely on the alkalinity of the fly ash to 

achieve current S02 removal rates of 75% 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 of quick 

lime scrubbers because of the reactivity of lime. The reactivity of lime 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 of upgrades 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 of 0.19 Ib/MMBtu. This rate is the "average value obtained over the 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 on transferring 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 B coal. 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 of the 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 of the Class I 

areas evaluated for a NOx emissions reduction from the base case emission rate to the SOFA 

emission rate 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 of SNCR on Colstrip 1&2 would need further review to evaluate the effects of their 

small furnaces and the type of PRB 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 of a boiler where NOx reacts with the reagent to chemically reduce NO (the major oxide of 

nitrogen in NOx) to nitrogen and water. Either urea or an ammonia-water solution are the typical 

sources of reducing 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 of the 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 of Section 4.2: 

"There is little difference between the cost of SNCR retrofit of an existing boiler 

and SNCR installation on a new boiler. Therefore, the cost estimating procedure 

is suitable for retrofit or new boiler applications on all types ofcoal-fired electric 

utility and large industrial boilers. " 

However, EPA goes on to state on page 1-21 of the same section: 

"SNCR system design is a proprietary technology. Extensive details ofthe 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 ofthese complexities, SNCR system design 

is generally undertaken by providing all of the plant and boiler specific data to 

the SNCR system supplier, who specifies the required NSR and other design 

parameters based on prior experience and computational fluid 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% over that 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. 

Cost Evaluation 

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 of application of the CCM cost analysis techniques to 

Colstrip Units I&2. Regardless of the basic cost of equipment, 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 of incremental 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-hr emission rate basis respectively. 

Visibility Evaluation 

The maximum improvement of 98th percentile visibility estimates at any of the 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 of 0.06 

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 of control 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 of 0.11 Ib/MMBtu 

attained with SCR was also evaluated as the New Source Performance (NSPS) level for new 

boilers of the size of Units 1&2. A site-specific engineering study of Colstrip 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 of the honeycomb and reacts to form N2 and H20 

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 SNCR process which relies on the higher 

temperature portions of the boiler and 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 of three possible locations for the 

SCR module as well as detailed cost estimation procedures for estimation of the SCR system and 

ancillary equipment. Installation of the SCR module may be upstream of the particulate control 

device in what is termed the "high dust SCR location". Such installations typically require lower 

quantities of catalysts, 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 of catalyst. A third option, the "tail-end SCR" is typical 

of many 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 a proprietary technology. Extensive details of the 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 highly site-specific. In light ofthese complexities, SCR 

system design is generally undertaken by providing all of the 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 

computationalfluid dynamics and chemical kinetic modeling. 

This section presents a step-by-step approach to estimate design parameters 

based on a procedure 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 main parameters: the boiler size or heat input, 

the required level ofNO, reduction, and the catalyst volume. " 

Cost Evaluation 

The calculations applicable for estimating the cost of an SCR system include the 

estimation of design parameters as described on pages 2-30 to 2-40 of the 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 of the base NOx level of 0.35 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 of cost analyses were performed for each averaging time. The first set of results 

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 of 0.1 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 of 98th 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 Other NOx 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 not justified are briefly discussed below. 

Advanced Separated Overjire Air (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 Overfire Air (ROFA) 

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 of the furnace. ROFA uses a 

rotating overfire air process whereas Alstom's system uses both horizontal (yaw) and vertical 

nozzle tip controls. PPL's review of data 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 of ROFA was about 5 times the cost of Alstom'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 of multiple control technology alternatives which result in essentially equivalent 

5-7
 
emissions. It is not our intent to encourage evaluation ofunnecessarily large numbers ofcontrol 

alternatives for every emissions unit...For example, iftwo or more control techniques result in 

control levels that are essentially identical, considering the uncertainties of emissions factors 

and other parameters pertinent to estimating performance, you may evaluate only the less costly 

ofthese options. 

In PPL's judgment, pursuant to the foregoing guidance, a further evaluation of ROFA is 

not necessary. 

Rich Reagent Injection (RRI) 

PPL took the same approach regarding RRI. PPL's review of RRI 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 similar results 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 of load 

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 of the 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 of Particulate 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 of new 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 of 0.015 lb/MMBtu (the filterable NSPS level) that had been evaluated 

in the original BART submittal was re-evaluated here for consistency. 

Cost Evaluation 

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 of utility sized 

6-1
 
units, the capital cost of the ESP was estimated at $60/kW and that of a 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 of a 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 of either an ESP or a FF is a function of the basic size of the electrical generating unit. 

The only cost difference between the assumption of a 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 of the 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 of additional 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 of 98th 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 of 0.015 

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 COST ANALYSES 

Table 7-1 summarizes the cost effectiveness results in terms if dollars per ton of pollutant 

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 of the 

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: Control Costs 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 

on cost of lime and 

equipment 

24-hour 0.38 $121 

Lime Injection 

(91 % Control) 30-day 0.15 $486 

Plant estimate based 

on cost of lime and 

equipment and cost 

24-hour 0.285 $282 of increased outages 

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 of the 

level of emissions reduction attained. An exception is that the S02 coal switching alterative was 

not included in the incremental calculations for either of the 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 Calpuff modeling 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., 

8-2
 
Table 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 and PM cases occur at the 

Theodore Roosevelt NP Class I area. 

(3) Maximum 98th percentile base case levels are presented per pollutant 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 of the 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 of the control levels evaluated. Table 9-2 

presents the same cost data for actual maximum 24-hour emission rates. Table 9-3 presents a 

summary of the 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 of the emission rates for 

Units 1&2. 

Table 9-1: Control Costs Summary - Typical30-Day Average 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 of 0.0525 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 of the 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 scrubber will 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 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 of wet 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 

9-1
 
Table 9-2: Control Costs Summary - Maximum 24-Hour Average Emission Rates 

TABLE 9-2 - CURRENT i NSPS f CONTROL OPTIONS COST SUMMARY
 

FOR THE PPL MONTANA,llC, AVERAGE OF COLSTRIP UNITS 1&2 - 2UlR AVERAGE EMISSIONS BASIS
 

Particulate Matter Sulfur Dioxide Nitroaen Oxides

Rate Rate Units Control Rate I	 Units I	 Units

Current(1) 

0.49 COFA(2) Emission rate 0.0525 IblMMBtu 0.76 IblMMBtu IblMMBtu

BD"(O) from I 

2006 NSPS 0.015 IblMMBtu 1.4 Ibs SO:!fMW out 1.0 IblMW out

New Sources !D.15 IblMM Btu in !D.ll IblMM Btu in1

Cost Effeciveness Cales Cost Effeciveness Cales

Option 

Control 

Options 

Present 

Added FF 

Added FF 

Added ESP 

Added ESP	 

Evaluated Option Evaluated cEtlI) Incremental Option Evaluated cEtlI) Incremental

Rate Rate from Present cE<7) Rate from Present) cE<7)

IblMMBtu $!ton IblMMBtu $/lon $/lon IblMMBtu $!ton $!ton

0.0525 Present 0.76 Present 0.49

0.015 $24,270 Fuel Switch 0.445 $5,943 SOFA 0.266 $321

WS-FG(14 0.010 $21,420 ) 0.38 $121 SNCR 0.21 $852 $2,976

0.015 $29,809 W8-FG(jI) 0.285 $2B2 $923 scRl'8) 0.154 $1,565 $5,132

0.010 $26 307 scRl'8) 0.084 $1412 $2657

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 of the current wet scrubbers would be required) 

2) Low-NO x 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 scrubber will 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 of wet 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 PROVEM errs 

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 errissions duringlhe rmdeling years (200f-2003). 

(scaled by the expected control eificiency for control alternatOles) 

(2) A"verage'errisslon'atesbetWeenUrli!s 1&i~'uriitl and Unit 2 errission rates "red~ferent, they are~indicated 'asl.JnitliUnit2 rates. 

(3) PreddiQnis from allthreepoilui"nts "fpresent errissions except the one beingcontrCllled' . 

(4) S02errissions 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
 

EPA REGION 8 COMMENT LETTER
 

January 28, 2008
 
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
 

REGIONS
 

1595 Wynkoop Sireet 

DENVER, CO 80202·1129 

Phone 800-227-8917 

hllp:/Iwww.epa.gov/region08 

Ref: 8P-AR JAN 282008

James Parker 

Manager. Compliance Services 

PPL Montana· Colstrip 

P.O. Box 38 

Colstrip, MT 59323 

Re: Best Available Retrofit Technology (BART) Assessment Colstrip Generating Station 

Dear Mr. Parker: 

On February 28,2007, EPA Region 8 sent a letter to PPL Montana - Colstrip (PPL) that 

provided the results of our "subject to" modeling for Best Available Retrofit Technology (BART) 

and requested that Colstrip perform a BART analysis for Units 1&2 and submit it to EPA Region 

8. On August 8, 2007, Colstrip submitted a BART analysis to EPA that was performed by TRC. 

We would like to thank you for submitting the BART analysis and recognize the effort that has 

gone into developing this document. 

We have completed our initial review ofthe August 8, 2007 submittal and have 

determined that there is additional information and analysis needed from Colstrip in order for us 

to complete our review. Following are EPA Region 8's comments on the analysis. In addition, 

we are attaching a copy of comments on the BART analysis for Colstrip Units 1&2 submitted to 

EPA on November 5, 2007 from the National Park Service.. 

Visibility Improvement and Impacts 

Throughout your analysis. you state that thc amotmt of visibility improvement resulting 

from a reduction in emissions, based on your current BART analysis, would not be discernible 

and therefore additional controls are not justified. The visibility improvement for S02, NOx, and 

PM in your analysis are all below 1.0 deciviews. and this is used as a reason not to implement 

more stringent control measures. EPA disagrees with your assertion. EPA states in the preamble 

to its BART Guidelines that, "Even though the visibility improvement from an individual source 

may not be perceptible, it should still be considered in setting BART because the contribution to 

haze may be significant relative to other source contributions in the Class I areas." (see 70 FR 

39129, July 6,2005). Visibility modeling shows that for Class I areas in Montana, and in 

particular U.L. Bend National 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 impairment would 

ignore the Clean Air Act's (CAA) intent to have BART requirements apply to sources that 

contribute to, as well as cause, such impairment (see 70 FR 39129, 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 or more should be considered to 

"cause" visibility impairment; a source that causes less than a 1.0 deciview change may still 

contribute to visibility impairment and thus be subject to BART." (see 70 FR 39161, July 5, 

2006). The BART Guidelines further state that "As a general matter, any threshold that you use 

for detennining whether a source "contributes" to visibility impairment should not be higher than 

0.5 deciviews" (see 70 FR 39161, July 5,2006). Given that EPA has said that sources are subject 

to BART based on a contribution threshold of no greater than 0.5 deciviews, it would be 

inconsistent to automatically rule out additional controls where the improvement in visibility 

may be less than 1.0 deciview or even 0.5 deciviews. The Colstrip BART analysis shows that a 

0.5 or greater deciview reduction is achievable for both NOx and S02 as individual pollutants at 

one Class I area, U.L. Bend, and demonstrates that with reductions in NOx and S02 combined, 

there is the potential for a 1.0 deciview or more improvement. 

General Comments 

1.	 PPL's analysis is based on adding control technology to meet woot it tenns "best 

demonstrated technology." PPL assumes recently updated NSPS emission limits for 

particulates, S02, and NOx represent best demonstrated technology and does not take into 

account the highest efliciency many of these control technologies are capable of 

achieving. However, the BART Guidelines state that "It is not our intent to require 

analysis of each possible level of efficiency for a control technique as such an analysis 

would result in a large number of options. It is important, however, that in analyzing the 

technology you take into account the most stringent emission control level that the 

technology is capable of achieving. You should consider recent regulatory decisions and 

performance data (e.g.. manufacturer's data, engineering estimates and the experience of 

other sources) when identifying an emissions performance level or levels to evaluate." 

(see 70 FR 39166, July 6, 2005). Throughout your analysis, you have not evaluated 

control technologies with the most stringent emission control level, resulting in inflated 

calculated cost effectiveness values. PPL needs to redo the analysis for control 

technologies using the most stringent emission control level that the technology is 

capable of achieving. Specific examples of this include: 

PPL should re-evaluate the costs and benefits of reducing S02 based 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 of 90%, and packed tower 

absorbers have removal efficiencies as high as 99.9% ("EPA Air Pollution 

Control Cost Manual", Sixth ed., EPA-452·02·001, January 2002, Section 5.2, 

Chapter 1, pg 1-3). 

The BART analysis assumed that the addition of selective non-catalytic reduction 

(SNCR) to separated overfire air (SOFA) could reduce NOx emissions by about 

11% over SOFA. However, EPA estimates that SNCR can reduce NOx by40%­

2 
50% for a boiler this size (EPA 2002, Section 4.2, Chapter 1, pg 1-3). PPL should 

re-evaluate SNCR at these higher efficiencies. 

PPL has assumed that the addition of selective catalytic reduction (SCR) would 

reduce NOx, by 17% to 0.15 Ib/MMbtu. However, EPA estimates that SCR can 

reduce NOx, by 70% - 90%+ for a boiler this size (EPA 2002, Section 4.2, 

Chapter 2, pg 2-3). IfSCR is capable ofreducing emissions below PPL's target, 

then the amount of the reductions and consequent visibility improvements will 

increase. PPL should re-evaluate SCR at these higher efficiencies. 

2.	 The cost analysis for the control technologies included in the analysis does not contain the 

proper documentation to support the 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 estimates of capital and annual 

costs. The basis for'equipment cost estimates also should be documented, either with data 

supplied by an equipment vendor (i.e., budget estimates or bids) or by a referenced source 

(such as the OAQPS Control Cost Manual. Fifth Edition, Febrwuy 1996, EPA 453/B-96­

00 1). In order to maintain and improve consistency, cost estimates should be based on 

the OAQPS Control Cost Manual, where possible." (see 70 FR 39166, July 6,2005). PPL 

needs to provide the proper documentation to support the costs used in the analysis. 

Please note that the "OAQPS Control Cost Manual", Fifth Edition, referenced above has 

been replaced by the "EPA Air Pollution Control Cost Manual", 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. For example, the text on page 4-19 discusses reaching 

0.18 IblMMBtu ofNOx through the application ofSOFA, however table 4-9 shows that 

the application ofSOFA would achieve only 0.23/0.27 IbIMMBtu. It appears that the 

lower emission numbers in the text reflect 24-hour averaging times, while those in the 

table reflect 30-day rolling averages. Since the EPNWRAP modeling that was 

conducted to detennine that Colstrip is subject-ta-BART was based on 24-hour actual 

emission rates, we believe that modeling conducted to show the visibility improvement 

from applying controls should also be based on 24-hour averages. In addition to the 

modeling that has been provided. PPL needs to remodel the control measures based on 

24-hour averages. 

S02 Emissions and Controls 

4.	 The analysis used 11 years for the remaining useful life for all of the control technologies. 

However, the typical useful life of these control technologies is expected to be 15 years 

based on infonnation 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 not have 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. 

3 
5.	 In your BART analysis, you did not analyze aI!f fuel switching options for S02 control. 

Fuel substitution to lower the fuel sulfur content can be a very cost effective means for 

reducing S02 emissions and should be analyzed. The analysis does state that coal 

cleaning would not result in sulfur reductions; however there are no calculations or 

documentation that supports this. PPL needs to provide an analysis for fuel switching 

options and provide an analysis to show what emission reductions coal cleaning would 

result in. 

6.	 In the portion of the analysis pertaining to energy impacts, you state that cost estimates 

are based on experience from Colstrip Units 3&4. PPL needs to provide additional 

information and documentation to explain how it translated the energy impacts at Units 

3&4 to Units 1&2. 

7.	 The BART Guidelines indicate that EGUs with pre-existing post-combustion controls 

achieving removal efficiencies of at least 50% should consider upgrades to the current 

scrubbers. PPL currently has pre.-existing post-combustion controls with venturi wet 

scrubbers achieving at least 50% control efficiency. In the BART analysis, PPL only 

considers the addition oflime to 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 "For those BARTeligible EGUs with preexisting post-combustion S02 controls achieving removal 

efficiencies of at least 50 percent, your BART determination should consider cost 

effective scrubber upgrades designed to improve the system's overall S02 removal 

efficiency. There are numerous scrubber enhancements available to upgrade the average 

removal efficiencies of all types of existing scrubber systems. We recommend that as you 

evaluate the definition of "upgrade", you evaluate options that not only improve the 

design removal efficiency of the scrubber vessel itself, but also consider upgrades that can 

improve the overall S02 removal efficiency of the scrubber system. Increasing a scrubber 

system's reliability, and conversely decreasing its downtime, by way of optimizing . 

operation procedures, improving maintenance practices, adjusting scrubber chemistry, 

and increasing auxiliary equipment redundancy, are all ways to improve average 802 

removal efficiencies. We recommend that as you evaluate the performance of existing 

wet scrubber systems, you consider some ofthe following upgrades, in no particular 

order, as potential scrubber upgrades that have been proven in the industry as cost 

effective means to increase overall S02 removal of wet systems: (a) Elimination of 

Bypass Reheat; (b) Installation of Liquid Distribution Rings; (c) Installation of Perforated 

Trays; (d) Use of Organic Acid Additives; (e) Improve or Upgrade Scrubber Auxiliary 

System Equipment; (f) Redesign Spray Header or Nozzle Configuration." (see 70 FR 

39171, July 6,2005). PPL needs to provide an analysis for upgrades to the current 

scrubbers that includes the upgrades suggested by the BART Guidelines and any other 

improvements to this control equipment that may be appropriate. 

4 
NOx Emissions and Controls 

8.	 The analysis used 11 years for the remaining useful Iif~ for all of the control teclmologies. 

However, the typical useful life of these control teclmologies is expected to be 20 years 

based 0(1 information from the EPA Control Cost Manual (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 not have 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 Cost Manual. 

9.	 You state in the BART analysis that the new NOx NSPS level is below the presumptive 

BART level and therefore was not analyzed. The BART Guidelines require an analysis 

of a level of control equivalent to NSPS, even ifit is below the presumptive limits. 

Specifically, the BART Guidelines state that "Where a NSPS exists for a source category 

(which is the case for most ofthe categories affected by BART), you should include a 

level of control equivalent to the NSPS as one of the control options. The NSPS standards 

are codified in 40 CFR part 60. We note that there are situations where NSPS standards 

do not require the most stringent level of available control for all sources within a 

category. For example, postcombustion NOx controls (the most stringent controls for 

stationary gas turbines) are not required under subpart GG ofthe NSPS for Stationary Gas 

Turbines. However, such controls must still be considered available technologies for the 

BART selection process." (see 70 FR 39164). PPL needs to provide an analysis for NOx 

that is equivalent to the current NSPS. 

10. In your analysis for adding Separated Overfue Air (SOFA), you state that you based COlt 

estimates on recent upgrades to the burners in Units 3&4. PPL needs to provide 

additional information and documentation to explain how it translated the costs of adding 

SOFA at Units 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 BART Guidelines state "Most EGUs can meet these 

presumptive NOx limits through the use of current combustion control technology, i.e. 

the careful control of combustion air and 10w-NOx burners. For units that cannot meet 

these limits using such technologies, you should consider whether advanced combustion 

control technologies such as TOtating opposed fire air should be uscd to meet thcse 

limits." (see 70 FR 39172, July 6,2005). In addition to the analysis for SOFA, SNCR, 

and SCR, PPL should analyze new control technologies than can achieve higher control 

levels than LNB and SOFA. Some ofthe technologies PPL should analyze include 

advanced separated overfire air (ASOFA), rich reagent 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 it is in Table A4-8(b) and Table 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. 

Particulate Matter Emissions and Controls 

13. On page 4-10 of the BART analysis, you state that "Wet scrubbers are currently operating 

to control particulate and S02 emissions on Colstrip Units 1&2. While enhancements to 

particulate collection efficiency are potentially possible, the filterable emission rates of 

0.047 and 0.058 IbIMMBtu, as determined from stack testing, are already very low and 

indicative of excellent control efficiency for this technology. Furthermore, enhancement 

of the wet scrubbers would not be expected to result in additional particulate removal. 

Accordingly, ESP and FF controls were the applicable and available control technologies 

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

boilers." PPL needs to provide an analysis or information for the basis of the statement 

that 98% control efficiency can not be enhanced to perform better. 

14. The PPL PM 10 BART analysis assumes that the lowest emission rate achievable by 

either a fabric filter (baghouse) or an Electrostatic Precipitator (ESP) is 0.Ql5 IbIMMBtu. 

However, EPA has proposed that the Desert Rock power plant will meet a filterable 

PMIO limit of 0.010 IblMMBtu (see Desert Rock Energy Center Proposed 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 Best Available Control Technology using techniques developed in the 

EPA Control Cost Manual. 

In order to move forward with the BART process, we ask that you submit the requested 

information and analysis to our office within thirty days from the date ofthis letter. 

Once again, we would like to thank you for submitting the BART analysis and 

acknowledge the work that has gone into preparing this analysis. If you have any questions, 

please contact Laurel Dygowski at (303) 312-6144. 

',..... ~RC~ ./

"--~J?~ ~VidetiCh,Director 

Air and 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 FiredSUb-bltumlrlous~()al Combustl()~~t Colstrip Unit 1 or 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 Exhaust VolumetricFlowrate, (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 (withlow S coal) IbsIMMBtu 30-dayavg OAOO 

~()ntrolle.cJ SQlED}i~~i9IlS(wittl ClcJcjecjlirneL IbsIMMBtu ___• --_-'_0'. _. __ ", •• _. 30::(jaYavg 0.200 

E:)(hClLJsfrelllRElrature, eFL T 314 

Stearn l"LJrblnePOVier Qutput (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 

Cost of Lime Inlection Equipment<l) 

Equi PITl~lltCost Total,(EC) (2007 dollars) $1,500,000 

Total Capital Costs, TCC $1,500,000 

Direct Annual Costs, DCC 

Operations and Maintenance Costs Lime Cost $375,000 

Miscellaneous O&M Costs $,year .- - ..... _. --- $125,000 

Total O&M Cost $500,000 

Indirect Annual Costs 

Capital Recovery CRF'TCC $164,692 

Total Indirect Annual 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&4 
Table 4.1-2 

PPL BART Cost Analysis 

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 1 or 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 Exhaust Volumetric Elowrate, (acfm) 

.t\:1i3,l(irnu.m.~r()sslj~atlnQut

Design Percent Load 

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 Cost Total, (EC) 

Total Capital Costs. TCC 

Direct Annual Costs, DCC 

Operations and Maintenance Costs 

Miscellaneous O&M Costs 

Total O&M Cost 

Indirect Annual Costs 

Capital Recovery 

Total Indirect Annual Costs, lAC 

Total Annual Costs, TAC • DAC + lAC 

<: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 

1JIncludes lime injection equipment based on the cost of similar eqUipment for units 3&4 
TangentialI}' Fired SUb-bltumlno

Stack~hi:JlJ§t V()lu_n1~tri cFIOWT(jte,tacfm) 

Maximum Gross Heat Input 

Design Percent Load 

Uncor1tr()lI~d~Q2~n1issi()ns{~thlo~ ~f()aIJ

Controlled S02 Emissions{with added lime) 

ExhaustTemperarure, (OF) 

Steam TUrbinepower Output (TMW) 

Hours of9peration 

lJncol1trolled~()2Emissions,{lblbrl.

lJnc(mtrollecJ~Q2 Emi ssi ons, (tonsNr) 

C()rJlroUed~02Emi ssions, ttonfyT) 

Value ~~,of u Power ~~ w, .,_ .' __ , _ _ _ Generated __ 

,Annual Interest RatE;l, (,*,) 

[)epreciationSchEldule (yr§) 

Capital Recovery Factor, CRF 

u~~~~Cl~

Cost Item 

Cost of Lime Injection Equipment<l) 

Basic lime injection equipment 

Additional sprays and absorption pump 

Totalc:al>ital Costs, TCC 

Direct Anl"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 1 or 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 

Indirect Annual Costs 

Capital Recovery	 CRF'TCC --- $329,384 

Total Indirect Annual Costs, lAC $329,384 

Total Annual Costs, TAC • DAC + lAC $1,929,384 

Cost Effectiveness ($/ton pollutant removed) $486 

Cost data references: 

111ncluges lime injection equipment based on the cost of similEir eqUipment f()r units 3&4 
Table 4.1-4
 

PPL BART Cost An"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-hr Average Emission Rates
 

Stack Exh8LJst Volumetric 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 

Steam Turbine Power Output (TMW) MW 330 

Hours of Operation 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 

Direct Annual 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 

Indirect Annual Costs 

Capital Recovery CRF"TCC $329,384 

Total Indirect Annual 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&4 
Table 5.2-1: SNCR Cost Analysis 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 at tuliload) 

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) 

Electri city 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 

( Per Control 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 metering for five zones 

• Water booster pumps 

• Urea solution distribution module 

• Valved connectors for urea and atomizing air 

- Flow monitoring for each injector- wall and 

lor lance type injectors 

• NOx momtor WIth feedback controls for urea 

Injection control 

- Foundationfor tank 

- 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 005 x IDCC 

Engineering and Home Office Fees 010xIDCC 

Process Contingency 005 x IDCC 

Total Indirect Installation Costs, TIlC 

Olher Capital Coate 

Project Contingency 015 x (IDCC + TIle) 

Preproducti on Cost 0.02 x (IDCC +TIIC + Project Contingency) 

Total Other Capital 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 1 23 

Added coal cost Increased coal consumption for vaporization 

Annual maintenance cost 0015xTCC 

Total Direct Annual Costs, IDAC 

Indirec1 Annual Costs 

Administrabve 002xTCC 

Propertry Taxes 001xTCC 

Insurance 001xTCC 

Capital RecoveIY - SNCR System CRFxTCC 

Total Indirect Annual Costs, TIAC 

Total Annual Coate, TAC· TOAC + TlAC 

Cost erectlveness ($/ton pollutant Removed) 

Cost data references: 

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

IDCC Adjusted using CI=96.089 (1998) to CI=121303 (2008) 

Equation 119 from OAQPS CCM DCC = $950xQ, x [2375/CI,f'" x [0.66 + 085 x eft] 

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 

Cost taken 

from EPA Cost 

Manual 

Equation 1.19 

(See notes for equati on) 

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 

$905 
Table 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 a 50% Solution ($Igallon) 

SNCR Life, (yrs) 

Capital RecOYeIY Factor, SNCR CRF(20yr) 

De.lgn Paramot.rs Sugg.st.d Factor 

SNCR Capital Equipment Cost SNCR System, including 

(Per Control Cost Manual, Equation 1.19) - Urea unloading ski d 

Includes eqUipment, instrumentation, sales tax - Centrigugal pumps for unloading 

freight, math modeling, urea pumps, etc. - Vertical Insulated fiberglass urea storage tank 

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

instrumentation 

- Injecti on zone meten ng 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>: monitor with feedback controls for urea 

injection control 

- Foundationfor tank 

- 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) 

Tolli Direct Capital Coata, TOCC (S.e coot rererencea notes, 

Indlr.ct Coata 

Indlr.ct In818l1atlon 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 015 x (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.ct Annual 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 for vaporizabon 

Annual maintenance cost 0015xTCC 

Total Direct Annual Costs, TDAC 

Indlr.ct Annual Coata 

Administrative 002xTCC 

Propertry Taxes 0.01 xTCC 

Insurance 0.01 xTCC 

Capital RecOYeIY - SNCR System CRFxTCC 

Total Indirect Annual Costs, llAC 

Tol8I Annual Coata, TAC· TOAC + TlAC 

Coot Eft'eetlv.n... (S/ton poUut.nt Remov.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 x eft] 

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 

$852 
Table 5.3-1: SCR Cost Analysis for Colstrip Units 1&2 (each) 

3O....y Av".go COlO· 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-day avg 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 VelOCity tIlrough SCR (ft/min) 960 

Percent 0, at SCR inlet 4% 

BdlaustGas Temp at SCR 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 Cost for 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 x a" 11,070 

wINO>< Efficiency Adjustment Factor 0.2869 + (1.058 x e",100) 1.012385714 11,207 

wIInlet NO>< Adjustment Factor 0.8524 • (0.3208 x NOx,") 096468 10,811 

WIAmmonie Slip Adjustment factor 1 2835 - (0 0567< slip) 1000 10,811 

wlSulfur in Fuel Adjustment o9636 • (0 0455 x S) 10091 10,910 

wiTemperallJre Adjustment Factor 15.16 - (0.03937 x 1).2.74 x W' x T' 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 Integer value) 30 

Height of a Layer (ft) (11.,..) (V",", N layersl A) + 1 391 

Number of Empty Layers (F or cata/ySl management) 1 

SCR Height Per b1dustry Standards (ft) hsc. : """ X (7 +11.,..) • 9 526 

Ibslhr ammonia as NH, Noxi n x a." x NSR x eff< 17/46 488 

gallonslhr of aqueous ammoni a 225 

Total Dlroct Capital Cooto. TOCC (S.. coot "',,onc.. not..) $20,407,368 

Indirect Com 

Indlroct "',tallotlon Co,to 

General Faciliaes Cost 0.05 x 10CC $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.pltal Com 

Project Contingency o15 x [TOCC + TIIC) $3,673,326 

Preproduction Cost 0.02 x [TOCC ,TIIC 'Project Contingency) $563243 

Total OtIler Capital Costs, TOCC 10CC + TIIC • Pro) Contingency $4 236 570 

Total Capital Com. TCC 10CC + TIlC + TOCC 528.nU11 

Direct Annual 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<lrect Annual Costo 

Administrative o 02xTCC $574,508 

Propel1JY Taxes 001 xTCC 287,254 

Insurance 0.01 xTCC 287,254 

Capital Recovery - Catatysr CRF(3,.) x Catatyst 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 

Coo1 Ell'actlvona.. (SIlon pollulanl R,mo.ad) 

Cost data references 

OAQPS Control Cost Manual (CCM), Sixtll Edltion, EPA-452-02-001, January 2002 

IDCC Adjusted using 0:96.089 (1998) to CI:121.313 (2008) 

Notes: 

1. Electricity cost includes ammoma vaporization heaters 

2. Assumes replacement of all catalyst at lIle end of 3 years witll replacement catatyst@$290 cubiC Inot 

51.942 
Table 5.3·2: SCR Cost Analysis for Colstrip UnItS 1&2leachl 

Maximum 24./lr Avorage 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 Cost for a 29% SolUllon ($Igallon) 

Cata~ Amortlzation Penod, (yrs) 

SCR Amortization Period, (yrs) 

Capital Recovery Factor, Catatyst 

Capital Recovery Factor, SCR 

D••lgn Paramll... 

ACFM 

Catatyst Volume 

Base Volume 

wlNOx Efficiency Adjustment Factor
 

wIInlet NOx Adjustment Factor
 

wlAmmoni a Slip Adjustment factor
 

wlSulfur in Fuel Adjustment
 

wITemperature Adjustment Factor 

Araa Catatyst (Al 

Area of SCR (11') 

Length and Width of SCR (n) 

N layers 

Number of Layers 

Height of a Layer (n) (tI.,...) 

Number of Emp!)' Layers 

SCR Height Per .,duslry Standards (n) 

Ibslhr ammonia 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.d Factor 

281x~

02869 + (1.058 x eff/l00)
 

08524 + (0.3208 x NOlcin)
 

1 2835 - (0 0567 x slip)
 

09636 + (0 0455 x S)
 

15.16 - (0.03937 x T) + 2.74 X 10'5 x T2
 

Based on veloic!)' of 960 fpm
 

115xA
 

Square Sed
 

V",,1311A
 

(to nearest integer value,
 

(Voa/ N layers! A) + 1
 

(For catatyst management)
 

hsao= 'I.... x (7 + 110,...1 + 9
 

No";n x a..., x NSR x eff x 17146
 

Total DIr.ct Capitol Com, TDCC (S.. coil ,,'..anc.s notasl 

Indlr.ct Costa 

Indlract Installation Com 

General Facilities Cost
 

Engineering and Home Office Fees
 

Process Contingency
 

Total Indirect InstaUation Costs, TIIC 

othar Capita' Com 

Project Conti ngoncy 

Preproduction Cost 

Total Other Capital Costs, TOCC 

Total Capital Costa. TCC 

Dlract Annual Colllt 

Annual Ammonia Cost
 

Eleclnci!)' (Added Cost due to SCR)'
 

Annual Mainrennace Cost 

Total Direct Annual Costs, IDAC 

Indlract Annual Costa 

Admi ni stratlve 

Propertry Taxes 

Insurance 

Cap,tal Recovery - Catatyst' 

Capital Recovery - SCR System Less Calatyst 

Totallndirect Annual Costs, TIAC 

Total Annual Colllt, TAC • TDAC + TlAC 

Cost Effactlvan... (Slton pollutant Ramovad) 

Cost data references: 

0.05 x IDCC 

o10xIDCC 

0.05 x IDCC 

0.15x[IDCC+TIIC)
 

0.02 x [IDCC + TlIC + Project Contingency)
 

IDCC + TIIC + Pro] Contingency
 

IDCC + TIIC + TOCC 

CCM, Equation 2 48 

0015xTCC 

002xTCC 

0.01 xTCC
 

0.01 xTCC
 

CRF(3 yr) x Catatyst 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 

IDCC Adjusted using CI=96.089 (1998) to CI=121 313 (2008) 

Notes: 

1. Electrici!)' cost includes ammonia vaporization heaters 

2. Assumes replacemart of all caratysr allhe end of 3years with replacement Calatysl@$290 cubiC foot 
Table 5.3-3: SCR Cost Analysis for Colstrip Units 1&2 leach) 

JO-d-v Av.rag. c.... Mulmum Control to 0.06 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 Coslfor a 29% Solution ($Igalon) 

Catetyst Amortizeti on Pen od, (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 NOx Adjusnnent 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) 

N layers 

Number of Layers 

Height 01 a Layar (ft) (~)

Number of Empty Layars 

SCR Height Per Industry Slandards (ft) 

Ibsihr ammonia 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.d F.ctor 

2,81 xC\,
 

0.2869. (1 ,058 x eff1100)
 

0,8524 • (03208 x NOxin)
 

1 2835· (00587 x slip)
 

o9838 • (0 0455 xS)
 

15,16 - (0,03937xT). 2 74 x 10" x T'
 

Based on velOCity of 960 rpm
 

115xA
 

Square Bed
 

V,.13,lIA
 

(to nearest Inleger value)
 

(V",; N layars! A). 1
 

(For catatysl management)
 

hsao ="".x(7.~). 9
 

Nox," x A... x NSR x effx 17/46
 

Tot.1 DIr.ctCopltll Com, rocc (5•• coot r.foronc.s not.s) 

Indlr.ct Com 

Indlr.ct Installation 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 

Direct Annuli Com 

Annual Ammoma Cost 

ElectriCity (Added Cost due to SCR)' 

Annual Maintennace Cost 

Total Dllect Annual Costs, TDAC 

Indirect Annu.1 Costs 

Administrative
 

Propertry Taxes
 

Insurance
 

Capital Recovery - Catatyst'
 

Capital Recovery· SCR System Less Calatyst
 

Totallndlrect Annual Costs, TIAC 

Totol Annual Co.ts, TAC • TDAC + TlAC 

Cost E1rtcttvtnts. (Slton pollut.nt R.movtd) 

Cost data references: 

0,05xTDCC 

0,10xTDCC 

005xTDCC 

0,15x [IDCC .TIIC)
 

002 x (IDCC • TIIC • Project Conti ngency)
 

TDCC • TIIC • Pro) Contingency
 

TDCC • TIIC • TOCC
 

CCM, Equation 248
 

0015 xTCC
 

o02xTCC 

0.D1 xTCC 

0,01 xTCC 

CRF(3 yr) x Catalyst Cost
 

CRF(20 yr) x (TCC - Cata",! Cost)
 

30-day avg 

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 at the end 013 years with 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 

51,735 
Table 5.3-4: SCR Cost AnalySis 'or Colstrip Un.s 1&2 leach) 

Miximum ~r Avorllgl CII' • Moxlmum Conlrolto 0.06 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 

Exhaust Gas Temp at SCR Inlet (deg F) 

Ammonia slip (ppmv) 

Ammonia Solution Concentration 

Sulfur content In coal 

Annual Interest Rate, (%) 

Electricity Cost ($!kWhr) 

Ammonia Cost for a 29% Solubon ($lgalionJ 

CatattstAmortizabon Pehod. (\'f5) 

SCR Amortizabon Penod. (\'f5) 

Capital Recovery Factor. Catattst 

Capital Recovery Factor, SCR 

D.Ilgn Par"",.t..1 

ACFM 

Catat,-sl Volume 

Base Volume 

wiNOx Efficiency Adjustment Factor 

wnnlet NOx Adjustment Factor 

w/Ammoni a Slip Adjustment factor 

wlSulfur in Fuel Adjustment 

wlTemperature Adjustment Factor 

Area Catattst (A) 

Area of SCR (fI') 

Length and Width of SCR (ft) 

N layers 

Number of Layers 

Height of a Layer (ft) (tI.,~)

Number of Empty Layers 

SCR Height Per IndUstry Standards 1ft) 

Ibslhr ammoni a as 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.d Flctor 

281xa"
 

0.2869 +(1.058 x eff/l00)
 

0.8524 +(0.3208 x NOxin)
 

1 2835 - (0.0567 x shp)
 

o9636 + (0 0455 x S)
 

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~ N layers! A) + 1
 

(For catattst managementJ
 

hsat= ....... x(7+~)+9
 

Noxm x Q~,x NSR x effx 17146
 

Totll DIr.ct Capilli Costl, TOCC (5•• cost reterenc," not.l) 

Indirect Costl 

IndlrectlnstllllUon Costl 

General Faci~ties Cost 

Englneenng and Home Office Fees 

Process ConMgency 

Total Indirect Instanabon Costs, TIiC 

Othor Clpllil Costl 

Project Contingency 

Preproduction Cost 

Totai Ot!1er Capital Costs, TOCC 

Totl' Clpilit COlts, TCC 

DIr.ct Annual Costl 

Annual Ammonia Cost
 

Electricity (Added Cost due to SCR)'
 

Annual Maintennace Cost
 

Total Di rect Annual Costs, TDAC 

Indlr.ct Annual COlts 

Admi nj stratlve
 

Propertiy Taxes
 

Insurance
 

Capital Recovery - Catattst'
 

Capitel Recovery. SCR System Less Catalyst
 

Total Indirect Annual Costs, TlAC 

Total Annual Costl. TAC· TOAC + nAC 

Cost Elr.ctIv.n... (Slton pollullnt R.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 

002 xTCC 

0.01 xTCC
 

0.01 xTCC
 

CRF(3 yr) x Catattst 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 all catat;st at the end of 3 years WIth replacement catattst@$290 cubiC foot 
Table 6.1·1
 

PPL BART Cost Analysis
 

Electr!>statlc Preclplta_torParticulate Control
 

330 Megawatt Coal Fired steam Electric Unit
 

Dry-Bottom Combustion In Colstrip Unit 1 and 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 

Steam Turbine 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 PMEmissions, (tonslyrl 833 

Controlled PM Emissions, (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 Cost Total, (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.ct Capital 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 Cost x 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 

$119,160,318 
Table 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-Bottom Combw;tlonlllColstrlp Unit 1 and Unit 2 (each)
 

0.015 Ibs/MMBtu Emission Rate 

Direct Annual 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 

10 hrlshift 

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 

Indirect Annual Costs 

Overhead 

Admi ni strative , --~ ._..._----,.,--< 

Propertry Taxes 

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 Indirect Annual 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 Cost Manual extimates P= 1.94 x 10-3 x SCA x hrs,yr as the total of electrification and rapping 

electiciity power consumption in kVVhrsfyT SCA is based on a SCAof 250 tr-/1,OOO ACFM 

and a migration velocity of 10 crn/sec characterisitc of coal fly-aSh 

3. Collector area= 250 tr-/1,OOO ACFM x Q = 308,437 tr­
Table 6.1-2
 

PPkB~~T Cost ArIalysls
 

Electrostatic Precipitator Pl1rt1clJlate Colltrol
 

330 Megawatt Coal 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 FilterablePMEmis?i ons 

Controlled Filterable PM Emissions 

ExhaustTemperature, ("F) 

SteamTurbine Power Output (MVV) 

Hours of Operat on 

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 Preparati on 

Building 

Total Direct Capital Costs, DC 

Indirect Capital Costs 

Engineering 

Construction and Field Expenses 

Contractor Fees 

Start:Up 

Performance Test 

Model Stucly 

Contingencies 

Total Indirect Capital Costs, IC 

Total Capital Costs, TCC· DC + IC 

Suggested Factor 

Capital Cost ($Jl<W) 

EC (Adjusted by Cost Index Cales) 

New Equi pment Cost x 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 

$119,160,318 
Table 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 

Direct Annual 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 10 hr/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 Direct Annual Costs, DAC $1,157,805 

Indirect Annual Costs 

Overhead 60"10 of Operating Labor and $580,578 

Maintenance Costs 

Admi ni strative 0.02TCC $2,383,206 

Propertry Taxes 0.01 TCC $1,191.603 

Insurance 0.01 TCC $1,191,603 

Capital Recovery CRF*TCC $11,243,871 

Total Indirect Annual 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 Center for 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 a function of the Specific Collecting Area (SCA)
 

The OAQPS Control Cost Manual extimates P= 1.94 x 10-3 x SCA x hrs¥ as the total of electrification and rapping 

electiciity power consumption in kVIIhrS¥. SCA is based on a SCA of 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 Cost Analysis 

Pulse Jet - Fabric Filter for 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 Cost Total, (EC) 

Direct Capital Costs 

Purchased EqUipment Costs 

FF and Auxiliary Equipment 

Instrumentation 

Sales Tax 

Freight 

Purchased EqUipment Costs, PEC 

Direct Installation Costs 

Foundations and Supports 

Handling and Erection 

Electrical 

PiPing 

Insulation for Ductwork 

Painting 

Direct Installation Cost, DIC 

Site Preparation 

Building 

Total Direct Capital Costs, DC 

Indirect Capital Costs 

Engineering
 

Construction and Field Expenses
 

Contractor Fees
 

Start-Up
 

Performance Test
 

Contingencies
 

Total Indirect Capital Costs, IC 

Total Capital Costs, 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 

$69,351,246 
Table 6.1-3 continued
 

PPL BART Cost Anillysls
 

Pulse Jet - Fabric Filter for 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 1 or Unit .. (~Clcll}
 

0.015 Ibs/MMBtu Emission Rate 

Direct Annual Costs 

Utilities
 

Fan Power1

)
 

Compressed Air Cost2

)
 

Ash Disposal Costs
 

OJ)eratil1gL(jbor
 

Operator
 

SUJ)ervisor
 

Maintenance
 

Labor
 

MCl!~riCl!!),r~pl(jcElmenJ~Clgsl

Total Direct Annual Costs, DAC 

Indirect Annual Costs 

Overhead 

Admi ni strative
 

Propertry Taxes
 

Insurance
 

Capital Recovery
 

Total Indirect Annual Costs, lAC 

Total Annual Costs, TAC • DAC + lAC 

Cost Effectiveness (Slton pollutant removed) 

Fp =(1.81 x 10·4)(Q)(deltaP)(hrsfyr)
 

2 scfm/1 ,000 acfm (each minute)
 

Transportation not included
 

10 hrlshift
 

15"10 of Operator
 

$037 I 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 in w.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 

DevelopmentCenter for 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 by the 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 to be $025 per 1,000 scfm
 

3. Bag replacementc0st canvarylNide~from 15%to 1QO% of the PEC(15% assumed); 

the bag life is assumed to be 2 years and a capital rec(Jl{ery factor of 0.5454 has been applied to the annual 

bag replacement cost NG ratio of assumed. $O.ytt2 labor cost assumed for bag replacement 
Table 6.1-4
 

PPLJSART Cost ~nalysls
 

Pulse Jet· Fabric Filter for 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 1 or 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 Output lMW)
 

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 Recovery F<: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 Cost Total, (EC) 

Direct Capital Costs 

Purchased Equipment Costs 

FF and Auxiliary Equipment 

Instrumentati on 

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 Preparati on 

Building 

Total Direct Capital Costs. DC 

Indirect Capital Costs 

Engineering
 

Construction and Field Expenses
 

Contractor Fees
 

Start-Up
 

Performance Test
 

Contingencies
 

Total Indirect Capital Costs. IC 

Total Capital Costs, TCC • DC + IC 

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 

$69,351,246 
Table 6.1-4 condnued
 

PPL BAIlT Cost Analysis
 

Pulse Jet· Fabric Filter for 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 1 or Unit 2 (eacm
 

0.010 Ib/MMBtu Emission Rate 

Direct Annual 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 

Indirect Annual Costs 

Overhead 

Admi ni strative 

Propertry Taxes 

Insurance 

Capital Recovery 

Total Indirect Annual Costs, lAC 

Total Annual Costs, TAC • DAC + lAC 

Cost Effectiveness (Slton pollutant removed) 

Fp =(1.81 x 1O-4)(Q)(delta Pj(hrsi{r) 

2 sCfm/l,OOO acfm (each minute) 

Transportation not included 

10 hrlshift 

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 Center for Environmental Research Information, June 1992. 

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

Cost data assumptions: 

Costsadjusted by costindicEls for 2008 CI=121313, and 1988 CI=74.587 

1. FF's have high~ variable pressure drops (70" w.c. assumed) - Electricity cost at $0.08IkV\iHr is typical 

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

2 scfm of <:ompress§ld air is assumEld to be required for each 1,000 acfm per minute of operation
 

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

3. Bagreplacement costcan varywide~from 15% to 100% ofthepEC (15% assumed): 

the bag life is assumed to be 2 years and a capital recovery factor of 0.5454 has been applied to the annual 

bag replacement cost A/C r~io of 5 assumed. $0.31fi2labor c()st a?sumed for bagreplacement 
Subject to Confidentiality Claim 

Confidential
 

Attachments 1 and 2
 

Attaclnnents to:
 

AddenduDl to
 

PPL Montana's
 

Colstrip BART Report
 

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 
3 

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..Jo. 
CONFIDENTIAL BUSINESS INFORMATION 

Confidential Attachment 1 

SOFA Cost Effectiveness Tables 

Subject to Confidentiality Claim 

Attachment to 

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 information is based. 

~UbJect to LOJllUlentIaUty Claim. 
Subject to ContidentialHv Cl!J.JI( 

CONFIDENTIAL BUSINESS INFORMATION " 0./'''1,)., 

Table 5.1-1
 

PPL BART Cost Analysis
 

LNCFS Level III NOx Burner Controls with SOFA
 

330..,egaYiatt Coalp:lr~~ ~~iII11l!!ectrlc Unl!
 

Tangentially Fired Sub-bltumlnous Coal Combustion In Colstrip Units 1&2 (Each)
 

30-day Average Emission Rates
 

Stack Exhaust Volumetric Flo......rate, (acfm)
 

Maximum Gross Heatlnput
 

Annual Capaci~ Factor (hrsiyT at full 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 Recovery Factor, CRF
 

Cost Item 

Capital EqulpmElnt Cost(2008] 

Equipment Cost Total, (Ee) 

Total Capital Costs, TCC • DC + IC 

Total Direct Annual Costs, DAC 

Indirect Annual Costs 

Capital Recovery 

Total Indirect Annual Costs, lAC 

Total Annual Costs, TAC· DAC + lAC 

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 

SOFA Actuators 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 

Cost Effectiveness ($lton pollutant removed) $437 

Cost data references: 

1] Alstom Proposal Number 43033682-01 
CONFIDENTIAL BUSINESS INFORMATION 

Subject to (oniideuthmiY \.J~C]~"

Table 5.1·2
 

PPL BART Cost Arlalysls
 

LNCFS Level III NOx Burner c:ontrolswhh SOFA
 

330 Megawatt Co21IFlred ~4'clll\Elec:trlcUIlIt
 

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 at full load) 

Uncontrolled NOx Emissions 

Controlled NOx Emissions 

ExhaustTemperature,("F) 

$tearn TUrbine 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 Cost Total, (EC) Cost From March 2008 Alstom Quote 

Installation Cost 

SOFA Actuators 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 Capital Costs, TCC· DC + IC - $4,708.845 

Total Direct Annual Costs, DAC o.25 mllllkW-hr $664,884 

Indirect Annual Costs 

Capital Recovery CRF'TCC --­ $444,482 

Total Indirect Annual Costs. lAC $444,482 

Total Annual Coats, TAC • DAC + lAC $1,109,366 

Cost erectlvenen ($lton pollutant removed) $321 

Cost data references:
 

1) A/stom Proposal Number 43033682-01
 

 

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CONFIDENTIAL BUSINESS INFORMATION 

Subject to Coniidentmul,J' \A~1U~,

Confidential Attachment 2 

Supplemental Fuel Switching Discussion 

Attachment to 

Addendum to PPL Montana's Colstrip BART Report 

June 12,2008 

Prepared by
 

TRC Environmental Corporation
 

and
 

PPL Montana
 
. ~\y Claim • t "'0 Confldentla I 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 if Colstrip 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 of the study was to investigate the feasibility of upgrading 

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 power plant 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 if a 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 per unit 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. If this 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 of increased 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 of the 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 

Subject to 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 of 0.7% to coal with a sulfur content of 0.3% 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 of sulfur 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 of the scrubber vessels. 
CONFIDENTIAL BUSINESS INFORMATION
 

Subject to ConfldentiaJity Claim 

Table 4.2-1
 

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 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 

Subject to 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 Unit 2 

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 

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) 

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.