ES–1 

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 burn 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 SO2 and 20 years for NOx, rather than 11 

years for both. 
ES–2 

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

NSPS level of 0.11 lb/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 SO2 control 

– Transferal of energy impacts associated with SO2 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 SO2 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 SO2 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-1, ES-2 and ES3. The cost evaluations in Table ES-1 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–3 

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 1 & 2, that 

implementation of further controls is not warranted. 
Table ES-1: Control Costs Summary – Typical 30-Day Average Emission Rates 

ES–4 
Table ES-2: Control Costs Summary – Maximum 24-Hour Average Emission Rates 

Table ES-2: Control Costs Summary – Maximum 24-Hour Emission Rates 

ES–5 
Table ES-3: Estimated Visibility and Visibility Improvements 

Estimated Estimated Estimated

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

Option (lb/MMBtu) (deciview s) Present Inc (6) Option (lb/MMBtu)(deciview s) Present Inc (6) Option (lb/MMBtu)(deciview s)Present Inc (6)

Present 0.0525 2.233 n/a n/a Present 0.76 2.233 n/a n/a Present 0.49 2.233 n/a n/a

ESP/FF 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

ESP/FF 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

Fuel SW 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 emission rate is the rate corresponding to the maximum daily emissions during the modeling years (2001-2003).

 (scaled by the expected control efficiency for control alternatives)

 (2) Average emission rates betw een Units 1&2If Unit 1 and Unit 2 emission rates are different, they are indicated as Unit 1/Unit 2 rates.

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

 (4) SO2 emissions reduced by 88%.

 (5) SO2 emission sreduced by 91%.

 (6) Inc = incremental.

 (7) Maximum improvements show n may occur at different Class I areas than the maximum prediction among all Class I areas.

Improvement (7) Improvement (7) Improvement (7)

ESTIMATED VISIBILITY AND VISIBILITY IMPROVEMENTS 

Filterable Particulate Sulfur Dioxide Nitrogen Oxides

ES–6 
i 

TABLE OF CONTENTS

EXECUTIVE SUMMARY ..................................................................................................... ES–1 

1.0 INTRODUCTION ...........................................................................................................1-1 

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 SO2 EVALUATIONS...................................................................4-1 

4.1 Maximum SO2 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 SO2 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 0.01 lb/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 
ii 

TABLE OF CONTENTS continued 

LIST OF TABLES 

Table ES-1: Control Costs Summary – Typical 30-Day Average Emission Rates................. ES-4 

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) SO2 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 

Table 3-2: Parameters for Interpolation and Extrapolation of Visibility Estimates 

(Approach 1)........................................................................................................... 3-3 

Table 7-1: Control Costs Summary and References................................................................. 7-2 

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

Evaluated and Corresponding Differences Between Control Cases.......................8-2 

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

Evaluated................................................................................................................. 8-3 

Table 9-1: Control Costs Summary – Typical 30-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 CALCULATION TABLES
1-1 

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(1) 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 burn 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. 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 SO2 and 20 years for NOx, rather than 11 

years for both. 

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

NSPS level of 0.11 lb/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 
1-2 

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 SO2 control 

– Transferal of energy impacts associated with SO2 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 SO2, 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(1) provides an additional 

description of the Colstrip BART analyses. 
1-3 

Table 1-1: EPA January 28, 2008 Comments 

Category EPA Comment Section(s) 

Evaluate the Maximum Control SO2

Level with Lime injection 

4.1 

Evaluate the Maximum NOx Control 

Level with SNCR 

5.2 

1. Evaluate the Most Stringent 

Level that the Technology 

is Capable of Achieving 

Evaluate the Maximum NOx Control 

Level with SCR 

5.3 

2. Provide Proper/Additional Cost Documentation 7.0 

General 

Comments 

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

4. Use a 15 Year Remaining Life for SO2 Control Costs 4.1, 4.2, 7.0 

5. Evaluate Fuel Switching and Coal Cleaning Options for SO2 Control 4.2, 

Attachment 2 

6. Explain How Energy Impacts from Units 3&4 Were Translated to 

Units 1&2 

4.1 

SO2

Comments 

7. Provide an Analysis of Venturi Scrubber Upgrades for SO2 Control 4.3 

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

9. Provide a NOx Control Analysis to the Present NSPS Level 5.3 

10. Provide Additional Information on How SOFA Costs at Units 3&4 

Were Transferred to Units 1&2 

5.1 

NOx

Comments 

11. Evaluate Additional NOx Control Technologies Such As ASOFA, 

RRI and ROFA. 

5.4 

12. Correct Table 4-8(a) Typographical Error Appendix 2 

13. Explain Why the Existing 98% Particulate Control Level Cannot be 

Improved. 

6.1 Particulate 

Comments 

14 Evaluate Particulate Control to 0.01 lb/MMBtu 6.2 
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 burn low sulfur (0.7% S), sub-bituminous northern Powder River Basin coal. Units 1&2 

began commercial operation in 1975 and 1976 and were determined 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 lb/MMBtu, but in 1997 they 

adopted a 0.45 lb/MMBtu annual limit as an early reduction under the Acid Rain Program. This 

level was reduced to 0.4 lb/MMBtu in 2008. Normally, the units operate with a NOx emission 

rate in the range of 0.30 to 0.35 lb/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 SO2

emissions. The design of the wet scrubber includes a venturi/plumb bob section with sprays to 

remove particulate and SO2, followed by a level of absorption sprays for additional SO2 removal, 

followed by a wash tray section for both particulate and SO2 polishing, followed by mist 

eliminators. The scrubbers utilize the alkalinity of the fly ash collected to remove the SO2. 

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% SO2 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 (SO2) 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 SO2 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 (H2SO4) 

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 lb/MMBtu for Unit 1 and 3897.2 lb/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) SO2 and NOx Emissions 

Typical/30-day Average 

Emissions 

Maximum 24-Hour Emissions 

Pollutant Emissions 

Unit lb/MMBtu lb/hr lb/MMBtu lb/hr 

Unit 1 0.40 1592.7 0.72 2612.0 

Unit 2 0.40 1558.9 0.80 2828.0 

SO2

Avg 1&2 0.40 1575.8 0.76 2720.0 

Unit 1 0.35 1393.6 0.45 1798.0 

Unit2 0.35 1364.0 0.53 1955.0 

NOx

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 

percentage of total 55.3% 60.4% 

lb/hr 187.1 226.0 

Filterable(1)

lb/MMBtu 0.047 0.058 

percentage of total 44.7% 39.6% 

lb/hr 151.3 148.1 

Condensable(2)

lb/MMBtu 0.038 0.038 

Coarse lb/hr 53.47 64.58 (3)

lb/MMBtu 0.0134 0.0166 

Soil lb/hr 128.73 155.48 (3)

lb/MMBtu 0.0323 0.0399 

Elemental lb/hr 4.95 5.97 

Carbon(3)

lb/MMBtu 0.0012 0.0015 

lb/hr 187.15 226.03 

Filterable(1)

Total 

Filterable(4)

lb/MMBtu 0.047 0.058 

Organic lb/hr 30.26 29.62 (3)

lb/MMBtu 0.0076 0.0076 

lb/hr 121.05 118.47 

Condensable(2) 

Inorganic(3)

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 lb/MMBtu and 206.6 lb/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 SO2 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 SO2

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 2001, 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 

(lb/MMBtu) 

Visibility 

(Deciviews) 

Base Case 0.76 2.233 

Lime Injection (88%) 0.38 2.00 

Lime Injection (91%) 0.285 1.954 

SO2

New Vessel (91%) 0.15 1.832 

Base Case 0.49 2.233 

SOFA 0.25 1.781 

SNCR 0.225 1.713 

NOx

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 SO2 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 

lb/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 

lb/MMBtu) 

Base Case 

minus 

Lime Injection (88%) 

0.76 – 0.38 

= 

0.38 

2.233 – 2.00 

= 

0.233 

0.61 

Lime Injection (88%) 

minus 

Lime Injection (91%) 

0.38 - 0.285 

= 

0.095 

2.00 – 1.954 

= 

0.046 

0.48 

Lime Injection (88%) 

minus 

New vessel (91%)) 

0.38 – 0.15 

= 

0.23 

2.00 – 1.832 

= 

0.168 

0.73 

Lime Injection (91%) 

minus 

New vessel (91%)) 

0.285 – 0.15 

= 

0.135 

1.954 – 1.832 

= 

0.122 

0.90 

SO2

Base Case 

minus 

New Vessel (91%) 

0.76 - 0.15 

= 

0.61 

2.233 – 1.832 

= 

0.401 

0.66 

Base Case 

minus 

SOFA 

0.49 – 0.25 

= 

0.24 

2.233 – 1.781 

= 

0.452 

1.88 

SOFA 

minus 

SNCR 

0.25 – 0.225 

= 

0.025 

1.781 – 1.713 

= 

0.068 

2.72 

SNCR 

minus 

SCR 

0.225 – 0.15 

= 

0.075 

1.713 – 1.584 

= 

0.129 

1.72 

NOx

Base Case 

minus 

SCR 

0.49 – 0.15 

= 

0.34 

2.233 – 1.584 

= 

0.649 

1.91 

PM Base Case 

minus 

ESP/Fabric Filter 

0.0525 – 0.015 

= 

0.0375 

2.233 – 2.213 

= 

0.020 

0.53 

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: 

(1) 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 
As can be seen in the Table 3-2, the deciview (dv) change per lb/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, 

x = 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 

lb/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 lb/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 of this addendum. 

 The deciview per lb/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 of the originally submitted BART report(1). 

3-5 
4.0 SUPPLEMENTARY SO2 EVALUATIONS

4.1 Maximum SO2 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 SO2 

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 SO2 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 SO2

emission level below 0.15 on a consistent basis. This emission level represents an SO2 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 SO2 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 PRB 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 SO2 controlled based on a 30-day average SO2

emission rate of 0.40 lbs/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 SO2 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 SO2 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 burn 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 SO2 or NOx at plants like Colstrip that burn sub-bituminous coal. 

4-3 
4.2.2 Fuel Switching

The Colstrip Plant burns 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 SO2 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 SO2 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 $10,258/ton based on typical, 30-day average emission rates and 

$5,943/ton based on maximum 24-hour emission rates. These costs are based on transportation 

costs and construction of an unloading facility only. Boiler upgrades and purchase of an 

additional scrubber vessel are additional concerns but because 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 SO2 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 SO2 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 SO2 removal efficiency. In addition, auxiliary equipment redundancy was 

evaluated by adding another set of absorption pumps and sprays to improve SO2 removal 

efficiency. These improvements are included in the analysis to attain a maximum SO2 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% SO2 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 SO2 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 SO2 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% SO2 removal efficiency. 

4-6 
5-1 

5.0 SUPPLEMENTARY NOx 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 lb/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 

lb/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 NOx formation. 

• 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 lb 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 
5-2 

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 lbs/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 lb/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 burns 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 
5-3 

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 of coal-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 of the theory 

and correlations that can be used to estimate design parameters such as the 

required NSR are not published in the technical literature. Furthermore, the 

design is highly site-specific. In light of these complexities, SNCR system design 

is generally undertaken 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 1&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 lb/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 1&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 

lbs/MMBtu attained with the Alstom SOFA techniques, a cost effectiveness of $905 per ton of 
5-4 

NOx controlled would apply to attain 0.15 lb/MMBtu based on the 30-day average emission rate. 

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 lb/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 NOx Control Level

The lowest NOx emission rate evaluated for Colstrip Units 1&2 is 0.06 lb/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 

lb/MMBtu is achievable from a retrofit technology on a continuous basis at Colstrip Units 1&2. 

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 fact the typical control level 

specified in the NSR settlement cases was 0.10 lb/MMBtu.) An emission rate of 0.11 lb/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 H2O 

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 
5-5 

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 of these 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 

computational fluid 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 of NOx 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 lbs/MMBtu, 30-day 
5-6 

rolling average, to 0.11 lbs/MMBtu, 30-day rolling average as well as to 0.06 lbs/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 lb/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 lb/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 0.11 lb/MMBtu 

• SCR 30-day rolling average basis $1735/ton based on 0.06 lb/MMBtu 

• SCR 24-hr average basis $1,565/ton based on 0.154 lb/MMBtu 

• SCR 24-hr average basis $1,412/ton based on 0.084 lb/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 lbs/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-1 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 lb/MMBtu and 

0.06 lb/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 lb/MMBtu and 

0.084 lb/MMBtu relative to the present base case emissions of 0.49 lb/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 
5-7 

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 Overfire Air (ASOFA) 

The design of the SOFA system (evaluated in Subsection 5.1) with individual sets of 

control dampers by corner 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 of this 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 
5-8 

emissions. It is not our intent to encourage evaluation of unnecessarily large numbers of control 

alternatives for every emissions unit...For example, if two 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 

of these 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 1&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 1&2. Since PPL's review 

indicated similar results and costs to SNCR, RRI was not evaluated any further. 
6-1 

6.0 SUPPLEMENTARY PARTICULATE 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 lb/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 lbs/MMBtu. No additional cost for dry 

injection technology has been added to the cost of the 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 
6-2 

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 lbs/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 lb/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 

lb/MMBtu to 0.015 lb/MMBtu is 0.042 deviviews and from the base case to 0.010 lb/MMBtu is 

0.048 deciviews. The maximum incremental improvement to go from an emission rate of 0.015 

lb/MMBtu to 0.010 lb/MMBtu is 0.006 deciviews. For the filterable particulate evaluation, there 

was no distinction between the typical.30-day average and maximum 24-hour emission rates. 
7-1 

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. 
7-2 

Table 7-1: Control Costs Summary and References 

Pollutant Control 

Technology 

Emission Rate 

Averaging 

Time 

Emission 

Rate 

(lb/MMBtu) 

$/Ton Reference 

Fuel Switching 30-day 0.23 $10,258 

24-hour 0.0.445 $5,943 

PPL Estimate 

30-day 0.2 $209 

Lime Injection 

(88% Control) 

24-hour 0.38 $121 

Plant estimate based 

on cost of lime and 

equipment 

30-day 0.15 $486 

SO2

Lime Injection 

(91% Control) 

24-hour 0.285 $282 

Plant estimate based 

on cost of lime and 

equipment and cost 

of increased outages 

30-day 0.19 $437 

SOFA 

24-hour 0.266 $321 

Confidential Alstom 

Proposal 

30-day 0.15 $905 

SNCR 

24-hour 0.210 $852 

OAQPS Control 

Cost Manual (2002) 

30-day 0.11 $1,942 

SCR 

24-hour 0.154 $1,763 

OAQPS Control 

Cost Manual (2002) 

30-day 0.06 $1,735 

NOx

SCR 

24-hour 0.084 $1,412 

OAQPS Control 

Cost Manual (2002) 

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 

Particulate 

Fabric Filter both 30-day 

and 24-hour 0.010 $21,420 

AWMA utility 

$/KW & OAQPS 

CCM 
8-1 

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(1). 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 SO2 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(1) presents Calpuff modeling results for each Class 

I area in Appendix B. 
8-2 

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

Areas Evaluated and Corresponding Differences Between Control Cases 

Deciview Difference 

Pollutant Control 

Technology 

Emission 

Rate 

(lb/MMBtu/ 

lb/hour) 

Max 98th

Percentile 

Estimate 

(deciviews) Cumulative Incremental 

Base Case 0.76/ 

2720.0 

2.233 0 0 

Lime 

Injection 

(88% 

Control) 

0.38/ 

1360.0 

2.000 0.233 0.233 

Lime 

Injection 

(91% 

Control) 

0.285/ 

1020.0 

1.954 0.279 0.046 

SO2

Fuel 

Switching 

0.445/ 

1592.6 

2.040 

Base Case 0.49/ 

1876.5 

2.233 0 0 

SOFA 0.266/ 

1018.7 

1.811 0.422 0.422 

SNCR 0.210/ 

804.2 

1.672 0.561 0.139 

SCR 0.154/ 

589.8 

1.591 0.642 0.081 

NOx

SCR 0.084/ 

321.6 

1.458 0.775 0.133 

Base Case 0.0525/ 

206.6 

2.233 0 0 

ESP/FF 0.015/ 

59.1 

2.213 0.020 0.020 

Filterable 

Particulate 

ESP/FF 0.010/ 

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 SO2

control alternatives. For the base case and the NOx and PM control alternatives the maximum 98th 

percentile visibility estimates occur at the UL Bend Class I area., 
8-3 

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

Evaluated 

Deciview Difference 

Pollutant Control 

Technology 

Emission Rate 

(lb/MMBtu/ 

lb/hour) 

Max 98th

Percentile 

Estimate 

(deciviews) Cumulative Incremental 

Base Case 0.76 

2720.0 

2.233 0 0 

Lime 

Injection 

(88% 

Control) 

0.38 

1360.0 

1.811 0.422 0.422 

Lime 

Injection 

(91% 

Control) 

0.285 

1020.0 

1.698 0.544 0.122 

SO2

Fuel 

Switching 

1.883 0.350 0.350 

Base Case 0.49 

1876.5 

2.186 0 0 

SOFA 0.266 

1018.7 

1.651 0.535 0.535 

SNCR 0.210 

804.2 

1.509 0.677 0.142 

SCR 0.154 

589.8 

1.394 0.792 0.115 

NOx

SCR 0.084 

321.6 

1.230 0.956 0.164 

Base Case 0.0525 

206.6 

2.186 0 0 

ESP/FF 0.015 

59.1 

2.144 0.042 0.042 

Filterable 

Particulate 

ESP/FF 0.010 

39.4 

2.138 0.048 0.006 

Notes: 

(1) The maximum cumulative and incremental differences for the SO2 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. 
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 – Typical 30-Day Average Emission Rates 

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

Table 9-3: Estimated Visibility and Visibility Improvements 

Estimated Estimated Estimated

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

Option (lb/MMBtu) (deciview s) Present Inc (6) Option (lb/MMBtu)(deciview s) Present Inc (6) Option (lb/MMBtu)(deciview s)Present Inc (6)

Present 0.0525 2.233 n/a n/a Present 0.76 2.233 n/a n/a Present 0.49 2.233 n/a n/a

ESP/FF 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

ESP/FF 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

Fuel SW 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 emission rate is the rate corresponding to the maximum daily emissions during the modeling years (2001-2003).

 (scaled by the expected control efficiency for control alternatives)

 (2) Average emission rates betw een Units 1&2If Unit 1 and Unit 2 emission rates are different, they are indicated as Unit 1/Unit 2 rates.

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

 (4) SO2 emissions reduced by 88%.

 (5) SO2 emission sreduced by 91%.

 (6) Inc = incremental.

 (7) Maximum improvements show n may occur at different Class I areas than the maximum prediction among all Class I areas.

Improvement (7) Improvement (7) Improvement (7)

ESTIMATED VISIBILITY AND VISIBILITY IMPROVEMENTS 

Filterable Particulate Sulfur Dioxide Nitrogen Oxides

9-2 
10-1 

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. 
APPENDIX 1 

EPA REGION 8 COMMENT LETTER 

January 28, 2008







APPENDIX 2 

Detailed Cost Calculation Tables