ES

– 1 EXECUTIVE SUMMARY
On January 28, 2008 EPA Region 8 provided PPL Montana (PPL) with comments on the
Best Available Retrofit Technol ogy (BART) Assessment for Co lstrip 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 res ponds to those comments and pr ovides additional analyses as
needed. The Colstrip power plant, is located in Co lstrip, Montana, is jointly owned by Puget Sound Energy and PPL Montana, LLC and is oper ated by PPL Montana, LLC. Units 1&2 were determined to be BART-eligible under th e 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 es timated costs for the control technologies evaluated based on typical emission rates representa tive of a 30-day averag e. 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 year s (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-sp ecific 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 w ith 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 no rtheast), the Washakie Wilderness Area (278 km to the southwest) and Ye llowstone National Park (281 km to the west). For this addendum, visibility impacts were estima ted 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 we re conducted for this addendum.

• Control costs were based on 15 years for SO 2 and 20 years for NO x , rather than 11 years for both.ES

– 2 • The maximum NO x control level with SCR was evaluated at 0.06 lb/MMBtu. The NSPS level of 0.11 lb/MMBtu was also evalua ted. (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 re liably demonstrated in a retrof it application – in fact the typical control level spec ified in the NSR settlement cases was 0.10 lb/MMBtu.)

• The maximum particulate control level was evaluated at 0.010 lb/MMBtu.

• The NO x control level with SOFA was revised from 0.18 lb/MMBtu to 0.19 lb/MMBtu (typical)

• The NO x control level with SNCR was revise d 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 SO 2 control

– Transferal of energy impacts associated with SO 2 control from Units 3&4 to Units 1&2.

– How SOFA costs at Units 3&4 we re transferred to Units 1&2.

– Additional NO x technologies.

– Venturi scrubber upgrades and operation.

– Cost documentation is provided in several sections of this addendum.
EPA's January 28, 2008 letter questioned whet her 91% (0.15 lb/MMBtu) was appropriate
as the maximum SO 2 control efficiency or whether a high er efficiency was attainable. PPL concluded that 91% was appropriate as an averag e efficiency and that hi gher 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 a nd 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, wa s evaluated in the origin al BART submittal as a potentially more palatable option to reduce SO 2 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 becau se 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 purch ase of an additional scrubber vessel is beyond BART requirements. Summaries of the cost and visibility analys es for all BART control levels evaluated, including the new levels evaluated in this adde ndum, are provided in Tables ES-1, ES-2 and ES3. The cost evaluations in Table ES-1 are base d on typical emissions repr esentative of a 30-day average and the cost evaluations in Tabl e ES-2 are based on ma ximum 24-hour average emissions. The costs are presente d both relative to the present em issions and incrementally from one level of control to the next. The visibility impacts of the present emissions and the controlES

– 3 alternatives based on maximum 24-hour emissions are provided in Table ES-3, both relative to the present emissions and incrementally. The vi sibility 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 Asse ssment for Colstrip Units 1 & 2, that implementation of further c ontrols is not warranted.Table ES-1: Control Costs Summary – Typical 30-Day Average Emission Rates

ES

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

ES

– 5Table ES-3: Estimated Visibili ty 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

– 6i 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 SO 2 EVALUATIONS ...................................................................4-1
4.1 Maximum SO 2 Control Level with Present Equipment ....................................... 4-1 4.2 Evaluation of Coal Cleani ng 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 SO 2 Removal ..............................4-5
5.0 SUPPLEMENTARY NO x EVALUATIONS ..................................................................5-1
5.1 SOFA ................................................................................................................... 5-1 5.2 SNCR ................................................................................................................... 5-2 5.3 SCR NO x Control Level ....................................................................................... 5-4 5.4 Other NO x Control Options ................................................................................. 5-7
6.0 SUPPLEMENTARY PARTICULATE EVALUATIONS ..............................................6-1
6.1 Present Venturi Scrubber Operat ion 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 VI SIBILITY ESTIMATES .........................................................8-1 9.0 SUMMARY .....................................................................................................................9-1
10.0 REFERENCES ..............................................................................................................10-1ii 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 Visibil ity and Visibility Improvements .............................................. ES-6 Table 1-1: EPA January 28, 2008 Comments ........................................................................... 1-3 Table 2-1: Present (Base Case) SO 2 and NO x Emissions ......................................................... 2-3 Table 2-2: Colstrip Base Case Part iculate Emissions, Type and Size Speciation ....................2-4
Table 3-1: CALPUFF Vi sibility Modeling Results from the August 2007 BART Report ......3-2
Table 3-2: Parameters for In terpolation and Extrapolation of Visibility Estimates (Approach 1) ........................................................................................................... 3-3
Table 7-1: Control Co sts Summary and References ................................................................. 7-2
Table 8-1: Maximum Overa ll 98th Percentile Vi sibility Estimates Among All Class 1 Areas Evaluated and Corresponding Diffe rences Between Control Cases .......................8-2
Table 8-2: Maximum 98th Percentile Vi sibility 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 Visibi lity and Visibility Improvements .................................................. 9-2

APPENDICES

APPENDIX 1 EPA REGION 8 COMMENT LETTER
APPENDIX 2 DETAILED COST CALCULATION TABLES1-1 1.0 INTRODUCTION On January 28, 2008 EPA Region 8 provided PPL Montana (PPL) with comments on the
Best Available Retrofit Technol ogy (BART) Assessment for Co lstrip Units 1&2 that PPL submitted in August 8, 2007. This Addendum to that assessment report (1) responds to those comments and provides additional an alyses as needed. EPA's lette r is included as Attachment 1. The Colstrip power plant, located in Colstr ip, 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 th e 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 es timated costs for the control technologies evaluated based on typical emission rates representa tive of a 30-day averag e. 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 th e modeling years (2001, 2002 & 2003). Even though PPL believes that the actua l 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 re presentative of site-specific cost effectiveness, we are providing the 24-hour cost ca lculation as requested. For the initial BART analysis, visibility predictions were made at Class I areas within 300 km of the Colstrip plant w ith 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 no rtheast), the Washakie Wilderness Area (278 km to the southwest) and Ye llowstone National Park (281 km to the west). For this addendum, visibility impacts were estima ted 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 we re conducted for this addendum.

• Control costs were based on 15 years for SO 2 and 20 years for NO x , rather than 11 years for both.

• The maximum NO x control level with SCR was evaluated at 0.06 lb/MMBtu. The NSPS level of 0.11 lb/MMBtu was also evalua ted. (Note that PPL believes that the 0.06 lb/MMBtu control level may not even be appropriate for new sources, and that1-2 level of control has not been re liably demonstrated in a retrof it application – in fact the typical control level spec ified in the NSR settlement cases was 0.10 lb/MMBtu.)

• The maximum particulate control level was evaluated at 0.010 lb/MMBtu.

• The NO x control level with SOFA was revised from 0.18 lb/MMBtu to 0.19 lb/MMBtu (typical)

• The NO x control level with SNCR was revise d 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 SO 2 control

– Transferal of energy impacts associated with SO 2 control from Units 3&4 to Units 1&2.

– How SOFA costs at Units 3&4 we re transferred to Units 1&2.

– Additional NO x technologies.

– Venturi scrubber upgrades and operation.

– Cost documentation is provided is several sections of this addendum.

Table 1-1 summarizes EPA's comments and refe rences the sections of this addendum in which they are addressed.
Section 2 of this addendum describes th e Colstrip plant operation and Units 1&2
emissions. Section 3 describes the methods used to evaluate costs a nd visibility impacts. Sections 4, 5 and 6 desc ribe the supplementary SO 2 , NO x and particulate an alyses 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 Cols trip BART analyses.1-3 Table 1-1: EPA January 28, 2008 Comments Category EPA Comment Section(s) Evaluate the Maximum Control SO 2 Level with Lime injection 4.1

Evaluate the Maximum NO x Control Level with SNCR 5.2 1. Evaluate the Most Stringent Level that the Technology is Capable of Achieving

Evaluate the Maximum NO x 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 SO 2 Control Costs 4.1, 4.2, 7.0 5. Evaluate Fuel Switching and Coal Cleaning Options for SO 2 Control 4.2, Attachment 2 6. Explain How Energy Impacts from Units 3&4 Were Translated to Units 1&2 4.1 SO 2 Comments

7. Provide an Analysis of Venturi Scrubber Upgrades for SO 2 Control 4.3 8. Use a 20 Year Remaining Life for NO x Control Costs 5.1, 5.2, 5.3, 7.0 9. Provide a NO x 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 NO x Comments

11. Evaluate Additional NO x 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 6.22.0 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 Ba sin 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 commercia l operation in 1984 and 1986 and are not BART eligible.
Units 1&2 are rated at 333 MW each. The fu rnaces are of tangential-fired design with a
Low NO x Concentric Firing (LNCFS) P2 system w ith close coupled overfire air (CCOFA). Originally, the units operated with a NO x 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, th e units operate with a NO x 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 NO x limit. The units have a wet particulate scrubber that controls both particulate and SO 2 emissions. The design of the wet scrubber include s a venturi/plumb bob s ection with sprays to remove particulate and SO 2 , followed by a level of absorp tion sprays for additional SO 2 removal, followed by a wash tray section for both particulate and SO 2 polishing, followed by mist
eliminators. The scrubbers utilize the alkalin ity of the fly ash collected to remove the SO 2 . The scrubbers are designed to have at leas t a 98% particulate c ontrol efficiency and operation of the equipment has shown particulate control efficiencies ap proaching 99.5%. They
achieve a 75% to 80% SO 2 removal (depending on the alkalinity of the ash). The scrubbers are designed to treat 100% of the flue gas and th ere are no provisions for bypassing the scrubbers. There are 3 scrubber vessels per unit and all 3 vessel s are required to be in operation for full load
on the unit.

2.2 Emissions The present (base case) sulfur dioxide (SO 2 ) and nitrogen oxides (NO x ) emissions for Colstrip Units 1&2 are presented in Table 2- 1. Presented are both the typical emissions representative of a 30-day aver age and the maximum daily emissions during the modeling years (2001, 2002 & 2003). The emissions ar e based on certified CEM data.

2-1For this addendum, both the typical and maximum SO 2 and NO x 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 t hose modeling results here is also based on the maximum daily emissions. The base case particulate emissions are presen ted in Table 2-2. They are presented in their filterable and condensable portions and fu rther divided into organic and inorganic (H 2 SO 4 ) condensable fractions and coarse, soil and elem ental 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 co arse, soil and elementa l 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 averag e during the modeling years). Speciation into organic and inorganic fractions is ba sed 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 th e 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, th e 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.

2-2Table 2-1: Present (Base Case) SO 2 and NO x 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 SO 2

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 NO x

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.

2-3Table 2-2: Colstrip Base Case Particulate Emissions, Type and Size Speciation Category Unit 1 Unit 2 lb/hr 338.4 374.1 Total PM 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 lb/hr 53.47 64.58 Coarse (3)
lb/MMBtu 0.0134 0.0166 lb/hr 128.73 155.48 Soil (3)
lb/MMBtu 0.0323 0.0399 lb/hr 4.95 5.97 Elemental 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 lb/hr 30.26 29.62 Organic (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 partic ulate emissions between the two units are 0.0525 lb/MMBtu and 206.6 lb/hr.

2-43.0 EVALUATION METHODOLOGY
3.1 Cost Analyses The control cost determinations were perf ormed 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. Emi ssions associated with both of these averaging periods were also used for each of the control le vels evaluated. For capital cost amortizations, a 7 percent per annum interest rate and a 15 year life for SO 2 controls and a 20 year life for NO x controls were assumed. Where costing referen ces are based on referenced dollar values, the
costs were corrected to 2008 dolla rs using cost index calculations. For the determination of capital and operatin g costs for the PPL BART analysis of control alternatives, bo th vendor cost estimates and calculated costs were used. The SO 2 reductions include two levels of we t scrubbing by lime injection. For NO x reductions, both combustion controls within the furnaces, and the add-on controls of Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reducti on (SCR) were evaluated. Alstom Power Inc. provided a cost proposal for in-combustion NO x controls that has been included in the option costing analyses. The guaranteed performance fo r the technology considered the older design of the Colstrip Unit 1&2 boilers with high heat rele ase rates for the Powder River Basin (PRB) coal
utilized. For SNCR and SCR control options, Section 4.2, “NO x Post combustion” controls Chapter 1 “Selective Noncatalytic Reduction”, a nd 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 altern ate 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 Cols trip 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 Absaro ka 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

3-1control options identified in PPL's BART repor t 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 SO 2

New Vessel (91%) 0.15 1.832 Base Case 0.49 2.233

SOFA 0.25 1.781 SNCR 0.225 1.713 NO x

SCR 0.15 1.584 Base Case 0.0525 2.233 PM 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 SO 2 and NO x 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/extra polated values presented here are based on maximum 24-hour emissions per recommendations in the BART guidelines. The change in visibility improvement (in de civiews) per change in emission rate (in lb/MMBtu) between each of the modeled control leve ls (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.

3-2Table 3-2: Parameters for Interpolatio n 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 SO 2

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 NO x

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 ra te 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 previous ly, 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 immedi ately preceding the lowest emission rate evaluated to the lowest emission rate evaluated.

3-3As can be seen in the Table 3-2, the deciview (dv) change per lb/MMBtu change varies
for the different contro l level intervals. The interpolated visibility improvement in de civiews for the new cont rol levels evaluated in this addendum will be calculated by th e standard formula of a straight line,

That is: y = m x + b, where
y = the visibility for the ne w emission rate being evaluated. m = the slope (dv change per emission rate cha nge) for the selected interval as described above. x = the emission rate difference between the new emission rate and th e emission rate at the upper end of the selected interval (negative) b = the visibility level at th e upper end of the se lected 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 extrapol ation was conducted using the deciview and deciview per lb/MMBtu values presented in Table 3-2 that are based on the maximum 98 th 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 98 th percentile predictions for
the base case and control alternatives from am ong all Class I areas evaluated. This approach generally provided larger deciview diffe rences than the other approach. The visibility estimates and cumulative a nd incremental differences are presented for both approaches in Section 8 and the higher leve ls of visibility improvement between the two approaches are used in the discussions a nd summary tables of this addendum. The deciview per lb/MMBtu values for th e 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 98 th percentile modeled

3-4visibility levels for each Class I area from whic h the interpolation/extra polation values are based are presented Appendix B of the originally submitted BART report (1)

.

3-54.0 SUPPLEMENTARY SO 2 EVALUATIONS
4.1 Maximum SO 2 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 eval uated for units that already have better than 50% reduction SO2 controls, PPL evaluated this optio n nonetheless. Based on the perf ormance of the Colstrip Units 3&4 wet scrubbers, which are similar to the Cols trip 1&2 wet scrubbers, once lime is added to the 1&2 scrubbers PPL would expect the SO 2 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 maintena nce that is needed due to the scaling caused by the additional lime. Without the spare vessel , the unit must be sh ut 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 SO 2 emission level below 0.15 on a consistent basis. This emission level represents an SO 2 emissions
reduction of 91%. PPL believes that 91% is appropriate reduc tion level to evaluate as a maximum average control level with present equipment. Higher efficiencies would not be
attainable on a continual basis due to th e 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 SO 2 emissions to the presumptive level of 0.15 lb/MMBtu (by having a spar e 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 effici ency 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 conducte d for the maximum controlled emissions level of 0.15 lb/MMBtu (91% control) for typical/ave rage 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 m inor adverse plant impacts from scrubber downtime, increas ed scaling, and additional disposal costs.

4-1However, 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 associat ed 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 fo r 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 im proved by the addition of lime to the scrubber liquid. Based upon PPL experience for Units 3&4, th e 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 ava ilable at 7% per annum, appendix Table 4.1-1
shows a cost effectiven ess of $209/ton of SO 2 controlled based on a 30-day average SO 2 emission rate of 0.40 lbs/MMBtu. While this re presents a 50% reduction of the 30-day average “uncontrolled” emissions, this level of contro l actually represents an 88% estimated control efficiency over the uncontrolled emission rate ba sed 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 ra te, the cost effectiveness is $121/ton. Both of these cases are presen ted 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 outag es for descaling, and additional lime consumption, an additional absorption pump and sprays are requir ed. These additional costs for the pump and sprays is an additi onal $3,000,000 as well as an estimate of the costs associated with the added descaling time are listed in Appendix 2, Tabl es 4.1-3 and 4.1-4 for 30- day and 24-hour average emission rate bases resp ectively. The amortizati on 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

4-2The maximum improvement of 98 th percentile visibility estimates at any of the Class I
areas evaluated for an SO 2 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. Thes e values are based on
maximum 24-hour emission rates.

4.2 Evaluation of Coal Cleani ng 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 proc essing procedures conducte d 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 remove d from coal through a cleaning proc ess, the pyritic sulfur is the form that is removed. A general rule of thum b estimates that about 35% to 55% of the pyritic
sulfur can be removed when coal is ‘washed’. Th e other forms of sulfur pr esent in coal, sulfates and organic sulfur, are not removed through coal washing. Although pyritic sulfur often makes up a significant percentage of th e total sulfur in bituminous co als, 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 re liable 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 proc ess called K-Fuel. Th is uses a process to
lower the moisture content in PRB coal. K-Fuel also claims to reduce SO 2 and NO x 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 indi cates that it may be beneficial to plants burning eastern bituminous coals, but it has not been demonstrated as a beneficial process for lowering SO 2 or NO x at plants like Colstrip that burn sub-bituminous coal.

4-34.2.2 Fuel Switching The Colstrip Plant burns mine mouth Rose bud sub-bituminous northern PRB coal with a sulfur content of approximately 0.7 %. The coal is conveyed from th e mine to the plant. There is presently no outside fuel handling capability at the plant. A fuel switching alternative was evaluate d based on the assumption that burning 0.3% sulfur coal would be a possibili ty if necessary plant upgrades were performed. PPL is concerned that coal transported to the plant may have a lo wer alkalinity than the present coal being burned and therefore lime injection would be required to maintain the SO 2 removal rate presently attained with the venturi scrubbers. Lime inj ection 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 vess el if lime injection were required to
maintain the same SO 2 removal efficiency as is presentl y attained by the alkalinity of the Rosebud coal. The lime injection w ould present a scaling concern and more vessel down time for de-scaling.

A description of the cost anal ysis conducted is provided in Confidential Attachment 2. The overall cost is estimated at $10,258/ton base d on typical, 30-day average emission rates and $5,943/ton based on maximum 24-hour emission rates. These costs are ba sed on transportation
costs and construction of an unloading facility only. Boiler upgrades and purchase of an
additional scrubber vessel ar e additional concerns but because of their present uncertainty are not
included in the cost estimate. Detailed cost es timates are provided in C onfidential Attachment 2,
Tables 4.2-1 and 4.2-2.

4-4The maximum improvement of 98 th percentile visibility estimates at any of the Class I
areas evaluated for an SO 2 emissions reduction by reducing the fu el sulfur content from 0.7% to
0.3% is 0.350 deciviews. This is ba sed on maximum 24-hour emission rates

4.3 Evaluation of Venturi Scrubber Upgrades for SO 2 Removal PPL has evaluated upgrades to the wet sc rubbers in terms of both improving design removal efficiency and improvi ng O&M practices to improve re liability. 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 tr eating the full flue gas flow. With this design, the improvement of scru bber system reliability or reduction of downtime has no effect on reducing emissions. All flue ga s leaving the furnace is being treated 100% of
the time. Operational improvements by adjusting scr ubber chemistry were evaluated by adding
lime to enhance SO 2 removal efficiency. In addition, auxiliary equipmen t redundancy was evaluated by adding another set of abso rption pumps and sprays to improve SO 2 removal efficiency. These improvements are included in the analysis to attain a maximum SO 2 removal of 91% (Subsection 4.1). Other common scrubber upgrades and th eir status are reviewed below.

• Elimination of Bypass Reheat . The Colstrip Units do not have the capability of bypass reheat, so essentially this upgrade is al ready included in the scrubber design.

• Installation of Liqui d Distribution Rings . This upgrade is consid ered in the evaluation to achieve 91% SO 2 removal efficiency.

• Installation of Perforated Trays . This upgrade is already pa rt 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 effec tiveness of the limestone. But, the current Colstrip scrubbers do not use limestone, they rely on the al kalinity of the fly ash to achieve current SO 2 removal rates of 75% to 80%. PPL does not believe addition of acid to the existing scrubbers will improve re moval efficiency currently achieved. A review of acid additives indicates that th ey 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 additi ves are helpful for limestone scrubbers, but not lime scrubbers. As discussed in Subs ection 4.2, PPL has evaluated the addition of lime to the scrubbers to improve SO 2 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 chemis try and auxiliary equipment redundancy.

• Redesign Spray Header or Nozzle Configuration . This upgrade is considered in the evaluation resulting in 91% SO 2 removal efficiency.

4-65-1 5.0 SUPPLEMENTARY NO x EVALUATIONS
5.1 SOFA Units 1&2 at Colstrip are currently operated with Close Coupled Overfire Air combustion technology to reduce NO x emissions. PPL has investigated upgrading the NO x control by installation of Separated Overfire Air (SOFA) and has obtained a proposal from Alstom Power Inc for their proprietary LNC FS Level III w/SOFA system. The proposal contains a NO x 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, th e 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 e xperience from Units 3&4 to Units 1&2.
Alstom has had the LNCFS Level III w/SO FA system perform better than 0.19 lb/MMBtu at other Units, but th ere are unique issues with the Colstrip 1&2 furnace that have them put the performance guarantee at th is 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 NO x formation when compared to other Units.

• Coal type . Colstrip coal has more sodium whic h results in more fouling and slagging issues in the furnace. This reduces the effective furnace size which makes the furnace hotter, resulting in more NO x formation. Furthermore, Co lstrip 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 devolatila zation and earlier combusti on in the absence of O 2 , resulting in less NO x formation.

• Experience on Colstrip Unit 3 . PPL's experience with th e LNCFS Level III w/SOFA system on Colstrip Unit 3, which has a larg er furnace and better "heat input to furnace area ratio" and longer "sub-st oichiometric residence time " than Colstrip Units 1&2, shows a 0.17 lb NO x /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 incl udes costs of the air flow and coal measurement equipment required to operate the new Level III sy stem. Tables 5.1-1 and 5.1-2 present the cost5-2 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 maxi mum 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 NO x control efficiency that would be obtained with the SOFA. Both ta bles assume a constant percent
NO x reduction from the baseline 30-day or 24-hour NO x 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 Confid ential Attachment 1.

Visibility Evaluation The maximum improvement of 98 th percentile visibility estimates at any of the Class I
areas evaluated for a NO x 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 NO x reduction of 20% beyond the SOFA emission rate could be obtained. This would result in a NO x 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% re duction by installing an SN CR 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 bu rned. Alstom has done extensive evaluation of SOFA on Units 1&2, but not SNCR. This 20% re duction with SNCR is PPL's best estimate at
this time. SNCR is a technology which injects an ammo nia based reagent into the post combustion
zones of a boiler where NO x reacts with the reagent to chemi cally reduce NO (the major oxide of nitrogen in NO x ) to nitrogen and water. Either urea or an ammonia-water solution are the typical sources of reducing agent. The analysis presente d herein is based on the discussions included in the EPA Control Cost Manual (the CCM) from January 2002. The relatively simple process of injecti ng 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 boile r fire box to locate the optimal injection5-3 points for injection. With regard to the applic ation of SNCR to existi ng 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. Th erefore, 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 te chnical 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 specifi es 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 ac ronym for the Normalized Stoichiometric
Ratio which is the ratio of the moles of a mmonia equivalent injected to the amount of
uncontrolled NO x . For this study level analysis, it is a ssumed that the CCM costing techniques for the necessary boiler modificatio ns 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 NO x by an additional 20% over that attained by the modifi cations 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 furn ace temperatures higher than in newer units initially designed for low NO x emissions. Furthermore, the lowered NO x 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 cal culation 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 tec hniques, a cost effectiveness of $905 per ton of5-4 NO x 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 differen ce 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 98 th percentile visibility estimates at any of the Class I
areas evaluated for a NO x emissions reduction from the base case maximum 24-hour emissions
level to the emissions level with SNCR is 0.667 d eciviews. The maximum incremental visibility improvement from the SOFA control level to th e SNCR control level is 0.142 deciviews. These
are based on maximum 24-hour emission rates

5.3 SCR NO x Control Level
The lowest NO x emission rate evaluated for Colstrip Units 1&2 is 0.06 lb/MMBtu through application of SCR post-co mbustion controls. It is be ing evaluated as a suggested control level by EPA Region 8. PPL is not sure that the ma ximum SCR control level of 0.06
lb/MMBtu is achievable from a retrofit technol ogy on a continuous basis at Colstrip Units 1&2.
PPL believes that the 0.06 lb/MMBtu control leve l 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 e ngineering study of Cols trip Units 1&2 would be required to accurately asce rtain what performance level SCR could achieve at Colstrip Units
1&2. A Selective Catalytic Reducti on (SCR) add-on control device employs a highly porous honeycomb type catalyst bed impregnated with catal ytic metals or metal oxides. Upstream of the catalyst bed, the ammonia based reagent is in timately mixed with the flue gas, the reagent,
and NO x , which contacts the reactive surface of the honeycomb and reacts to form N 2 and H 2 O
and continues to the exhaust stack afte r significant reductions in uncontrolled NO x concentrations. SCR differs from SNCR in that the catalyst allows the reduction reactions to5-5 occur at lower temperatures than must be utiliz ed in the SNCR process which relies on the higher temperature portions of the boiler and economi zer to foster the reduction reactions. The description provided herein is based on the EPA Control Cost Manual, Section 4.2
“NO x Post-Combustion”. This reference provides de scriptions of three possible locations for the
SCR module as well as detailed co st estimation procedures for es timation of the SCR system and ancillary equipment. Installation of the SCR mo dule may be upstream of the particulate control device in what is termed the “high dust SCR loca tion”. Such installations typically require lower quantities of catalysts, however, the beds are subj ect 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 cool ed to such an extent that reheating of the exhaust to the minimum SCR ope rating temperature is required.
From the EPA Control Cost Ma nual, Section 4.2, page 2-30:

“SCR system design is a proprietary technol ogy. Extensive details of the theory and correlations that can be used to estimate design parameters such as the required catalyst volume are not publis hed in the technical literature. Furthermore, the design is highly site-speci fic. In light of these complexities, SCR system design is generally undertaken by providing all of the plant and boiler specific data to the SCR sy stem 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 NO x Control on Coal-Fired Boilers. 3 This procedure assumes SCR system size and cost are based on three main param eters: the boiler size or heat input, the required level of NO x 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 pa ges 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 ta ken directly from the Control Cost Manual.
The cost estimations are based on reduction of the base NO x level of 0.35 lbs/MMBtu, 30-day5-6 rolling average, to 0.11 lbs/MMBtu, 30-day roll ing average as well as to 0.06 lbs/MMBtu, 30- day rolling average. Two sets of cost analyses were performed for each averaging tim e. The first set of results
was based on an uncontrolled emission rate equal to the 30-day average NO x 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 pres ented, 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 operati ons for the entire year. The 0.06 lbs/MMBtu (30- day average) value also may be unrealistic because the already low uncontrolled NO x emissions with the existing LNCFS II burne r technology, and the old hot furnace desi gn 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 increm ental cost effectiveness of SCR as compared
to SNCR.

Visibility Evaluation Visibility improvement was estimated for bot h 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 corres pond 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 98 th percentile visibility estim ates among all Class I areas evaluated corresponding to NO x emissions reductions from the ba se case to the two SCR control
levels are 0.792 and 0.956 deciviews. The maxi mum incremental visibility improvements from5-7 the SNCR control level to the less controlled SCR control level (i.e., 0.154 lb/MMBtu which corresponds to 0.11 lb/MMBtu typica l) is 0.115 deciviews. The ma ximum incremental visibility improvements from the less controlled SCR leve l to the more controlled SCR level is 0.164
deciviews. These are based on maximum 24-hour emission rates

5.4 Other NO x Control Options The BART guidelines state that all possible control techno logies do not need to be
evaluated. PPL feels that the most appropriate NO x 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 br iefly discussed below.

Advanced Separated Overfire Air (ASOFA) The design of the SOFA syst em (evaluated in Subsection 5.1) with individual sets of control dampers by corner and nozzle control bot h vertically and horizontally (see Alstom proposal) in coordination with th e 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 NO x 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 th e upper portion of the furnace. ROFA uses a rotating overfire air process wh ereas Alstom's system uses bot h horizontal (yaw) and vertical nozzle tip controls. PPL's review of data indicates that ROFA w ill 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 RO FA, and they indicated that NO x 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 Alst om's system on Colstrip Unit 3. Additionally, PPL's review of lowest NO x emitting units across the country showed significantly more Alstom system s than ROFA. As EPA has st ated in its July 2005 BART guidance: A possible outcome of the BART procedures discussed in these guidelines is the evaluation of multiple control technology alterna tives which result in essentially equivalent5-8 emissions. It is not our intent to encourage evaluation of unnece ssarily 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, co nsidering the uncertainties of emissions factors and other parameters pertinent to estimating perf ormance, you may evaluate only the less costly of these options. In PPL’s judgment, pursuant to the foregoing guidance, a furt her evaluation of ROFA is not necessary.

Rich Reagent Injection (RRI) PPL took the same approach regarding RRI. PP L's review of RRI i ndicates it is similar
to SNCR and achieves similar results. The resu lts reviewed were on cyclone units which are different than the tangential fire d furnaces at Colstrip 1&2. The review indicated that RRI was
used in combination with overfire air and SNCR to achieve NO x 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 SN CR, RRI was not evaluated any further.6-1 6.0 SUPPLEMENTARY PARTICULATE EVALUATIONS
6.1 Present Venturi Scrubber Operat ion 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 scrubbe rs utilize a venturi/p lumb bob section that causes a high pressure drop (delta P) at this lo cation 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 operat e with a plumb bob delta P of 17 inches wg. Increasing this delt a P may improve particulate remova l, but our experience indicates that improvement would be less th an 10%. Increasing delta P would result in more times of load limitations due to ID Fan air flow limits. Typi cally 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 indica tes this improvement would be le ss than 5%. Additional testing would have to be performed to quantify any im provements 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 usi ng other post combustion equipment. In view of the average present filt erable 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 co ntrols applied to the current average emission rate to reduce this value to 0.010 lbs/MMBtu. No a dditional 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 filt erable 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 methodologi es for ESPs and FFs are appropriate for moderately sized units to a few hundred thousand ACFM. To estimate the cost of utility sized6-2 units, the capital cost of th e ESP was estimated at $60/kW and that of a FF at $50/kW. 4 Using the equipment cost as typical for coal-fired util ity 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 Colstr ip 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% cont rol 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 assumpti on 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 c hosen, 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 98 th percentile visibility estim ates among all Class I areas evaluated for a filterable part iculate emission reduction from th e base case level of 0.0525
lb/MMBtu to 0.015 lb/MMBtu is 0.042 deviviews a nd 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 ar e also provided in the re spective sections of the
addendum and in the cost tables. The tables it emizing the costs (cost tables) are provided in Appendix 2. For NO x control with SOFA, the cost ta bles 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

30-day 0.23 $10,258 Fuel Switching

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 SO 2

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 NO x

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 CCM8-1 8.0 SUMMARY OF ALL VISIBILITY ESTIMATES Visibility estimates are based on Calpu ff 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, visibili ty estimates are base d 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 ra tes. The deciview values are presented as
98 th percentile levels. Table 8-1 presents the maximum deciview le vels 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 whic h the control is being a pplied. Table 8-1 also presents the cumulative visibility improvement fro m the base case to each control alternative and the incremental improvement from the immediately preceding contro l alternative in terms of the level of emissions reduction attained. An exception is that the SO 2 coal switching alterative was
not included in the incremental calculations for eith er of the lime injection control alternatives.
The cumulative and incremental differences in Table 8-1 are based on th e differences between the maximum 98th percentile deciview estimates among all Class I areas. Table 8-2 presents the same informati on as Table 8-1 except that the maximum
differences between visibility estimates for the base ca se 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 modeli ng results for each Class I area in Appendix B.8-2 Table 8-1: Maximum Overall 98th Percenti le 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 98 th 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 SO 2

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 NO x

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 th e Theodore Roosevelt NP Class I area for the SO 2 control alternatives. For the base case and the NO x 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 Visi bility Differences Among All Class I Areas Evaluated

Deciview Difference Pollutant Control Technology Emission Rate (lb/MMBtu/

lb/hour) Max 98 th 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 SO 2

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 NO x

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 SO 2 cases occur at the ULBend Class I area. (2) The maximum cumulative and incremental differences for the NO x and PM cases occur at the Theodore Roosevelt NP Class I area. (3) Maximum 98th percentile base case levels are pr esented per pollutant for the Class I area for which the differences between control a lternatives and the base case were the maximum.9.0 SUMMARY
The results of the cost and vi sibility 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 maximu m 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 98 th 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

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

Table 9-3: Estimated Visibi lity 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

9-210-1 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 NO x Control on Coal-fired Boilers, Draft Report, prepared for the U.S. Environmental Prot ection Agency by the Cadmus Group, Inc., Bechtel Power Corporation, and Science App lications International Corporation, May 1998

4. AWMA, Air Pollution Engineering Manual, Air & Waste Management Association, Anthony J. Buonicore and Wayne T. Da vis, eds., Van Nostrand Reinhold, 1992.

# APPENDIX 1
EPA REGION 8 COMMENT LETTER

January 28, 2008

# APPENDIX 2
Detailed Cost Calculation Tables