# Otter Tail Power Company Big Stone Generating Station Unit 1

Best Available Retrofit Technology Analysis

November 2, 2009
Project 53777

### i 11/2/2009 Otter Tail Power Company Big Stone Plant Unit I Best Available Retrof it Technology Analysis

Table of Contents

LIST OF TABLES ...........................................................................................................iii

EXECUTIVE SUMMARY ........................................................................................ES-1

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

### 1.1 BACKGROUND ................................................................................................ 2 1.2 BART ANALYSIS PARAMETERS.................................................................. 3 1.3 APPROACH ....................................................................................................... 5 1.3.1 IDENTIFICATION OF RETROF IT CONTROL TECHNOLOGIES............... 6 1.3.2 FEASIBILITY ANALYSIS................................................................................ 6 1.3.3 EVALUATE TECHNICALLY FEASIBLE CONTROL OPTIONS BY EFFECTIVENESS.............................................................................................. 6 1.3.4 IMPACT ANALYSIS......................................................................................... 6 1.3.5 METHODOLOGY FOR ESTIMATED COSTS................................................ 7 1.3.6 METHODOLOGY FOR VISIBILITY IMPACTS DETERMINATION .......... 9 1.3.7 ADDITIONAL APPROACH METHODS....................................................... 10 1.4 THE ROLE OF MODELING AND CALP UFF IN A BART ANALYSIS ..... 10 1.4.1 CALPUFF MODELING METHODOLOGY................................................... 11 1.4.2 MODELING SCENARIOS.............................................................................. 11 2.0 NO X BART EVALUATION ..........................................................................................13 

### 2.0.1 BART GUIDELINE NO X 

### LIMITS FOR CYCLONE-FIRED BOILERS ....... 13 2.1 IDENTIFICATION OF RETROFIT NO X 

### CONTROL TECHNOLOGIES .... 13 2.2 TECHNICAL DESCRIPTIONS AND FEASIBILITY ANALYSIS OF NO X 

### CONTROL TECHNOLOGIES ........................................................................................ 14 2.2.1 FEASIBILITY OF COMBUSTION NO X 

### CONTROLS.................................. 14 2.2.2 FEASIBILITY OF POST-COMBUSTION NO X 

### CONTROLS....................... 15 2.2.3 RESULTS OF FEASIBILITY ANALYSIS ............................................................ 16 2.3 CONTROL EFFECTIVENE SS EVALUATION OF NO X 

### CONTROL TECHNOLOGIES ............................................................................................................ 16 2.4 EVALUATION OF IMPACTS FOR FEASIBLE NO X 

### CONTROLS............. 18 2.4.1 COST IMPACTS OF NO X 

### CONTROLS ......................................................... 18 2.4.2 ENERGY IMPACTS OF NO X 

### CONTROL ALTERNATIVES ...................... 25 2.4.3 NON AIR QUALITY AND OTHER E NVIRONMENTAL IMPACTS OF NO X 

### CONTROL ALTERNATIVES......................................................................... 27 2.4.4 VISIBILITY IMPAIRMENT IMPACTS OF NO X 

### CONTROLS .................... 28 2.4.5 SUMMARY OF IMPACTS OF NO X 

### CONTROLS – BSP UNIT I ................ 30 3.0 SO 2 BART EVALUATION............................................................................................32 

### 3.0.1 BART GUIDELINE SO 2 

### LIMITS FOR CYCLONE-FIRED BOILERS ........ 32

### ii 11/2/2009 3.1 IDENTIFICATION OF RETROFIT SO 2 

### CONTROL TECHNOLOGIES ..... 32 3.2 TECHNICAL DESCRIPTION AN D FEASIBLITY ANALYSIS .................. 33 3.2.1 PRE-COMBUSTION FUEL TREATM ENTS - FUEL SWITCHING ............ 33 3.2.2 POST-COMBUSTION FLUE GAS DESULFURIZATION ........................... 33 3.2.3 RESULTS OF FEASIBILITY ANALYSIS ..................................................... 34 3.3 EVALUATE TECHNICALLY FEASIBILE SO 2 

### CONTROL OPTIONS BY EFFECTIVENESS............................................................................................................ 35 3.4 EVALUATION OF IMPACTS FOR FEASIBLE SO 2 

### CONTROLS .............. 36 3.4.1 COST ESTIMATES ......................................................................................... 36 3.4.2 ENERGY IMPACTS........................................................................................ 43 3.4.3 NON-AIR QUALITY ENVIRONMENTAL IMPACTS................................. 43 3.4.4 VISIBILITY IMPACTS ................................................................................... 44 3.4.5 IMPACT SUMMARY...................................................................................... 45 4.0 PARTICULATE MATTER BART EVALUATION...................................................46 

### 4.1 IDENTIFICATION OF AVAILABL E RETROFIT PM CONTROL TECHNOLOGIES ............................................................................................................ 46 4.2 TECHNICAL DESCRIPTION AN D FEASIBLITY ANALYSIS .................. 47 4.2.1 FABRIC FILTER (FF) ..................................................................................... 47 4.2.2 COHPAC .......................................................................................................... 47 4.2.3 ELECTROSTATIC PRECIPITATOR (ESP)................................................... 48 4.3 RANK OF TECHNICALLY FEAS IBLE PM CONTROL OPTIONS BY EFFECTIVENESS............................................................................................................ 48 4.4 EVALUATION OF IMPACTS FOR FEAS IBLE PM CONTROLS – UNIT I49 4.4.1 VISIBILITY IMPACTS ................................................................................... 49 5.0 BART RECOMMENDATIONS....................................................................................49 

### 5.1 NO X 

### BART ....................................................................................................... 50 5.2 SO 2 

### BART ........................................................................................................ 50 5.3 PM BART ......................................................................................................... 51 5.4 COMBINED BART.......................................................................................... 52
Appendix A Technical Feasibility Assessment Details for NO X Controls (A1) Summary of CUECost Inputs (A2) Summary of Modeling Results (A3)
Appendix B Technical Description of SO 2 Controls (B1)
Appendix C Technical Description of Particulate Matter Controls (C1)
Appendix D Visibility Modeling and Impairment Improvement Analysis Details (D1)

### iii 11/2/2009 List of Tables
1.2-1 – Unit Design and Operating Parameters 1.2-2 – Coal Parameters 1.2-3 – Economic Factors 1.4-1 – Big Stone Plant Modeling Scenarios

2.1-1 – Potentially Available NO X Control Alternatives Identified for BART Analysis 2.2-1 – NO X BART Feasibility Analysis Results 2.3-1 – Evaluated NO X Control Technologies 2.3-2 – Estimated Control Options NO X Emission Rates Evaluated 2.4-1 – Unit Capital Cost Factors of Feasible NO X Control Options 2.4-2 – Estimated O&M Costs for NO X Control Options 2.4-3 – Capital and Annualized Costs Estimated for NO X Control Alternatives 2.4-4 – Estimated Annual Emissions and LTAC for NO X Control Alternatives 2.4-5 – Estimated Incremental Annual Emissions and LTAC for NO X Control Alternatives 2.4-6 – Visibility Impairment Impacts from Emission Controls 2.4-7 – Cost for Incremental Visibility Improvement 2.4-8 – Impacts Summary for BSP Unit I NO X Controls

3.1-1 – SO 2 Control Technologies Identified for BART Analysis 3.2-1 – SO 2 BART Feasibility Analysis Results 3.3-1 – SO 2 Control Technologies Identified for BART Analysis 3.4-1 – First Year O&M Cost Estimate for BSP FGD Systems 3.4-2 – Capital and Annualized Costs Estimated for SO 2 Control Alternatives 3.4-3 – Estimated Annual Emissions and LTAC for SO 2 Control Alternatives 3.4-4 – Estimated Incremental Annual Emissions and LTAC for SO 2 Control Alternatives 3.4-5 – Energy Requirements of SO 2 BART Alternatives 3.4-6 – Visibility Impairment Impacts from Emission Controls 3.4-7 – Cost for Incremental Visibility Improvement 3.4-8 – Impacts Summary for BSP Unit I SO 2 Controls

4.1-1 – PM Control Technologies Identified for BART Analysis 4.2-1 – PM BART Feasibility Analysis Results

5.4-1 – Visibility Impairment Impacts from Combined Emissions

### ES-1 11/2/2009 EXECUTIVE SUMMARY

The U.S. Environmental Protection Agency (EPA ) finalized the Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (B ART) Determinations in 2005 (40 CFR 51, Subpart P; 40 CFR 51, App. Y). BART is defined as “an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant which is emitted by a BART-eligible source. The emission limitation must be established, on a case-bycase basis, taking into consideration the technology av ailable, the costs of compliance, the energy and non-air quality environmental impacts of compliance, any pollution control equipment in use at the source, the remaining useful life of the source, a nd the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology” (40 CFR 51.301). This document presents the BART analysis for each of three major pollutants (nitrogen oxides (NO X ), sulfur dioxide (SO 2 ), and particulate matter (PM)) for Otter Tail Power Company’s (OTPC’s) Big Stone Plant (BSP) Unit I located near Big Stone City, South Dakota. Otter Tail Power Company is operating agent for the Big Stone Plant co-owners: NorthWestern Energy, Montana-Dakota Utilities, Co., a division of MDU Resources Group, and Otter Tail Power Company.

BSP is a steam electric generating plant with one ge nerating unit burning Powder River Basin coal and a net electrical output of 475 MW. Particulate contro l for Unit I is provided by a conventional pulse-jet fabric filter installed in 2007. Nitrogen oxides (NO x ) emissions from the unit are controlled with an overfire air system (OFA). The unit does not have contro ls for sulfur dioxide emissions other than firing lowsulfur Powder River Basin coal. Unit I began operati on in 1975 and is presumed to be subject to the requirements for BART analysis under the Regional Haze Rule absent a formal determination to the contrary from the DENR.

The BART analysis steps 1 through 5 for NO X , SO 2 and PM emissions from BSP are described in this report. Potentially applicable control technologies are first identified. A brief description of the processes and their capabilities are then reviewed for availability and feasibility. Subsequently, those available technologies deemed feasible for retrofit ap plication are ranked according to control capability. The impacts analysis then reviews the estimated ca pital and O&M costs for each alternative, the energy impacts and non-air quality impacts. The impact base d on the remaining useful life of the source is reviewed as part of the cost analysis. In the final step of the analysis, feasible and available technologies are assessed for their potential visibility impairment impact reduction capability via visibility modeling results. The results of the impact analyses are tabulat ed and potential BART control options are listed.

### ES-2 11/2/2009 The final result of this analysis is a recommendati on of the Best Available Retrofit Technology (BART) based upon the detailed analysis conducted in this report. For NO X , five control alternatives were identified and evaluated using the 5 steps. Over-fire air (OFA), separated over-fire air (SOFA), Selective Non-Catalytic Reduction (SNCR) with SOFA and Selective Catalytic Reduction (SCR) with SOFA were the technologies that remained after completing step s 1 though 4 of the analysis. To reduce visibility impacts due to NO X emissions below a discernable level of 0.5 dV, SOFA is recommended as BART for BSP Unit I. Application of SOFA for NO X control translates into a BART emission rate of 2,804 pounds per hour.

For SO 2 , three control alternatives were identified and evaluated using the 5 steps. Wet FGD and semidry FGD at two levels of control were selected for visibility impacts evaluation after completing steps 1 though 4 of the analysis. To reduce visibility impacts due to SO 2 emissions below a discernable level of 0.5 dV, semi-dry FGD is recommended as BART for B SP Unit I. Application of semi-dry FGD for SO 2 control translates into a BART emission rate of 505 pounds per hour.

For the PM evaluation, three post combustion control technologies were selected for evaluation in addition to the existing pulse-jet fabr ic filter. BSP Unit I currently uses a pulse-jet fabric filter (installed in 2007) that is the best technology available for pa rticulate control, the impact review was abbreviated and maintaining the existing pulse-jet fabric filte r is recommended as BART for BSP Unit I. The corresponding BART emission rate for the exis ting fabric filter is 84.1 pounds per hour

Modeling to determine visibility impairment was performed using the recommended BSP Unit I BART
emission rates for NO X , SO 2 , and PM. The 98 th percentile results are provided in Table ES-1.

### ES-3 11/2/2009 TABLE ES-1 – Visibility Impairment Impacts from Combined Emissions

Control Technique NO X Emission Rate (lb/hr) SO 2 Emission Rate (lb/hr) PM Emission Rate (lb/hr) Visibility Impairment Impact

(dV)
BART 2,804 505 84.1 0.493

The modeling showed that the proposed BART emissions rates for NO X , SO 2 and PM caused no Class I area to exceed 0.5 dV for predicted visibility impairment impact (98 th percentile) with Boundary Waters Canoe Area Wilderness (Boundary Waters) showing the hi ghest predicted visibility impairment impact at 0.493 dV for the 2007 modeled year.

### 1 11/2/2009 1.0 INTRODUCTION The EPA finalized the Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations in 2005 (40 CFR 51, Subpart P; 40 CFR 51, App.Y). BART is defined as “an emission limitation based on the degree of reduction achi evable through the application of the best system of continuous emission reduction for each pollutant which is emitted by a BART-eligible source. The emission limitation must be established, on a case-by- case basis, taking into consideration the technology available, the costs of compliance, the energy and non-air quality environmenta l impacts of compliance, any pollution control equipment in use at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasona bly be anticipated to result from the use of such technology” (40 CFR 51.301). This document presents the BART analysis for each of three major pollutants (nitrogen oxides (NO X ), sulfur dioxide (SO 2 ), and particulate matter (PM)) for Otter Tail Power Company’s (OTPC’s) Big Stone Plant (BSP) Unit I located near Big Stone City, South Dakota. Otter Tail Power Company is operating agent for the Bi g Stone Plant co-owners: NorthWestern Energy, Montana-Dakota Utilities, Co., a division of MDU Resources Group, and Otter Tail Power Company.

A BART eligible source is one that meets three criteri a identified by EPA: (1) source is BART eligible if operations fall within one of 26 specifically listed s ource categories, (2) the source entered into service between August 7, 1962 and August 7, 1977, and (3) th e source has the potential to emit 250 tons per year or more of any air (40 CFR 51.301)). The Sout h Dakota Department of Environment & Natural Resources (DENR) reviewed the sources within S outh Dakota and independent ly determined which sources are BART eligible. The DENR classified the electric generating unit (EGU) at Big Stone Plant as BART eligible. Once a source is determined to be eligible, baseline modeling is performed to determine if the source “contributes” to visibility impairment by exceeding EPA’s recommended 0.5 deciView (dV) threshold. Baseline modeling results show that Unit I at BSP exceeds the 0.5 dV impact threshold and is subject to a BART analysis.

The EPA has established guidelines for states to fo llow when determining BART. These guidelines are discretionary for sources other than 750 MW power pl ants (40 CFR 51.308(e); 40 CFR 51, App, Y, I.H). Per EPA’s guidelines, the general steps for determin ing BART for each pollutant are (40 CFR 51, Appy. Y, IV.D.):

STEP 1 - Identify all available retrofit control technologies (within the BART Guidelines). STEP 2 - Eliminate technically infeasible options.

### 2 11/2/2009 STEP 3 - Evaluate control effectiveness of remaining control technologies. STEP 4 - Evaluate the following impacts for each f easible control technology and document results:

• The cost of compliance.

• The energy impacts.

• The non-air quality environmental impacts.

• The remaining useful life of the source. STEP 5 – Evaluate the visibility impacts.

OTPC retained Burns & McDonnell to assist in the co mpletion of the Best Available Retrofit Technology analysis for Big Stone Plant (BSP) Unit I. i This report includes steps 1 through 5 of the BART
Determination for emissions from Unit I at BSP. S ection 1 of the report summarizes the plant conditions, provides the parameters used in the analysis and di scusses the approach to the BART Determination. The BART analysis for each pollutant (NO X , SO 2 and PM) is provided in Sections 2 through 5. Within the section for each pollutant, the results of each step of the BART analysis are summarized for the unit. Summaries are provided at the end of the report that co mmunicate the results of each step in the analyses, that combine results obtained for each pollutant an d that develop permit limit recommendations based upon a 30 day rolling average.



### 1.1 BACKGROUND
Otter Tail Power Company operates the Big Stone Plan t near Big Stone City, South Dakota. BSP is a steam electric generating plant with one Babcock & Wilcox (B&W) cyclone-fired steam generating unit burning Powder River Basin coal and a net electrical output of 475 MW. Particulate control for Unit I was originally provided by an elect rostatic precipitator. In 2001, a new developmental technology, the Advanced HybridTM system, was installed. Th e Advanced HybridTM technology used both an electrostatic precipitator and a fabric filter (baghouse) for exhaust gas particulate removal. However, the demonstration technology encountered operational pr oblems during its testing phase, which resulted in decreased fabric filter life, decreased particulate re moval efficiencies, and limited plant operations. Consequently, the Advanced HybridTM system was deem ed unacceptable for particulate emissions control and was removed and replaced with a conventional pulse-jet fabric filter in 2007. The Advanced HybridTM system is not currently used in any coal-fired power plant. Nitrogen oxides (NO x ) emissions

i Burns & McDonnell plans, designs and constructs electric generating facilities and has been providing environmental services to the power industry since the 1970s. As a result of its long history providing these services, Burns & McDonnell has extensive experience in permitting, Best Available Control Technology (BACT) studies, BART analysis and control technology analysis.

### 3 11/2/2009 from the unit are controlled with an over-fire air system (OFA). The unit does not have controls for sulfur dioxide emissions other than firing low-sulfur Powd er River Basin coal. Unit I began operation in 1975 and is presumed to be subject to the requirement s for BART analysis under the Regional Haze Rule absent a formal determination to the contrary from the DENR.



### 1.2 BART ANALYSIS PARAMETERS
Table 1.2-1 contains the design and operating parameters for BSP Unit I used in the analysis. Typical coal parameters used in the BART analysis are provi ded in Table 1.2-2. The economic factors for this study are presented in Table 1.2-3.



### TABLE 1.2-1 – Unit Design and Operating Parameters

Unit Characteristics Unit I Parameters Boiler Type Cyclone Boiler Manufacturer B&W Boiler Heat Input Capacity (descriptive), mmBtu/hr 5,609 Unit Generator Output Capacity, MW (net) 475 NO X Emissions lb/mmBtu 0.86 lb/hr 1 4,854.8 SO 2 Emissions lb/mmBtu 0.86 lb/hr 1 4,832.2 PM Emissions lb/mmBtu 0.015 lb/hr 2 84.1
1 Highest 24-hour actual average emission rates during 2001-2003 as recommended by the BART Guideline. The SO 2 emission rate does not correspond to fuel sulfur content. 2 Highest achievable 24-hour average emission rate based on the existing control technology emission rate and the unit heat input

### 4 11/2/2009 TABLE 1.2-2 – Coal Parameters

Ultimate Coal Analysis (% by mass): PRB Typical Moisture 29.75 Carbon 49.30 Hydrogen 3.32 Nitrogen 0.66 Chlorine 0.01 Sulfur 0.33 Ash 4.63 Oxygen 12.00 Total 100.00 Higher Heating Value, Btu/lb 8,547 Ash Mineral Analysis (% by mass): Silica 35.51 Alumina 17.11 Titania 1.26 Calcium Oxide 26.67 Magnesium Oxide 5.30 Sodium Oxide 1.68 Iron Oxide 6.07 Sulfur Trioxide 1.56 Potassium Oxide 2.87 Phosphorus Pentoxide 0.97 Strontium Oxide not reported Barium Oxide not reported Manganese Oxide not reported Total 99.00

### 5 11/2/2009 TABLE 1.2-3 – Economic Factors

Total Possible Operating Hours per Year 8,760 Amortization Life, Years 30 Discount Rate 9% Construction Cost Escalation 3% O&M Escalation 2% Auxiliary Electric Power Cost, $/MW-hr $25 Fly Ash Disposal Cost ($/ton) $2 Bottom Ash Disposal ($/ton) $3.50 Gypsum Waste Disposal ($/ton) $1 Operating Labor Rate, $/hr $48 Lime Cost ($/ton delivered) $145 Limestone Cost ($/ton delivered) $24 Urea Cost, ($/ton delivered) $380 Ammonia Cost ($/ton delivered) $325



### 1.3 APPROACH
The purpose of the Regional Haze Rule is to address visibility impairment in mandatory Class I areas that
results from the emission of SO 2 , NO X , PM, Volatile Organic Compounds (VOCs) and ammonia from certain major sources. The visibility impact of VOCs and ammonia are considered negligible and are not addressed further in this report. Before the actual BA RT analysis can begin, a basis must be defined for establishing emission rates to be used for BSP Unit I. For NO X and SO 2 , the highest 24-hour actual average emission rates for 2001-2003 were used for the basis as recommended by the BART guideline. For PM, the achievable emission rate for the fabric f ilter installed in 2007 was used as the basis of the study. A sulfuric acid mist (SAM) emission rate of 3.604 pounds per hour as approved in the Modeling
Protocol was used for the baseline ev aluation and for all control scenarios.

In Part IV of the Guidelines for BART Determinati on, and discussed in Section 1.0 of this report, the EPA provides five basic steps for a case-by-case BART analysis although states have the discretion to adopt approaches that differ from the guidelines for sources other than 750 MW power plants. The format of this report follows these basic steps. The approach used to complete each step is summarized
below.

### 6 11/2/2009 1.3.1 IDENTIFICATION OF RE TROFIT CONTROL TECHNOLOGIES
The initial step in the BART determination is the iden tification of retrofit control technologies. In order to identify the applicable control t echnologies, several reference works are consulted. A preliminary list of control technologies and their estimated capabilities is developed.



### 1.3.2 FEASIBILITY ANALYSIS
The second step of the BART process is to evaluate the control processes that have been identified and determine if any of the processes are technically in feasible. The BART guidelines discuss consideration of two key concepts during this step in the analysis . The two concepts to consider are the “availability” and “applicability” of each control technology.

A control technology is considered available, “i f the source owner may obtain it through commercial channels, or it is otherwise available in the common sense meaning of the term” or “if it has reached the stage of licensing and commercial availability.” On th e contrary, a control technology is not considered available “in the pilot scale testing stages of developm ent.” (70 FR 39165) When considering a source’s applicability, technical judgment must be exercised to determine “if it can reasonably be installed and operated on the source type.” The EPA also does not “e xpect a source owner to conduct extended trials to learn how to apply a technology on a totally new and dissimilar source type.” (70 FR 39165) “A technology that is available and applicable is technically feasible.” (70 FR 39165)



### 1.3.3 EVALUATE TECHNICALLY FEASIBLE CONTROL OPTIONS BY EFFECTIVENESS
The third step in the BART analysis is to evaluate the control effectiveness of the technically feasible alternatives. During the feasibility determination in step 2 of the BART analysis, the control efficiency is reviewed and presented with the description of each technology. The evaluation of the technically
feasible BART alternatives concludes with the alternatives ranked in descending order of control
effectiveness.



### 1.3.4 IMPACT ANALYSIS
Step four in the BART analysis procedure is the impa ct analysis. The BART Guidelines lists four factors to be considered in the impact analysis:

• The costs of compliance;

• Energy impacts;

### 7 11/2/2009 • Non-air quality environmental impacts; and

• The remaining useful life of the source.
The first three of the four factors considered in the impact analysis are di scussed in the associated pollutant section. The remaining useful life of the so urce is included as part of the cost of compliance. Due to the complexity involved with estimati ng costs, additional discussion is provided below.



### 1.3.5 METHODOLOGY FOR ESTIMATED COSTS

The economic evaluations of each control alternative are presented together for each pollutant in the respective sections of the report. Capital and O&M cost estimates for each control alternative are presented. The Levelized Total Annual Cost (LTAC) and Unit Control Costs for the control alternatives are calculated and presented. The Levelized Total A nnual Cost (LTAC) represents the levelized annual cost of procurement, construction a nd operation over a 30 year design life in current (2009) dollars. As a minimum, the design life for any alternative was taken to be that recommended by “The EPA Air Pollution Control Cost Manual”, Sixth Edition, January 2002, EPA/452/B-02-001.

The LTAC is used to calculate the average annual and in cremental cost effectiveness of each alternative. The differences between alternatives are also presented graphically in the form of a plot of the LTAC versus the annual emissions reduction (tpy) for each altern ative. This form of plot graphically depicts the cost effectiveness (in $/ton of pollutant reduction) of each alternative relative to all of the others. The average cost effectiveness is defined as the LTAC di vided by the annual emissions reduction (ton/yr). The area on the plot indicated by the various data poi nts represents the cost effectiveness envelope for the
alternatives under consideration. A smooth line is drawn on this plot connecting the rightmost points (those with the lowest cost for a given level of em issions reduction). This line is referred to as the Dominant Control Curve (DCC). The DCC defines the right hand boundary of the envelope encompassing all of the alternatives considered. The DCC is used as a screening tool between considered alternatives. Those alternatives whose plotted position is above and/or to the left of the DCC are not as cost effective as those forming the line and thus can be eliminated from further analysis. An example DCC chart was provided in the BART Guidelines.

### 8 11/2/2009 To more accurately compare alternatives having differe nt costs and control efficiencies; the incremental
cost effectiveness is also determined for those alternatives on the DCC. The incremental cost effectiveness is defined as the LTAC of a given contro l option minus the LTAC of an alternative, divided by the difference between the annual emissions re duction (tpy) of the given control option and the alternative being evaluated. The combination of these two economic analyses can be used as an argument for the elimination of control technologies with signifi cantly greater marginal control costs than the given case. The equation used for the incrementa l cost effectiveness is shown below.

### 9 11/2/2009 ) ( ) (

2 1 2 1 

### AE AE LTAC LTAC ICF

− −
=

Where,
ICF = Incremental cost effectiveness ($/incremental ton removed) LTAC 1 = Levelized Total Annual Cost of control alternative No. 1 ($/yr) LTAC 2 = Levelized Total Annual Cost of control alternative No. 2 ($/yr) AE 1 = Control option No. 1 Annual Emissions Reduction (ton/yr) AE 2 = Control option No. 2 Annual Emissions Reduction (ton/yr) (The higher cost, more effective control option is subscript 1 in this equation.)

The economic analyses presented in this report include not only the estimated capital and O&M costs for each alternative, but also the LTAC for economic compar ison of the various alterna tives. In addition, the average cost effectiveness is presente d for each alternative. Finally, a comparison between alternatives, in the form of the incremental cost effectiveness, is presented in both numerical and graphical form. Thus a comprehensive comparison of the economic impacts of each alternative, as well as the differences in economic impact between alternatives is clearly presented.



### 1.3.6 METHODOLOGY FOR VISIBI LITY IMPACTS DETERMINATION
In the BART Determination Guidelines, and discussed in Section 1.0 of this report, the EPA provides five basic steps for a case-by-case BART analysis. The fifth step involves evaluating visibility impacts utilizing dispersion modeling. Visibility impairment impacts for modeled baseline (pre-control) and postcontrol emission levels and visibility improvements are to be assessed in deciViews (dV). The BART guidelines describe the thresholds for visibility impairment as:

“A single source that is responsible for a 1.0 dV change or more should be considered to “cause” visibility impairment; a source that causes less than a 1.0 dV change may still contribute to visibility impairment..... any threshold that you (the States) use for determining whether a source “contributes” to visibility impairment should not be higher than 0.5 dV.” (70 FR 39161)

This study follows the EPA’s Regional Haze Rule thre shold recommendations and thus, 0.5 dV is the de minimis threshold level of visibility impairment impact for an otherwise BART-eligible source. In other words, a BART-eligible source for which modeling predic ts a visibility impairment impact of greater than 0.5 dV is deemed to contribute to a visibility impa irment impact and thus is subject to a case-by-case BART analysis. A BART-eligible source for which the modeling predicts less than a 0.5 dV impact

### 10 11/2/2009 would be deemed to not have a visibility impairmentimpact, and thus could be exempted from a case-bycase BART analysis on that basis. Most noticeably, the EPA fails to address the question of whether or not a difference in visibility impairment impact im provement of less than 0.5 dV between two BART alternatives would constitute equivale ncy under the visibility analysis, or if any difference in the model results, no matter how slight, should be interpre ted as ranking one solution over the other.

The approach taken in the BART analysis for BSP inco rporates the visibility analysis results as part of the decision making process. If two alternatives have an identical potential for visibility improvement, the remaining criteria identified for consideration as part of the impact analysis are th en used to differentiate
between the two alternatives. Where similar visib ility improvement potentials are identified for two or more alternatives, the incremental cost to achieve the slightly greater visibility improvement is determined and evaluated against incremental costs for th e next most stringent alternative. This approach
identifies the more effective BART alternative in te rms of regional haze considerations, not in terms of the most stringent control alternative, as would happen if a strictly top-down approach had been implemented.



### 1.3.7 ADDITIONAL APPROACH METHODS
In addition to the steps discussed above, the presumpti ve limits and their application to power plants
smaller than 750 MW in size warrant mention due to thei r effects on the contents of the report. For power plants greater than 750 MW in size, the EPA requires state agencies to apply the presumptive limits for
BART as a floor for NO X or SO 2 control. However, for power plants smaller than 750 MW in size, the presumptive limits are described as being “generally cost-effective” but not set as a minimum performance requirement (see, e.g., 40 CFR 51, App. Y, IV.E.4). Thus, EGUs at power plants smaller than 750 MW in size, like BSP, are not required to meet the presumptive BART limits. This BART analysis for BSP will evaluate potential contro l options that can attain presumptive limits on typical EGUs. However, based upon the feasibility analysis , the recommended control options may not achieve the EPA’s presumptive BART limits for specific pollutants.



### 1.4 THE ROLE OF MODELING AND CALPUFF IN A BART ANALYSIS
The BART guidelines list visibility impact at a Cl ass I area as one of the factors in a BART
determination. For Class I areas more than 50 km from a source, the EPA has identified CALPUFF as a guideline model for long-range transport that is suita ble for predicting potential changes in visibility.

### 11 11/2/2009 CALPUFF is a non-steady-state meteorological and air quality dispersion modeling system used to assess long-range transport of pollutants. Seven Class I areas have been identif ied for inclusion in the visibility analysis for BSP. These are the Theodore Rooseve lt National Park (NP), the Lostwood National Wildlife Refuge (WR), Voyagers NP, Isle Royal NP, Boundary Waters Canoe Area Wilderness, Badlands NP, and Wind Cave NP, the closest of which is more than 400 km (248 miles) from BSP.



### 1.4.1 CALPUFF MODELING METHODOLOGY
The specific version of CALPUFF, coordinate grid poi nts, wind field options, terrain, dispersion options, receptor coordinates and plume characteristics and ot her model parameters approved by the DENR were used for modeling. Meteorological data for the y ears 2002, 2006 and 2007 were used for the modeling. In order to predict the change in light extinction at the Class I areas, SO 2 , NO X , and PM were modeled with CALPUFF using pre-control (b aseline) and post-control emission scenarios. A variety of postcontrol scenarios were modeled to determine the reduction in visibility impact for each control technology.

The BART guideline states that a visibility improvement is based upon the modeled change in visibility impacts, measured in deciViews, for the pre-contro l and post-control emission scenarios. The comparison should be made for the 98th percentile days (40 CFR 51, App. Y, IV.D.5). In other words, visibility impacts should be compared on an annual basis using the eighth highest day for comparison (365 * (1- .98) ≈ 7 days of acceptable exceedance). Therefore, the visibility impairment impact reduction presented
for each control scenario in this section is based on the 98 th percentile value or eighth highest day.



### 1.4.2 MODELING SCENARIOS
Since a BART analysis is based on the degree of visibility impairment reduction achieved by the application of control technologies, the CALPUFF an alysis examined multiple emission scenarios based upon the feasible control technologies identified for each pollutant. Th ese scenarios represent the
emissions of SO 2 , NO X , and PM under the following conditions:

• Baseline NO X , SO 2 and PM emissions

• PM emissions based upon existing controlled baseline conditions, and NO X and SO 2 emissions based upon application of several control technologies The modeled emission rates in each scenario are presented in Table 1.4-1.

### 12 11/2/2009 TABLE 1.4-1 – Big Stone Plant Modeling Scenarios

Unit I

Scenario NO X (lb/h) SO 2 (lb/h) PM (lb/h) 1 0 Baseline 4,854.8 4,832.2 84.1

1 Over-fire Air (OFA) Presumptive Dry FGD 3,645.9 841.4 84.1

2 OFA Presumptive Wet FGD 3,645.9 841.4 84.1

3 OFA Dry FGD at 90% Control 3,645.9 504.8 84.1

4 OFA Wet FGD at 95% Control 3,645.9 241.2 84.1

5 Separated OFA (SOFA) Presumptive Dry FGD 2,804.5 841.4 84.1

5A SOFA Dry FGD at 90% Control 2,804.5 504.8 84.1

5B SOFA Wet FGD at 95% Control 2,804.5 241.2 84.1

6 SNCR with SOFA Presumptive Dry FGD 1,963.2 841.4 84.1

7 RRI+SNCR with SOFA Presumptive Dry FGD 1,121.8 841.4 84.1

8 SCR with SOFA Presumptive Dry FGD 560.9 841.4 84.1 1 – The PM technology for all modeling scenarios is the existing pulse-jet fabric filter.

These scenarios represent the range of emissions evaluated for consideration in making a BART
determination. The baseline scenario is based on the historical, highest 24-hour actual average SO 2 and
NO X emission rates for BSP between 2001 and 2003. The emission rate for PM is the achievable controlled emission rate for the existing fabric filter. Due to the number of variations involved for each pollutant, the scenarios are discu ssed in the section related to the controlled pollutant.

### 13 11/2/2009 2.0 NO X 

### BART EVALUATION The BART analysis steps 1 through 5 for NO X emissions from BSP are described in this section. Potentially applicable NO x control technologies are first identifie d. A brief description of the processes and their capabilities are then reviewed for availability and feasibility. A detailed technical description of each control technology is provided in Appendix A1. Subsequently, those available technologies deemed feasible for retrofit application are ranked according to nominal NO x control capability. The impacts analysis then reviews the estimated capital and O& M costs for each alternative, including Balance Of Plant (BOP) requirements. Following the cost de termination, the energy impacts and non-air quality impacts are reviewed for each technology. The impact based on the remaining useful life of the source is reviewed as part of the cost analysis. In the final step of the analysis, feasible and available technologies are assessed for their potential visibility impairment impact reduction capability via visibility modeling results. The results of the impact analyses are tabul ated and potential BART control options are listed.



### 2.0.1 BART GUIDELINE NO X 

### LIMITS FOR CYCLONE-FIRED BOILERS
EPA’s presumptive limit for emissions of nitrogen oxides from cyclone-fired boilers, which does not apply to BSP, was established in the final BART Guidelines 1 :

“The use of SCRs at cyclone units burning bi tuminous coal, sub-bituminous coal, and lignite should enable the units to cost-effectively meet NO X rates of 0.10 lbs/mmBtu. As a result, [the EPA] are establishing a presumptive NO x limit of 0.10 lbs/mmBtu based on the use of SCR for coal-fired cyclone units greater than 200 MW located at 750 MW power plants. ” [70 FR 39172]

40 CFR 51, App. Y, IV.E.5. While Unit I at BSP is greater than 200 MW output, it is not located at a 750 MW power plant. Thus, Unit I is not subject to presumptive limits.



### 2.1 IDENTIFICATION OF RETROFIT NO X 

### CONTROL TECHNOLOGIES
The first step in the BART evaluation for NO x emissions is to identify potentially applicable retrofit control alternatives. A comprehensive literature se arch was performed, with sources including technical papers and presentations made by parties involved with design, construction, and testing of NO X control techniques at conferences sponsored by nationally-r ecognized technical organizations, plus hardware supplier experience lists.

### 14 11/2/2009 There are two basic categories of NO X emission control alternatives:

• Combustion controls; and

• Post-Combustion controls.

A summary of the potentially available alternatives identified for NO X emissions control on coal-fired cyclone units is shown in Table 2.1-1.



### TABLE 2.1-1 – Potentially Available NO X 

### Control Alternatives Identified for BART Analysis

Combustion Controls
Low-NO X Burners (LNBs) Over-fire Air (OFA) Separated Over-fire Air (SOFA)
Post-Combustion Controls Selective Non-Catalytic Reduction (SNCR) Rich Reagent Injection (RRI) Selective Catalytic Reduction (SCR)



### 2.2 TECHNICAL DESCRIPTIONS AND FEASIBILITY ANALYSIS OF NO X 

### CONTROL TECHNOLOGIES
The second step of the BART process is to evaluate the control processes that have been identified and eliminate any that are technically infeasible for a pplication at the source. The following paragraphs summarize the evaluation of the processes fo r technical feasibility for BSP Unit I NO X controls. A detailed description of the various NO X control technology retrofits and thei r technical feasibility is included in Appendix A1, with the associated re ferences for technical literature.



### 2.2.1 FEASIBILITY OF COMBUSTION NO X 

### CONTROLS
The following combustion controls are potentially feasi ble technologies that are applied to a cyclone-fired
boiler.

• An over-fire air (OFA) system has already been implemented on the Unit I boiler with the ability to significantly lower NO X emissions. Implementation of more stringent operational procedures to

### 15 11/2/2009 maintain significantly lower NO X emissions with the existing OFA system was considered a feasible application at BSP for Unit I.

• Separated over-fire air (SOFA) systems have been retrofit to many cyclone boilers for combustion
NO X control. 2,3,4,5,6 SOFA offers the highest performing version of this technology for cyclone boilers, and may include relocating vent ports and/or flue gas r ecirculation ports. SOFA is a feasible technology for BSP Unit I and is include d in the control effectiveness analysis for
additional NO X . The NO X control improvements through use of SOFA on Unit I will be limited by potential adverse impacts on cyclone operation associated with air-staged (sub-stoichiometric air/fuel) cyclone operation, which are described in Appendix A1.

Low-NOX burners (LNBs), while commonly applied to pul verized coal-fired boilers, are not applicable to cyclone fired units since initial combustion occurs in the barrel-shaped cycl one and not in the furnace chamber as is the case for the pulverized coal-fired boiler. Therefore, they will not be considered further.



### 2.2.2 FEASIBILITY OF POST-COMBUSTION NO X 

### CONTROLS
Post-combustion controls involve technologies that are applied to the flue gas after the combustion process. Typically these processes involve the u se of a reagent to chemically react with NO X . These are summarized as follows; for more details, refer to the technical feasibility evaluation included in Appendix
A1:

• SNCR has been applied on several cyclone-fired bo ilers since 1995 and its installation on the Unit I cyclone boiler is considered feasible. 7,8,9 Because BSP Unit I already has OFA for NO X control, SNCR will be evaluated in conjunctio n with the existing OFA or SOFA.

• Rich Reagent Injection (RRI) injects aqueous ur ea into the high-temperature lower furnace zone and requires an “air-starved” atmosphere to avoid creating instead of reducing NO X . RRI has been developed and demonstrated with appli cation intended only on cyclone boilers. 9,10,11,12 RRI has been installed and is commercially available.

o RRI is susceptible to impairment due to fouling by ash slag deposits and heat-related damage of injection nozzles, which are located n ear the cyclones in the lower furnace.

o RRI is considered feasible for application on cy clone boilers operating under substoichiometric
conditions with advanced forms of SOFA and in combination with SNCR for NO X control at BSP
Unit I.

• Selective Catalytic Reduction (SCR) technology has been installed on 22 cyclone-fired boilers in the U.S., burning bituminous or sub-bituminous coals, and its installation on BSP Unit I for

### 16 11/2/2009 additional NO X control is considered technically feasible. 34 As with SNCR, SCR will be evaluated in conjunction with the existing OFA or SOFA.



### 2.2.3 RESULTS OF FEASIBILITY ANALYSIS

The results of the evaluation of the identified BA RT alternatives following th e feasibility analysis are
summarized in Table 2.2-1.



### TABLE 2.2-1 – NO X 

### BART Feasibility Analysis Results

Control Technology In service on Existing Utility Boilers Commercially Available Technically Applicable To Big Stone Plant Over-fire Air (OFA) Yes Yes Yes Separated OFA (SOFA) Yes Yes Yes Selective Non-cataly tic Reduction (SNCR) with OFA or SOFA Yes Yes Yes
Rich Reagent Injection (RRI) + SNCR with SOFA Yes Yes Yes
Selective Catalytic Reduction (SCR) with OFA or SOFA Yes Yes Yes



### 2.3 CONTROL EFFECTIVENESS EVALUATION OF NO X 

### CONTROL TECHNOLOGIES
Control options that offer zero or very small additio nal control performance at a significant cost impact were not included in impact analysis. Alternativ es that are equally effective in predicted emission reduction percentage but are more expensive to instal l and operate, or have more substantial operational limitations compared to other feasible alternatives, we re also eliminated from further analysis. Table 2.3-1 lists the feasible control technologies and indicates the technologies evaluated in the analysis.

### 17 11/2/2009 TABLE 2.3-1 – Evaluated NO X 

### Control Technologies

Control Technology Approximate Control Efficiency Evaluated Over-fire Air (OFA) 25 Yes Separated OFA (SOFA) 42 Yes Selective Non-catalytic Reduction (SNCR) with OFA 60 No 1 SNCR with SOFA 60 Yes Rich Reagent Injection (RRI)+SNCR with SOFA 77 Yes Selective Catalytic Reduction (SCR) with OFA 88 No 2 SCR with SOFA 88 Yes 1 – Due to an estimated $1,810,000 increase in leveli zed annual costs for the same level of control as SNCR with SOFA, this technology w ould be above the dominant contro ls curve and are not evaluated further as described in Section 1.3.5. 2 – Due to an estimated $140,000 increase in levelized annual costs for the same level of control as SCR with SOFA, this technology would be above the dominant controls curv e and are not evaluated further as described in Section 1.3.5

Available NO X emission control options considered feasible for BSP Unit I boiler are listed in Table 2.3-2 in descending order of control eff ectiveness. Ranking of the alternativ es in Table 2.3-2 assumes that the
baseline level of NO X emissions for the BSP Unit I boiler is asso ciated with the emission rate of 0.86
lb/mmBtu.

The emission reduction (control effectiveness) percen tages developed for the feasible alternatives shown in Table 2.3-2 are estimates based upon engin eering judgments with considerations of:

• the general combustion properties of Powder River Basin (PRB) coal;

• published and available emission reduction perform ance achieved at other similar utility power plants (wet-bottom cyclone-fired boilers); and

• inclusion of performance margins to allow for va riations in fuel, weathe r, equipment condition, and other factors that prevent the ultimate p eak short-term performance from being reliably sustained over the course of long-term operation.

The potential operational limitations mentioned in the detailed feasibility discussions included in Appendix A1 for deeply air-staged cyclones associated with separated over-fire air and Rich Reagent Injection alternatives are expected to limit the amount of NO X control potential possible compared to other boiler types where this technique or technology was applied.

### 18 11/2/2009 TABLE 2.3-2 – Estimated Control Options NO X 

### Emission Rates Evaluated

NO X Control Technique Emission Rate (lb/mmBtu) Control Percentage Hourly Emission

(lb/hr)
SCR w/ SOFA 0.10 88 560.9 Rich Reagent Injection (RRI)+SNCR w/ SOFA 0.20 77 1,121.8

SNCR w/ SOFA 0.35 60 1,963.2
Separated Over-fire Air (SOFA) 0.50 42 2,804.5
Over-fire Air (OFA) 0.65 25 3,645.9
Baseline 0.86 -- 4,854.8



### 2.4 EVALUATION OF IMPACTS FOR FEASIBLE NO X 

### CONTROLS
The fourth step of a BART analysis is to evaluate the following impacts of feasible emission controls:

• The cost of compliance.

• The energy impacts.

• The non-air quality environmental impacts.

• The remaining useful life of the source.

The purpose of the impacts evaluation is to determ ine if there are any energy, economic, non-air quality environmental reasons, or aspects of the remaining useful life of the source, which would eliminate the remaining control technologies from consideration for BSP Unit I.



### 2.4.1 COST IMPACTS OF NO X 

### CONTROLS
An evaluation was performed to determine the co mpliance costs of installing various feasible NO X control
alternatives on BSP Unit I boiler. This evaluation included estimates for:

• Capital costs;

• Fixed and variable operating and maintenance (O&M) costs; and

• Levelized total annual costs to engineer, procure, construct, install, startup, test, and place into commercial operation a particular control technology.

### 19 11/2/2009 The results of this evaluation are summarized in Tables 2.4-1 through 2.4-6.



### 2.4.1.1 CAPITAL COST ESTIMATES FOR NO X 

### CONTROLS The capital costs to implement the various NO X control technologies were largely estimated from unit output capital cost factors ($/kW) published in techni cal papers discussing those control technologies. Anticipated costs unique to BSP that are necessary fo r installation of the control technology were also identified. In the cases involving SNCR or RRI, vend or budgetary cost information was obtained and used in place of, or to adjust, the published unit output cost factors. These cost estimates were considered to be study grade, which is + or – 30% accuracy.

A review of the unit capital cost factor a nd associated capital costs for the feasible NO X emission reduction technology evaluated for BSP are presented in Table 2.4-1.



### TABLE 2.4-1 – Unit Capital Cost Factors of Feasible NO X 

### Control Options

NO X 

### Control Technique Unit Capital Cost 1 

### ($/kW) Capital Cost ($1000)
SCR with SOFA 172 2 81,800

RRI + SNCR with SOFA 34 3 16,200 SNCR with SOFA 25 11,900 Separated Over-fire Air (SOFA) 10 4,800 Over-fire Air (OFA) Existing Existing 1 – Unit capital cost factors ($/kW) of these individual technologies were combined by simple addition. Actual installed costs may differ due to positive or negative synergistic effects. 2 – Estimate taken from CUECost adjusted to reflect Burns & McDonnell project experience included in Appendix A2. 3 – RRI estimate is taken from the DOE report, “Field Testing of Advanced Layered Technology Approach (ALTATM) for NOx Control in Sioux Unit 1”.



### 2.4.1.2 OPERATING AND MAINTE NANCE COST ESTIMATES FOR NO X 

### CONTROLS The operation and maintenance costs to implement the NO X control technology evaluated for BSP Unit I were largely estimated from cost factors establishe d in the EPA’s Air Pollution Control Cost Manual

### 20 11/2/2009 (OAQPS), and from engineering judgment applied to that control technology. These cost estimates were considered to be study grade, which is + or – 30% accuracy.

Fixed and variable operating and maintenan ce costs considered and included in each NO X control technology’s O&M costs are estimates of:

• Auxiliary electrical power consumption for operating the additional control equipment;

• Reagent consumption, and reagent unit cost for SCR, SNCR and RRI alternatives;

• Catalyst replacement for SCR; and

• General operating labor, plus main tenance labor and materials devoted to the additional emission control equipment and its impact on existing boiler equipment.

A review of the estimated operation an d maintenance costs for the feasible NO X emission reduction technology evaluated for BSP are presented in Table 2.4-2.



### TABLE 2.4-2 – Estimated O&M Costs for NO X 

### Control Options

NO X 

### Control Alternative First Year O&M Cost ($1,000)
SCR with SOFA 4,110
RRI+SNCR and SOFA 7,260
SNCR with SOFA 2,120 Separated Over-fire Air (SOFA) 152 Over-fire Air (OFA) 106

In order to compare a particular NO X emission reduction alternative during the cost of compliance impact analysis portion of the BART selection process, the basic methodology defined in the BART Guidelines
was followed. The Levelized Tota l Annual Cost (LTAC) of these NO X control alternatives was
calculated based on the same economic conditions and a 30 year project life (see Section 1.3.5 of this BART evaluation for methodology details). Estimate d capital costs were split evenly over a two year construction period for all alternatives and a presen t value was calculated. Table 2.4-3 shows the estimated present value capital cost and annua lized cost values for the various feasible NO X emission reduction technologies. These are listed in order of c ontrol effectiveness, with the highest ranked options at the top.

### 21 11/2/2009 TABLE 2.4-3 – Capital and Annualized Costs Estimated for NO X 

### Control Alternatives

NO X 

### Control Alternative Capital Cost 1 

### ($1000) Present Value Capital

Cost ($1,000) First Year O&M Cost ($1,000) Levelized Cost 2 

### ($1,000) SCR with SOFA 81,800 76,800 4,110 13,210 RRI+SNCR and SOFA 16,200 15,200 7,260 11,390 SNCR with SOFA 11,900 11,200 2,120 3,990 Separated Over-fire Air (SOFA) 4,800 4,500 152 650 Over-fire Air (OFA) 0 0 106 140 1 – Installed capital cost is estimated for determinati on of total capital cost for a control technology, assuming maximum unit output capacity is based on 475,000 kW. 2 – Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. The Annualized O&M cost fa ctor = 1.361 and the Capital Recovery Factor = 0.0991

The average cost effectiveness was then determined as the LTAC divided by baseline annual tons of pollutant emissions that would be avoided by implem entation of the respective alternative. Table 2.4-4 shows the average cost eff ectiveness comparison for the NO X control technologies. The feasible control alternatives were also compared by calculating the change in LTAC per incremental ton of pollutant removed for the next most stringent alternative (incre mental cost effectiveness). This identified which alternatives produced the highest increment of exp ected pollutant reduction for the estimated lowest average LTAC increment compared with the pre-cont rol baseline emission rate. The expected annual number of tons of pollutant remove d versus estimated LTAC for each remaining control alternative was then plotted.

### 22 11/2/2009 TABLE 2.4-4 – Estimated Annual Emissions and LTAC for NO X 

### Control Alternatives

NO X Control Alternative Annual NO X Emissions 1 (Tons/yr) Annual NO X Emissions Reduction 1 (Tons/yr) Levelized Total Annual

Cost ($1,000) Average Cost Effectiveness ($/ton) SCR with SOFA 2,090 16,000 13,210 825
RRI+SNCR and SOFA 4,180 13,910 11,390 818
SNCR with SOFA 7,310 10,780 3,990 197 Separated Over-fire Air (SOFA) 10,440 7,640 650 85 Over-fire Air (OFA) 13,570 4,510 140 31

Baseline 18,080 - - -

1 – Annual NO X emissions and control level based upon 8,760 hours of operation and 85% capacity factor.

The comparison of the cost-effectiveness of the cont rol options evaluated for BSP is shown in Figure
2.4-1. The estimated annual amount of NO X removal (emission reduction) in tons per year is plotted on the abscissa (horizontal axis) and the estimated LTA C in thousands of U.S. dollars per year on the ordinate (vertical axis).

### 23 11/2/2009 Figure 2.4-1 – NO X 

### Control Cost Effectiveness

SNCR/ SOFA SCR / SOFA

SOFA OFA RRI/SNCR/SOFA

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000

- 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 Emissions Reduction (tpy)Total Levelized Costs ($1000)

The purpose of Figure 2.4-1 is to show the range of control and cost for the evaluated NO X reduction alternatives and identify the least-cost controls so that the Dominant Controls Curve (DCC) can be created. The DCC is the best fit line through the points forming the lower rightmost boundary of the data zone on a scatter plot of the LTAC versus the annual NO X removal tonnage for the various remaining BART alternatives. Points distinctly to the left of and ab ove this curve are inferior control alternatives per the
BART Guidelines on a cost effectiveness basis. Fo llowing a “bottom-up” graphical comparison approach,
each of the NO X control technologies represented by a data point to the left of and above the least cost envelope should be excluded from further analysis on a cost efficiency basis. Of the highest-performing versions of the technically feasible NO X control alternatives evaluated for cost-effectiveness, the data point for RRI/SNCR/SOFA is seen to be more costly for fewer tons of NO X removed than for SCR with SOFA. This appears to be an inferior control, and thus shou ld not be included on the least cost and DCC boundary. Figure 2.4.2 provides the DCC.

### 24 11/2/2009 Figure 2.4-2 – NO X 

### Control Cost Effectiveness and Dominant Control Cost Curve

OFA SOFA SCR / SOFA

SNCR / SOFA

$0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000

- 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 Emissions Reduction (tpy)Total Levelized Costs ($1000)

The next step in the cost eff ectiveness analysis for the BART NO X control alternatives is to review the incremental cost effectiveness between remaining least- cost alternatives. Table 2.4-5 contains a repetition
of the LTAC and NO X control information with RRI+SNCR/SOFA removed, and shows the incremental
cost effectiveness between each successive set of least-cost NO X control alternatives. The incremental
NO X control tons per year, divided by the incremental levelized annual cost, yields an incremental control cost effectiveness ($/ton).

### 25 11/2/2009 TABLE 2.4-5 – Estimated Incremen tal Annual Emissions and LTAC for NO X 

### Control Alternatives

NO X Control Technique Levelized Total Annual

Cost ($1,000) Annual Emission Reduction 1 (Tons/yr) Incremental Levelized

Total Annual

Cost 2 ($1,000) Incremental Annual Emission Reduction 1,2

(Tons/yr) Incremental Control Cost Effectiveness ($/ton) 3

SCR with SOFA 13,210 16,000 9,220 5,220 1,766

SNCR with SOFA 3,990 10,780 3,340 3,140 1,063

SOFA 650 7,640 510 3,130 163

OFA 140 4,510 140 4,510 31

1 – Annual NO X emissions and control level based upon 8,760 hours of operation and 85% capacity factor. 2 – Increment based upon comparison between consecutive alternatives (points) from lowest to highest. 3 – Incremental control cost effectiveness is incremental LTA C divided by incremental annual emission reduction (tons per year).

In the final BART Guidelines, the EPA does not prop ose hard definitions for reasonable or unreasonable average or incremental cost effectiveness values. As can be seen from a review of Table 2.4-4, the average levelized control cost effectiveness of c ontrol alternatives ranges from $31/ton to $825/ton.

The incremental cost effectiveness is a measure of the increase in marginal co st effectiveness between two specific alternatives. The incremental cost analysis indicates that from a cost effectiveness viewpoint, the most costly alternative is SCR with SO FA. This control option is considered technically feasible for BSP, but incurs a significant annual (lev elized) incremental cost compared to the other
feasible NO X control techniques.



### 2.4.2 ENERGY IMPACTS OF NO X 

### CONTROL ALTERNATIVES

The feasible NO X control alternatives were reviewed for significant or unusual energy penalties or
benefits associated with their use. There ar e several basic kinds of energy impacts for NO X emissions
controls:

• Potential increase or decrease in power plant en ergy consumption resulting from a change in thermal (heat) energy to net electrical output conv ersion efficiency of the unit, usually expressed as an hourly unit heat rate (Btu/kW-hr). This may or may not change the net electrical output

### 26 11/2/2009 (MW) capacity of the EGU depending on if there ar e physical or imposed limits on the total heat input to the boiler or electrical power output.

• Potential increase or decrease in net electrical output of the unit resulting from changes in physical operational limitations imposed on the ability to sustain a fuel heat input rate (mmBtu/hr), which results in a potentially lower or higher unit net electrical output (MW) capacity. This is effectively a change in ne t electrical output (MW) capacity of the EGU.

• Potential increase or decrease in net electrical output of the unit resulting from changes in auxiliary electrical power demand and usage (kW, kW -hrs). This is effectively a change in net electrical output (MW) capacity of the EGU.

• Potential increase or decrease in reliability and av ailability to generate electrical power. This results in a change to the number of hours of annual operation, not necessarily a change in net electrical output (MW) capacity of the EGU.

There should not be a major impact on energy consumption by the operation of the variations of an overfire air (OFA) system, such as separated over-fire ai r (SOFA). An OFA system does not significantly change the total amount of air introduced into the boiler, only the location where it is introduced. Combustion air damper actuators’ electrical power de mand would be an insignificant (+ 1 kW) change in net electrical power consumption. For cyclone bo ilers, providing effective volumes and velocities of separated over-fire air at the injection ports should no t require higher forced draft fan power consumption resulting from higher fan discharge pressure. Higher vent ductwork pressure drop impacts of the OFA system on the forced draft fans’ auxiliary electrical pow er consumption are expected to be negligible (less than 1% of the annual auxiliary pow er consumed by these fans) so that unit net electrical output (MW) capacity is essentially the same as the current nameplate rating.

Boiler furnace exit gas temperature and superheater st eam / reheater steam outlet temperatures may be slightly elevated during air-staged cyclone operation w ith OFA. This impact on the boiler’s operation is typically small, and within the design capabilities of th e boiler from a heat transfer and mechanical stress standpoint. This small negative impact (much less th an 1%) on the plant unit heat rate (higher Btu/kWhr) was not quantified, as the historical variation in coal heat content that influences plant unit heat rate is expected to have more significant impacts.

OFA is not expected to significantly reduce unit relia bility and availability to generate electrical power, once the amount of secondary combustion air that can be withdrawn from the cyclones is established for
consistent combustion and continuous slag tapping under substoichiomet ric air/fuel operating conditions.

### 27 11/2/2009 There may be some changes in the degradation rate of the boiler’s furnace waterwall tubes resulting from exposure of more area of the furnace walls to slight ly air-starved conditions during OFA operation. Such conditions can promote corrosion from sulfur compounds in the furnace gases being created above the cyclones and below the OFA injection ports. Due to the relatively small amounts of sulfur content in the PRB coal and the modest amount of air-staging of the existing cyclones during OFA operation, the expected change in corrosion rate of the boiler tubes should be minor. This degradation is expected to occur over many years of operation, and normally re quires periodic replacement of the deteriorated
sections of boiler furnace waterwall tubes to avoid for ced outages to repair tube leaks or failed sections. The potential change in the frequency of furnace wall t ube failures and changeouts is difficult to estimate, and has not been quantified.

For SNCR-related NO X control alternatives, the injection of a diluted urea solution requires some additional auxiliary power for heating and pumping th e liquid, and using compressed air for atomization and cooling the reagent injection nozzles/lances, on the order of 150 to 400 kW. The injection of water (used for urea dilution) into the boile r flue gas also has a small negative impact on the plant heat rate (higher Btu/kw-hr), which is approximately equal to the heat released from the reaction of the reagent
with NO X or oxygen. The impact of additional flue gas created by operation of an SNCR-related system on induced draft fan power consumption should be insignificant.

For the SCR NO X control alternative, the system requires th e same 150 to 400 kW of auxiliary power for heating and pumping the reagent (ammonia) as SNCR , and using compressed air for atomization and cooling the reagent injection nozzles/lances, on the or der of 150 to 400 kW. If a urea based reagent feed system is used, an additional 400 kW of auxiliary power is required to convert the urea to ammonia. However, the major consumer of auxiliary power for a SCR is additional induced draft fan power needed
to overcome the additional 6 to 9 inches of water column pressure drop created by the addition of catalyst and ductwork. In most cases, the addition of an SCR would require replacement of the induced draft fans and depending upon the fan and motor efficiency additional 400 to 1000 kW of auxiliary power.



### 2.4.3 NON AIR QUALITY AND OTHER ENVIRONMENTAL IMPACTS OF NO X 

### CONTROL ALTERNATIVES
Operation using OFA or SOFA systems for NO X emissions control will increase the amount of unburned carbon in the flyash produced by the boiler and collected for disposal by small increments. The potential

### 28 11/2/2009 changes in the annual amounts of flyash disposal rates are expected to be incons equential, and have not been quantified.

Operation of an SCR or SNCR system will normally create a small amount of unreacted ammonia or urea to be emitted into the flue gas. The amount of am monia slip produced depends on the amount of reagent utilization and location of the injection points. Higher NO X reduction performance involves greater amounts of reagent usage and ammonia slip. This is typically controlled to less than 10 ppmvd, especially since the possible formation of sulfates such as ammonium sulfate [(NH 4 ) 2 SO 4 ] and ammonium bisulfate [NH 4 HSO 4 ] will be more problematic at higher slip levels. Sulfur trioxide (SO 3 ) can also be formed during combustion in the boiler or convers ion in the SCR to combine with ammonia during passage through the flue gas ductwork to form the sulfates.

Some of the unreacted ammonia and other compounds discussed above will be collected with the flyash in the pulse-jet fabric filter. If a scrubber is insta lled, some of the ammonia and other compounds will be captured. These collected materials may impact th e disposal of fly ash or scrubber blow down.

Storage of ammonia reagent on-site creates the potentia l for accidents, leaks, and subsequent releases to air, ground, and surface water immediately surroun ding the facility. Regulation of storage and containment of such reagents s will be unde r the requirements of various federal Acts.



### 2.4.4 VISIBILITY IMPA IRMENT IMPACTS OF NO X 

### CONTROLS
The final impact analysis conducted was to assess the visibility impairment impact reduction for the NO X control technologies. The analysis used a baseline NO X emission rate which assumed the highest 24-hour actual emission rate for 2001-2003 as recommended by the BART guideline and listed in the Modeling
Protocol. Four CALPUFF model runs for BSP were conducted with the constant SO 2 emission rate of 0.15 lb/mmBtu, constant PM emission rate of 0.015 lb/mmBtu, and various levels of NO X control. Table
2.4-6 shows the modeled emission rates.

The difference between the modeled impacts at the 98 th percentile level from various controlled emission rates represents the visibility impairment impact reduction in deciViews (dV). Table 2.4-6 shows the results of the visibility impact modeling attributable to NO x reductions while maintaining PM and SO 2 emissions constant. A table containing the 98 th percentile results for all modeled years and Class I areas is included in Appendix A3. Combined impacts from all pollutants are addressed later in the report.

### 29 11/2/2009 TABLE 2.4-6 – Visibility Impairment Impacts from Emission Controls

NO X Control

Technique Emission Rate (lb/mmBtu) Visibility Impairment Impact

(dV) Visibility Impairment

Reduction

( Δ dV) 1 Technology Incremental

Reduction

( Δ dV) SCR with SOFA 0.10 0.170 0.487 0.218

SNCR with SOFA 0.35 0.388 0.269 0.136 Separated Over-fire Air (SOFA) 0.50 0.524 0.133 0.133 Over-fire Air (OFA) 0.65 0.657 - -

Baseline 0.86 1.079 - - 1 – Impairment reduction is from OFA levels.

The results of the baseline visibility impa irment modeling for BSP showed that NO X emissions caused a Class I area to exceed 0.5 dV for predicted visibility impairment impact (98 th percentile). Modeled visibility impairment impacts decreased with the addition of NO X controls.

The 0.5 dV value is the lowest visibility impairment impact that is considered discernible by the human eye and the EPA set this threshold as the point where a given source is considered a “contributing source” (40 CFR 51, App. Y, III.A.1.). Thus, an impairment impact of less than 0.5 dV is considered visibly indiscernible. The difference in impacts between OF A (lowest control level) and SCR (highest control level) is less than 0.5 dV, which is visibly indiscer nible. To assess the cost effectiveness of the various controls with respect to visibility improvement, the incremental cost to achieve the visibility improvement is determined and evaluated against incremental costs fo r the next most stringent alternative. Table 2.4-7 shows the costs to achieve the incremental reduction in visibility impairment.

### 30 11/2/2009 TABLE 2.4-7 – Cost for Incremental Visibility Improvement

NO X Control Technique Incremental Levelized Total Annual Cost 1 ($) Impairment Reduction

( Δ dV) Incremental Reduction

( Δ dV) Cost for Incremental Improvement ($/dV) SCR with SOFA 9,220,000 0.487 0.218 42,290,000

SNCR with SOFA 3,340,000 0.269 0.136 24,560,000 Separated Over-fire Air (SOFA) 510,000 0.133 0.133 3,830,000 Over-fire Air (OFA) 140,000 - - -

1 – Increment based upon comparison between consecutive alternatives (points) from lowest to highest.



### 2.4.5 SUMMARY OF IMPACTS OF NO X 

### CONTROLS – BSP UNIT I
Table 2.4-8 summarizes the various quantifiable impacts discussed in Sections 2.4.1 through 2.4.4 for the
NO X alternatives evaluated for BSP Unit I.

TABLE 2.4-8 – Impacts Summary for BSP Unit I NO X Controls

NO X Control Technique Emission Rate (lb/mmBtu) Levelized Total Annual

Cost ($1,000) Incremental Levelized

Total Annual Cost 1 ($1,000) Visibility Impairment Impact

(dV) Visibility Impairment Reduction (dV) Technology Incremental

Reduction

( Δ dV)
SCR with SOFA 0.10 13,210 9,220 0.170 0.487 0.218

SNCR with SOFA 0.35 3,990 3,140 0.388 0.269 0.136 Separated Over-fire Air (SOFA) 0.50 650 510 0.524 0.133 0.133
Over-fire Air (OFA) 0.65 140 140 0.657 - -

Baseline 0.86

- - 1.079 - - 1 – Increment based upon comparison between consecutive alternatives (points) from lowest to highest.

### 31 11/2/2009 NO X 

### SECTION REFERENCES:

1. “Regional Haze Regulations and Guidelines fo r Best Available Retrofit Technology (BART) Determinations”; Environmental Protection Agency; Federal Register, Volume 70, No. 128; July 6, 2005.

2. “The State of the Art in Cyclone Boiler NO X Reduction”, by O’Connor, Dave, Himes, Rick, and Facchiano, Tony (Electric Power Research Institute), presented at the EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, Atlanta, GA, August 16-20, 1999.

3. “B&W’s Advances on Cyclones NO X Control Via Fuel and Air Staging Technologies”, by Farzan, H., Maringo, G., Johnson, D. W., and Wong, D.K. (Bab cock & Wilcox, Co.), Beard, C.T. (Eastman Kodak Company), and Brewster, S.E. (Tennessee Valley Auth ority), presented at the EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, Atlanta, GA, August 16-20, 1999. Available at B&W’s internet website: http://www.babcock.com /pgg/tt/pdf/BR-1683.pdf

4. B&W experience list September 18, 2002.

5. “Reburning Projects in the Department of Energy’s Clean Coal Technology Demonstration Program”, by Mann, Al and Ruppel, Tom (Parsons Corporation), and Sarkus, Tom (National Energy Technical Laboratory), presented at the 2004 DOE-NETL Conference on Reburning for NO X Control, Morgantown, WV, May 18, 2004. A reburn-related document (an updated version of a poster from the May 18 Conference) is titled “Scorecard on Reburning 6/1/2004” by Al Mann an d Tom Ruppel, Parsons Corporation, available on-line at: http://www.netl.doe.gov/publications/proceedin gs/04/NOx/posters/Reburning%20Scorecard.pdf

6. GE Energy (formerly GE-EER) expe rience list September 29, 2005.

7. “Demonstration of Rich Reagent Injection for NO X Control in AmerenUE’s Sioux Unit 1” by Cremer, Marc A. and Adams, Bradley R. (Reaction Engineering International), Boll, David E. (AmerenUE), and O’Connor, David C. (Electric Power Research Institute), pres ented at the US DOE Conference on SCR/SNCR for NO X Control, Pittsburgh, PA, May 15-16, 2002.

8. “Evaluation of Cost Effective Non-SCR Options for NO X Control in PRB Fired Cyclone Boilers” by Cremer, Marc A., Wang, David H. and Adams, Bradley R. (Reac tion Engineering International); Boll, David E. and Stuckmeyer, Kenneth B. (AmerenUE), presented at the Western Fuels Symposium, 19 th International Conference on Lignite, Brown, and Subbituminous Coals (formerly Low-Rank Fuels), October 12-14, 2004, Billings, MT.

9. “NO X Emissions Below 0.15 lb/Mbtu Achieved in a Cyclone-Fired Bo iler Using In-Furnace Control”, by Cremer, M., Adams, B., and Chiodo, A., (Reaction Engineering International); Giesmann, C., Stuckmeyer, K., and Boyle, J. (AmerenUE), presented at the Po wergen International 2005 conference, December 6-8, 2005, Las Vegas, Nevada.

10. RJM experience list September 3, 2004.

11. “Design and Demonstration of Rich Reag ent Injections (RRI) Performance For NO X Reduction at Connectiv’s B.L. England Station” by Cremer, Marc A. and Adams, Bradley R. (Reaction Engineering International); O’Connor, David C. (Electric Power Res earch Institute); Bhamidipati, Venkata (Conectiv B.L. England Station), and Broderick, R. Gifford (RJM Corporation), presented at the 2001 US EPA/DOE/EPRI MEGA Symposium on SCR and SNCRs, Chicago, IL, August 20-23, 2001. (available from REI’s internet website http://www.reaction- eng.com/donwloads/rri_mega.pdf )

12. “Improved Rich Reagent Injection (RRI) Performance For NO X Control In Coal Fired Utility Boilers” by Cremer, Marc A. and Wang, Huafeng D. (Reaction Engineering International), Boll, David E. (AmerenUE), Schindler, Edmund (RJM Corporation) , and Vasquez, Edmundo RMT, Inc. (Alliant Energy Corp.), presented at 2003 U.S. DOE Conference on SCR and SNCR for NO X Control, Pittsburgh, PA, October 29-30, 2003.

### 32 11/2/2009 3.0 SO 2 

### BART EVALUATION In this section, steps 1 through 5 of the BA RT determination for BSP are described for SO 2 . Potentially applicable SO 2 control technologies are first identified. A brief description of the processes and their capabilities are then reviewed for availability and f easibility. A detailed technical description of each control technology is provided in Appendix B1. Subsequently, those available technologies deemed feasible for retrofit application are ranked according to nominal SO 2 control capability. The impacts analysis then reviews the estimated capital and O& M costs for each alternative, including Balance Of Plant (BOP) requirements. Following the cost de termination, the energy impacts and non-air quality impacts are reviewed for each technology. The impact based on the remaining useful life of the source is reviewed as part of the cost analysis. In the final step of the analysis, feasible and available technologies are assessed for their potential visibility impairment impact reduction capability via visibility modeling results. The results of the impact analyses are tabulated and potential BART control options are listed.



### 3.0.1 BART GUIDELINE SO 2 

### LIMITS FOR CYCL ONE-FIRED BOILERS

EPA’s recommended limit for emissions of sulfur di oxides from cyclone-fired boilers was established in
the final BART Guidelines:

“You [meaning States] must require 750 MW power plants to meet specific control levels for SO 2 of either 95 percent control or 0.15 lbs/mmBtu, for each EGU greater than 200 MW that is currently uncontrolled unless you determine that an alternative control level is justified based on a careful consideration of the statutory factors.”

40 CFR 51, App. Y, IV.E.4. While Unit I at BSP is greater than 200 MW output, it is not located at a 750 MW power plant. Thus, Unit I is not subject to presumptive limits.



### 3.1 IDENTIFICATION OF RETROFIT SO 2 

### CONTROL TECHNOLOGIES
The initial step in the BART determination is the identification of retrofit SO 2 control technologies. In order to identify the applicable SO 2 control technologies, several re ference works were consulted, including “Controlling SO 2 Emissions: A Review of Technologi es (EPA-600/R-00-093, October 2000) and the RACT/BACT/LAER Clearinghouse (RLBC). From these and other literature sources, a preliminary list of control technologies and their estimated capabilities was developed.

### 33 11/2/2009 Removal of SO 2 from flue gas can either be accomplished prior to combustion, or post combustion. The primary method for pre-combustion controls is fuel switching. Post combustion methods include wet Flue Gas Desulfurization (FGD) typically using li mestone reagent and semi-dry FGD technologies using lime reagent. Following are descriptions and t echnical analyses of the identified technologies for application to BSP Unit I. Table 3.1-1 contains the results of this effort.



### TABLE 3.1-1 – SO 2 

### Control Technologies Identified for BART Analysis

Control Technology Fuel Switching Semi-Dry Flue Gas Desulfurization Wet Flue Gas Desulfurization



### 3.2 TECHNICAL DESCRIPTION AND FEASIBLITY ANALYSIS
The second step in the BART analysis procedure is a technical feasibility analysis of the options identified in Step 1. The two concepts to consid er are the “availability” and “applicability” of each control technology. The technical and feasibility anal ysis is presented below for each identified option.



### 3.2.1 PRE-COMBUSTION FUEL TREATMENTS - FUEL SWITCHING
Fuel switching can be a viable method of fuel sulfur content reduction in certain situations. The PRB coal
listed in Table 1.2-2 is one of the lower sulfur coal s available in the U.S. a nd switching to a different lower sulfur coal (if available) would ach ieve little to no additional reduction in SO 2 emissions. Therefore, for the purpose of this BART analysis, fu el switching is not considered a viable option for SO 2 control for BSP Unit I.



### 3.2.2 POST- COMBUSTION FLUE GAS DESULFURIZATION
Two different post combusti on processes for reducing SO 2 emissions were evaluated as BART alternatives in this analysis. These include tw o well established Flue Gas Desulfurization (FGD) processes, wet and semi-dry. Commercially-available wet and semi-dry FGD processes achieve SO 2 removal by absorption of the SO 2 into an aqueous slurry which contains a neutralizing agent, normally either lime or ground limestone. Chemical reaction(s) between the SO 2 and the neutralizing agent convert
the SO 2 to a stable compound that can be readily sold or disposed of in a permitted facility.

### 34 11/2/2009 3.2.2.1 WET FLUE GAS DESULFURIZATION Wet FGD technology utilizing lime or limestone as the reagent and employing forced oxidation to produce gypsum (calcium sulfate dihydrate, CaSO 4 2H 2 O) as the byproduct is commonly applied to coalfired boilers. Absorbed SO 2 is converted to calcium sulfite and then oxidized to calcium sulfate dihydrate (gypsum) which is filtered from the scrubber solution and either disposed of in a permitted disposal facility, or possibly sold for wallboard production.

Based on commercial availability a nd applicability, wet FGD systems were found to be an acceptable
BART alternative for SO 2 emission control.



### 3.2.2.2 SEMI-DRY FLUE GAS DESULFURIZATION The most common semi-dry FGD system is the lime Sp ray Dryer Absorber (SDA) using a fabric filter for downstream particulate collection. This report addresses the spray dryer FGD process. Two other variations, the Novel Integrated Desulfurization (NID TM) and Circulating Dry Scrubber are similar technologies that achieve similar levels of control e ffectiveness. They primarily differ by the type of reactor vessel used, the method in which water and li me are introduced into the reactor and the degree of solids recycling. Due to similar nature of the diffe rent semi-dry technologies and the similar levels of control efficiency achieved by all the technologies, semi-dry technologies are grouped together for the analysis. Technical characteristics associated with the semi-dry t echnologies are described in Appendix
B1.

Based upon availability and applicability, semi-dry FGD is considered a viable alternative for SO 2 emission control.



### 3.2.3 RESULTS OF FEASIBILITY ANALYSIS

The results of the evaluation of the identified BA RT alternatives following th e feasibility analysis are
summarized in Table 3.2-1.



### TABLE 3.2-1 – SO 2 

### BART Feasibility Analysis Results

Control Technology In service on Existing Utility Boilers Commercially Available Technically Applicable To Big Stone Plant Fuel Switching Yes Yes No Wet FGD Yes Yes Yes Semi-dry FGD Yes Yes Yes

### 35 11/2/2009 3.3 EVALUATE TECHNICALLY FEASIBILE SO 2 

### CONTROL OPTIONS BY EFFECTIVENESS
The third step in the BART analysis procedure is to evaluate the control effectiveness of the technically
feasible alternatives.

Historically, wet FGD systems have operated with SO 2 control efficiency anywhere from 70% to in excess of 95%. For the purposes of this study, wet FGD performance was evaluated at presumptive
BART limit of 0.15 lb/mmBtu and also at the 95% SO 2 control as representative of the performance of this technology on PRB coal. Further technical char acteristics associated with wet FGD are described in Appendix B1.

No variation of semi-dry FGD systems has cl early demonstrated the ability to achieve SO 2 removal levels similar to wet FGD systems in the U.S. Table B-1, in Appendix B, lists many of the recent lime spray dryer system installations in the U.S. The information in Table B-1 was obtained from the RACT/BACT/LAER Clearing House. Burns & McDonnell completed a study of the emission reduction performance of existing, electri c utility, semi-dry FGD systems. 3 Information utilized for the evaluation was derived from EIA coal quality data and EPA SO 2 stack emissions and heat input data. The evaluation determined that the highest SO 2 removal efficiency maintained by semi-dry FGD on a continuous basis was just above 90%. No unit was able to maintain an efficiency of 95%. Semi-dry FGD is considered a viable alternative to achieve the presumptive SO 2 BART level, but the upper bound on SO 2 removal efficiency was set at 90% based on a review of the historic performance of this technology.

Table 3.3.1 presents the remaining BART alterna tives following the feasibility analysis ranked in descending order according to their effectiveness in SO 2 control.

### 36 11/2/2009 TABLE 3.3-1 – SO 2 

### Control Technologies Identified for BART Analysis

SO 2 Control Technique Emission Rate (lb/mmBtu) Control Percentage Hourly Emission

(lb/hr)
Wet Limestone FGD 0.043 95 241.2
Semi-dry Lime FGD 0.09 90 504.8
Presumptive Wet Limestone FGD 0.15 83 841.4
Presumptive Semi-dry Lime FGD 0.15 83 841.4
Baseline 0.86 -- 4,832.2



### 3.4 EVALUATION OF IMPACTS FOR FEASIBLE SO 2 

### CONTROLS
Step four in the BART analysis procedure is the impa ct analysis. The BART Guidelines lists four factors to be considered in the impact analysis.

• The costs of compliance;

• Energy impacts;

• Non-air quality environmental impacts; and

• The remaining useful life of the source.

Three of the four impacts required by the BART Gu idelines are discussed in the following sections. The remaining useful life of the source was determined to be greater than the project life definition in the EPA’s OAQPS Control Cost Manual (EPA/453/B-96 -001) and thus had no impact on the BART determination for BSP. In addition, the visibility im pairment impact of each alternative was evaluated as part of the impact analysis.



### 3.4.1 COST ESTIMATES
Cost estimates for the wet and semi-dry (including SDA and fabric filter) SO 2 control technologies were completed utilizing the Coal Utility Environmental Cost (CUECost) computer model (Version 1.0)
available from the EPA. The CUECost model is a spreadsheet-based computer model that was specifically developed to estimate the cost of ai r pollution control technologies for utility power plants within +/- 30 percent accuracy. The EPA released th e version of the model used for this study in

### 37 11/2/2009 February 2000. The model is availabl e for download from the EPA website at http://www.epa.gov/ttncatc1/products.html

.

The user must specify the design parameters for the air pollution control technologies in CUECost. Unit costs for consumables, labor, and other variables can be modified by the user to fit the specific situation
under evaluation. Because these models are in spreadsheet form, the calculation procedures and assumptions can be readily determined and adjusted by the experienced user as necessary to fit the unique requirements of the evaluation being conducted. The pr ogram itself is also somewhat user adjustable to compensate for local conditions. The CUECost default case is a generic facility located in Pennsylvania. Burns & McDonnell has adjusted the CUECost spread sheets as described in th e following sections to account for known facility and local conditions.

Operating information utilized as input into the mode l for the purpose of cost estimating is listed in
Tables 1.2-1 and 1.2-2. Economic information utilized as input into the model is given in Table 1.2-3. The model was run with 2008 designated as the cost b asis year because equipment cost estimating in the model is based on the Chemical Engineering Cost Index and the composite 2008 index is the latest version available. Following completion of the estim ating on a 2008 cost basis year, all costs were escalated to a 2009 basis year utilizing the infl ation rates designated in Table 1.2-3.



### 3.4.1.1 WET FGD CAPITAL COST ESTIMATE The capital cost estimate for the wet FGD system includes the SO 2 control system and major support facilities. This capital cost estimate for wet FGD app lies to either evaluated emission rate as the accuracy
of the estimate cannot account for the cost differe ntial due to minor equipment differences. The SO 2 control system cost is representative of a typical furn ish and erect contract by a wet FGD system supplier. The “typical” furnish and erect contract would not include costs for foundations. The wet FGD system cost estimated by CUECost is broken down into the major subsystems of reagent preparation, SO 2 absorption tower, dewatering systems, flue gas handl ing systems (booster fans and ductwork) and support systems. The estimated capital cost associated with a wet FGD system is $171,800,000 or a unit capital cost of $362/kW.



### 3.4.1.2 SEMI-DRY FGD CAPIT AL COST ESTIMATE
Estimated direct costs for the semi -dry FGD system include the absorbers and major support facilities. It was assumed that the existing fabric filter can be used to collect the reaction products from the semi-dry
FGD absorber. The SO 2 control system cost is representative of a typical furnish and erect contract by a

### 38 11/2/2009 lime semi-dry FGD system supplier. This capital co st estimate for semi-dry FGD applies to either evaluated emission rate as the accuracy of the estimate cannot account for the cost differential due to minor equipment differences. The “typical” furnis h and erect contract would not include costs for foundations. The system costs estimated by CUECos t are broken down into the major subsystems of reagent preparation, absorber, waste handling syst ems, flue gas handling systems (booster fans and ductwork) and support systems. The estimated capita l cost associated with a semi-dry FGD system is $141,300,000 or a unit capital cost of $297/kW.



### 3.4.1.3 O&M COST ESTIMATE The annual operating and maintenance costs (O&M) co sts are comprised of fixed costs (maintenance and labor) and variable cost (consumables). These costs were developed as part of the CUECost model and include operating labor, administrative and support la bor and maintenance. Table 3.4-1 summarizes the O&M cost estimates for the wet and semi-dry FGD systems.



### TABLE 3.4-1 – First Year O&M Cost Estimate for BSP FGD Systems

SO 2 Control System Fixed Costs ($1000/yr) Variable Costs ($1000/yr) Total O&M ($1000/yr) Wet FGD $7,000 $2,600 $9,600 Presumptive Wet FGD $7,000 $2,490 $9,490 Semi-dry FGD $4,500 $3,160 $7,660 Presumptive Semi-dry FGD $4,490 $2,990 $7,480



### 3.4.1.4 LEVELIZED TO TAL ANNUAL COST In order to compare a particular SO 2 emission reduction alternative during the cost of compliance impact analysis portion of the BART selection process, the basic methodology defined in the BART Guidelines was followed [70 FR 39167-39168]. The Leveli zed Total Annual Cost (LTAC) for these SO 2 control
alternatives was calculated based on the same economic conditions and a 30 year project life (see Section 1.3.5 of this BART evaluation for methodology details). Estimated capital costs were split evenly over a two year construction period for all alternatives a nd a present value was calculated. Table 3.4-2 shows the estimated present value capital cost and th e annualized cost for the two feasible SO 2 emission reduction technologies. These are listed in order of c ontrol effectiveness, with the highest ranked options at the top.

### 39 11/2/2009 TABLE 3.4-2 – Capital and Annualized Costs Estimated for SO 2 

### Control Alternatives

SO 2 

### Control Alternative Capital Cost 1 

### ($1000) Present Value Capital

Cost ($1,000) First Year O&M Cost ($1,000) Levelized Cost 2 

### ($1,000) Wet FGD 171,800 161,400 9,600 29,050 Presumptive Wet FGD 171,800 161,400 9,490 28,900 Semi-dry FGD 141,300 132,700 7,660 23,570 Presumptive Semi-dry FGD 141,300 132,700 7,480 23,330 1 – Installed capital cost is estimated for determination of total capital cost for a control technology, assuming maximum unit output capacity is based on 475,000 kW. 2 – Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. The Annualized O&M cost factor = 1.361 and the Capital Recovery Factor = 0.0991

The average cost effectiveness was th en determined as the LTAC divided by the annual tons of pollutant emissions that would be avoided by implementation of the respective alternative. Table 3.4-3 shows the average cost effectiveness comparison for the SO 2 control technologies. The feasible control alternatives were also compared by calculating the change in LT AC per incremental ton of pollutant removed for the next most stringent alternative (incremental cost effectiveness). This identified which alternatives produced the highest increment of expected polluta nt reduction for the estimated lowest average LTAC increment compared with the pre-control baseline emi ssion rate. The expected annual number of tons of pollutant removed versus estimated LTAC for each re maining control alternative was then plotted.



### TABLE 3.4-3 – Estimated Annual Emissions and LTAC for SO 2 

### Control Alternatives

SO 2 Control Alternative Annual SO 2 Emissions 1 (Tons/yr) Annual SO 2 Emissions Reduction 1 (Tons/yr) Levelized Total Annual

Cost ($1,000) Average Cost Effectiveness ($/ton)
Wet FGD 900 17,100 29,050 1,699
Semi-dry FGD 1,880 16,120 23,570 1,462
Presumptive Wet FGD 3,130 14,870 28,900 1,944
Presumptive Semi-dry FGD 3,130 14,870 23,330 1,569

Baseline 18,000 - - -

1 – Annual SO 2 emissions and control level based upon 8,760 hours of operation and 85% capacity factor.

### 40 11/2/2009 The comparison of the cost-effectiveness of the contro l options evaluated for BSP is shown in Figure 3.4-
1. The estimated annual amount of SO 2 removal (emission reduction) in tons per year is plotted on the abscissa (horizontal axis) and the estimated levelized total annual cost in thousands of U.S. dollars per year on the ordinate (vertical axis). 

### Figure 3.4-1 – SO 2 

### Control Cost Effectiveness

Presumptive Semi-dry FGD Wet FGD

Semi-dry FGD Presumptive Wet FGD

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000

- 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 Emissions Reduction (tpy)Total Levelized Costs ($1000)

The purpose of Figure 3.4-1 is to show the range of control and cost for the evaluated SO 2 reduction alternatives and identify the least-cost controls so that the Dominant Controls Curve (DCC) can be created. The DCC is the best fit line through the points forming the lower rightmost boundary of the data zone on a scatter plot of the LTAC versus the annual SO 2 removal tonnage for the various remaining BART alternatives. Points distinctly to the left of and ab ove this curve are inferior control alternatives per the
BART Guidelines on a cost effectiveness basis. Fo llowing a “bottom-up” graphical comparison approach,
each of the SO 2 control technologies represented by a data point to the left of and above the least cost envelope should be excluded from further analysis on a cost efficiency basis. Of the highest-performing versions of the technically feasible SO 2 control alternatives evaluated for cost-effectiveness, the data point for presumptive wet FGD is seen to be more costly for the same tons of SO 2 removed than for presumptive

### 41 11/2/2009 semi-dry FGD, semi-dry FGD or wet FGD. The presu mptive wet FGD appears to be an inferior control,
and thus should not be included on the least cost a nd DCC boundary. Figure 3.4.2 provides the DCC for the
SO 2 Controls



### Figure 3.4-2 – SO 2 

### Control Cost Effectiveness and Dominant Cost Control Curve

Semi-dry FGD Wet FGD

Presumptive Semi-dry FGD

$0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 $35,000

- 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 Emissions Reduction (tpy)Total Levelized Costs ($1000)

The next step in the cost eff ectiveness analysis for the BART SO 2 control alternatives is to review the incremental cost effectiveness between remaining least- cost alternatives. Table 3.4-4 contains a repetition
of the levelized total annual cost and SO 2 control information with presumptive wet FGD removed, and
shows the incremental cost effectiveness between each successive set of least-cost SO 2 control
alternatives. The incremental SO 2 control tons per year, divided by the incremental levelized annual cost, yields an incremental average unit cost ($/ton).

### 42 11/2/2009 TABLE 3.4-4 – Estimated Incremen tal Annual Emissions and LTAC for SO 2 

### Control Alternatives

SO 2 Control Technique Levelized Total Annual

Cost ($1,000) Annual Emission Reduction 1 (Tons/yr) Incremental Levelized

Total Annual

Cost 2 ($1,000) Incremental Annual Emission Reduction 1,2

(Tons/yr) Incremental Control Cost Effectiveness ($/ton) 3
Wet FGD 29,050 17,100 5,480 980 5,592 Semi-dry FGD 23,570 16,120 240 1,250 192

Presumptive Semi-dry FGD 23,330 14,870 23,330 14,870 1,569

1 – Annual SO 2 emissions and control level based upon 8,760 hours of operation and 85% capacity factor. 2 – Increment based upon comparison between cons ecutive alternatives from lowest to highest. 3 – Incremental control cost effectiveness is incremental LTA C divided by incremental annual emission reduction (tons per year).

As can be seen from a review of Table 3.4-4, the incremental levelized control cost effectiveness of control alternatives ranges from $192/ton to $5,592/ton. In the final BART Guidelines, the EPA state
that:

“ For example, you may be faced with a choice between two available control devices at a source, control A and control B, where control B achie ves slightly greater emission reductions. The average cost (total annual cost/total annual em ission reductions) for each may be deemed to be reasonable. However, the incremental cost (t otal annual cost A – B/total annual emission reductions A – B) of the additional control B may be very great. In such an instance, it may be inappropriate to choose control B, based on its hi gh incremental costs, even though its average cost may be considered reasonable.” (40 CFR 51, App. Y, IV.D.e.5.)

The incremental cost effectiveness is a measure of the increase in marginal co st effectiveness between two specific alternatives. The incremental cost analysis indicates that from a cost effectiveness viewpoint, the most costly alternative is wet FGD. The wet FGD control option is considered technically feasible for BSP, but incurs a significant annual (lev elized) incremental cost compared to the other
feasible SO 2 control techniques and is an in appropriate control opt ion based upon high incremental costs.

### 43 11/2/2009 3.4.2 ENERGY IMPACTS
The energy impacts of each alternative, in terms of bo th estimated kW of energy usage and the percent of total generation, are given in Table 3.4-5. The primar y energy impact of the wet FGD alternative consists of the additional electrical load resulting from pumps, blowers, booster fans, ball mills for limestone grinding and vacuum pumps for byproduct slurry dewa tering. The largest energy users for the semi-dry alternatives are pumps, atomizers and booster fans. Building HVAC and interior and exterior lighting loads are also included, but the major energy consump tion is due to the primary systems described above.



### TABLE 3.4-5 Energy Requirements of SO 2 

### BART Alternatives

BART Alternative Energy Demand

(kW) Percent of Nominal Generation Wet FGD 9,500 2.0% Semi-dry FGD 3,325 0.7%



### 3.4.3 NON-AIR QUALITY ENVIRONMENTAL IMPACTS
Non-air quality environmental impacts of the installa tion and operation of the various BART alternatives include solid and aqueous waste streams, and salable products that could result from the implementation of various BART alternatives. Captured mercury would be present in the solid waste stream from any post combustion alternative as a trace contaminant in the solid waste. Under current regulation, the presence of trace amounts of mercury would not affect its disposal.

A wet FGD system for BSP Unit I is estimated to produce approximately 6 tons per hour of solid waste. The waste stream would be composed of gypsum solids and inerts at approximately 15% moisture. Over the course of a year, the total solid waste quantity is estimated to be approximate ly 44,700 tons of gypsum
solids which would need to be landfilled.

The annual quantity of aqueous waste that would be produced by a wet FGD system is difficult to quantify because the blowdown rate from a wet FGD system is primarily a function of the dissolved
chloride levels in the absorber reaction tank. Most of the chloride reaching the scrubber is in the form of hydrochloric acid which is readily absorbed and neutralized. Based upon the use of relatively low chloride coal, one can assume the chlorides to be removed via the blowdown stream as CaCl 2 and would leave the plant in the entrained moisture in the so lid waste. No blowdown specifically for chloride disposal or special treatment of the w aste would be required under these conditions.

### 44 11/2/2009 3.4.4 VISIBILITY IMPACTS
The final impact analysis conducted was to assess the visibility impairment impact reduction for the SO 2 control technologies. The analysis used a baseline SO 2 emission rate which assumed the highest 24-hour actual emission rate for 2001-2003 as recommended by the BART guideline and listed in the Modeling
Protocol. Three CALPUFF model runs for BSP were conducted with the constant NO X emission rate of 0.65 lb/mmBtu, constant PM emission rate of 0.015 lb/mmBtu, and various levels of SO 2 control applied.
Table 3.4-6 shows the modeled emission rates.

The modeling for this analysis was performed us ing CALPUFF. The difference between the modeled impacts at the 98 th percentile level from various controlled emission rates represents the visibility impairment impact reduction in deciViews (dV). Tabl e 3.4-6 shows the results of the visibility impact modeling attributable to SO 2 reductions while maintaining NO X and PM emissions constant. The modeling results with combined impacts from a ll pollutants are addressed later in the report.

TABLE 3.4-6 – Visibility Impairment Impacts from Emission Controls

SO 2 Control Technique Emission Rate (lb/mmBtu) Visibility Impairment Impact

(dV) Visibility Impairment Reduction 1 ( Δ dV) Technology Incremental

Reduction

( Δ dV)
Wet FGD 0.043 0.611 0.046 0.009 Semi-dry FGD 0.09 0.620 0.037 0.037 Presumptive Semi-dry FGD 0.15 0.657 - -

Baseline 0.86 1.079 - - 1 – Impairment reduction is from presumptive semi-dry FGD levels.

The results of the baseline visibility impa irment modeling for BSP showed that SO 2 emissions caused a Class I area to exceed 0.5 dV for predicted visibility impairment impact (98 th percentile). Modeled visibility impairment impacts decreased with the addition of all SO 2 controls.

As previously discussed, the 0.5 dV value is the lowest visibility impairment impact that is considered discernible by the human eye and the EPA set this threshold as the point where a given source is considered a “contributing source”. Thus, an impairment impact or a difference in impairment impacts of

### 45 11/2/2009 less than 0.5 dV is considered visibly indiscernible. Because the difference in impacts between semi-dry FGD and wet FGD are 0.009 dV apart, the visibilit y improvement resulting from these controls is considered indiscernible. Where visibility improve ment between alternatives is indiscernible, the
incremental cost to achieve the indiscernible visibilit y improvement is determined and evaluated against incremental costs for the next most stringent altern ative. Table 3.4-7 shows the costs to achieve the incremental reduction in visibility impairment.

TABLE 3.4-7 – Cost for Incremental Visibility Improvement

SO 2 Control Technique Incremental Levelized Total Annual Cost 1 ($) Impairment Reduction

( Δ dV) Incremental Reduction

( Δ dV) Cost for Incremental Improvement ($/dV)
Wet FGD 5,480,000 0.046 0.009 608,900,000 Semi-dry FGD 240,000 0.037 0.037 6,500,000 Presumptive Semi-dry FGD 23,330,000 - - - 1 – Increment based upon comparison between consecutive alternatives (points) from lowest to highest.



### 3.4.5 IMPACT SUMMARY
Table 3.4-8 summarizes the various quantifiable impacts discussed in Sections 3.4.1 through 3.4.4 for the
SO 2 alternatives evaluated for BSP Unit I.

TABLE 3.4-8 – Impacts Summary for BSP Unit I SO 2 Controls

SO 2 Control Technique Emission Rate (lb/mmBtu) Levelized Total Annual

Cost ($1,000) Incremental Levelized

Total Annual Cost 1 ($1,000) Visibility Impairment Impact

(dV) Visibility Impairment Reduction (dV) Technology Incremental

Reduction

( Δ dV)
Wet FGD 0.043 29,050 5,480 0.611 0.046 0.009
Semi-dry FGD 0.09 23,570 240 0.620 0.037 0.037Presumptive Semidry FGD 0.15 23,330 23,330 0.657 - -

Baseline 0.86

- - 1.079 - - 1 – Increment based upon comparison between consecutive alternatives (points) from lowest to highest.

### 46 11/2/2009 4.0 PARTICULATE MATTER BART EVALUATION In this section, steps 1 through 5 of the BART dete rmination for BSP Unit I are described for PM. All PM control technologies are first identified. A t echnical description of the processes and their capabilities are then reviewed to determine availability and f easibility. Subsequently, those available technologies deemed feasible for retrofit application are ranked according to nominal PM control capability. The impacts analysis then reviews the estimated cost, en ergy, and non-air quality impacts for each technology. The impact of the remaining useful life of the source is reviewed as part of the cost analysis. In the final step of the analysis, the remaining technologies ar e assessed for their potential visibility impairment impact reduction capability via visib ility modeling results. The results of the complete analyses are tabulated and possible BART control options are listed.

The BART guidelines published in the Federal Register on July 6, 2005 (70 FR 39104) do not specify presumptive BART levels for particulate matter (PM) emissions. The guidelines suggest the use of PM 10 as the indicator for all PM 2.5 , because all PM 2.5 is encompassed within the PM 10 emissions fraction. (40 CFR 51, App. Y, II.A.3.) The BART guidelin es specify the distinction between coarse (PM 10 minus
PM 2.5 ) or fine (PM 2.5 ) PM in determining visibility impacts, which was made during the CALPUFF visibility modeling.

The BART Guidelines indicate that one of the evaluate d emission limits must be at least as stringent as the New Source Performance Standard (NSPS) requirement for the source (40 CFR 51, App. Y, IV.D.1). The BSP pulse-jet fabric filter meets the current NSPS emission rate 0.015 lb/mmBtu as required of new sources under 40 CFR § 60.42Da(c). All of the evalua ted control technologies used a PM emission rate
of 0.015 lb/mmBtu.



### 4.1 IDENTIFICATION OF AVAI LABLE RETROFIT PM CONTROL TECHNOLOGIES
The initial step of the BART determination is th e identification of available retrofit PM control technologies. In order to produce a list of control technologies and their estimated capabilities, sources such as the RACT/BACT/LAER Clearinghouse (RBLC) were used. The results of the investigation determined that the removal of PM from flue gas is accomplished using post combustion technology. The two most common post combustion technologies used to c ontrol PM emissions include fabric filters (FF)

### 47 11/2/2009 and electrostatic precipitators (ESPs). The existing BSP configuration contains a pulse-jet fabric filter
that was installed in 2007. Table 4.1-1 contains the results of the available PM control technologies.



### TABLE 4.1-1 PM Control Technologi es Identified for BART Analysis

Control Technology Existing Fabric Filter

New Fabric Filter COHPAC Baghouse Electrostatic Precipitator


### 4.2 TECHNICAL DESCRIPTION AND FEASIBLITY ANALYSIS
The second step in the BART analysis procedure is a technical feasibility analysis of the options identified in Step 1. This analysis is presented below for each identified option.


### 4.2.1 FABRIC FILTER (FF)
A fabric filter or baghouse removes particulate by passi ng flue gas through filter bags. A pulse-jet fabric filter (PJFF), a common type of fabric filter, consists of isolatable compartments and a tube sheet which separates the particulate laden flue gas from the clean flue gas. The flue gas passes through the PJFF by flowing from the outside of the bag to the inside up th e center of the bag through the hole in the tube sheet and out the PJFF. Fly ash particles are collected on the outside of the bags and the cleaned gas stream passes through the bag to the outlet of the fabric filter. Each filter bag alternates between relatively long periods of filtering and short periods of cleaning. During the cleaning period, fly ash that has accumulated on the bags is removed by pulses of air and falls into a hopper for disposal.

The existing fabric filter on BSP Unit I can achieve a filterable PM emission rate of 0.015 lb/mmBtu. Therefore, continuing the use of the existing fabric filt er is a technically feasible option. Replacement of the existing fabric filter with a new fabric filter is feasible, but would provide little to no increase in removal efficiency or reduction in emission rate.



### 4.2.2 COHPAC
A COmpact Hybrid PArticulate Collector (COHPAC) is a high air-to-cloth ratio pulse jet fabric filter located downstream of an existing ESP. The C OHPAC acts as a polishing device for control of particulate emissions. The difference between a COHPAC and the fabric filter described above is that a COHPAC is installed after an ESP. Because Big St one Plant does not have an ESP and already uses a fabric filter for particulate control, the u se of a COHPAC is not considered further.

### 48 11/2/2009 4.2.3 ELECTROSTATIC PRECIPITATOR (ESP)
ESPs are commonly used as the primary filterable PM control device on coal fired units. The ESP discharge electrodes generate a high voltage electrical field that gives the particulate matter an electric charge (positive or negative). The charged particl es will then be collected on a collection plate. Technical characteristics associated with ESPs are described in Appendix C1.

It is anticipated that a new ESP installed at BSP coul d achieve a PM emission rate of approximately 0.015 lb/mmBtu. Therefore, the use of a new electrostat ic precipitator is a technically feasible option. Replacement of the existing fabric filter with a new ESP is feasible, but would provide little to no increase in removal efficiency or reduction in emission rate.

The results of the feasibility analysis for the available BART alternatives are summarized in Table 4.2-1.



### TABLE 4.2-1 – PM BART Feasibility Analysis Results

Control Technology In Service on Existing Utility Boilers Commercially Available Technically Applicable To Big Stone Plant Existing Fabric Filter Yes Yes Yes New Fabric Filter Yes Yes Yes COHPAC Baghouse No 1 Yes No New ESP Yes Yes Yes 1 – While COHPAC has been installed on existing EGUs, it has not been installed in conjunction with an existing fabric filter.



### 4.3 RANK OF TECHNICALLY FEASIB LE PM CONTROL OPTIONS BY EFFECTIVENESS
The third step in the BART analysis procedure is to rank the technically feasible alternatives. However, because BSP Unit I currently uses a pulse-jet fabric fi lter that is the best technology available for particulate control and can achieve similar emission ra tes to new versions of the same technology or a new ESP replacing the existing fabric filter with new particulate control is inappropriate. Thus, the existing fabric filter is the highest ra nked and only option evaluated further.

### 49 11/2/2009 4.4 EVALUATION OF IMPACTS FOR FE ASIBLE PM CONTROLS – UNIT I
Step four in the BART analysis procedure is the im pact analysis. The BART Guidelines list four factors to be considered in the impact analysis:

• The costs of compliance;

• Energy impacts;

• Non-air quality environmental impacts; and

• The remaining useful life of the source.

Because Big Stone Plant Unit I currently uses a pulse-jet fabric filter that is the best technology available for particulate control and can achieve similar emi ssion rates to new versions of the same technology replacing the existing fabric filter with new particul ate control is inappropriate. Reviewing the four impacts listed above would provide no additional informati on regarding the type of technology to be selected to best achieve visual emissions improveme nt. However, as described in Section 1.3.6, the visibility impairment impacts due to particulate matter were included as part of the analysis.



### 4.4.1 VISIBILITY IMPACTS
A visibility analysis specifically for PM was not conduc ted due to the selection of the existing fabric filter
and the conclusion that the alternatives would result in the same emission rate. Per the BART Guidelines, because BSP has “elected to apply the most stringent c ontrols available...you need not conduct, or require the source to conduct, an air quality modeling analys is for the purpose of determining its visibility impacts.” (40 CFR 51. App. Y, IV.D.5.)



### 5.0 BART RECOMMENDATIONS The presented emission rates in this section are th e BART recommendation. However, because the accuracy of the cost estimate is + 30% and in some cases is greater than the variance of the estimated costs between control alternatives, the technology selected by Big Stone Plant to meet the BART recommendation may change. This section summariz es the analysis performed for each pollutant.

### 50 11/2/2009 5.1 NO X 

### BART
Five types of NO X control processes were identified for evalua tion. Over-fire air (OFA), separated overfire air (SOFA), Selective Non-Catalytic Reduction (SNCR), Rich Reagent Injection (RRI), Selective Catalytic Reduction (SCR) and combinations these technol ogies were evaluated for control effectiveness. Of these alternatives, stand alone SNCR and SCR were eliminated from further impacts analysis as BSP already has an OFA system in operation. A cost analysis of the remaining technologies eliminated RRI/SNCR/SOFA due to the operating costs.

Predicted visibility impairment impact s decreased significantly with the NO X control technologies. The largest incremental impact reduction came from the application of SCR. However, 

### the difference in impacts between OFA (lowest control level) and S CR (highest control leve l) is less than 0.5 dV, which is visibly indiscernible. The modeling also shows that SOFA must be applied to reduce visibility impacts due to the NO X contribution below a discernable level of 0.5 dV. An analysis of the incremental cost-effectiveness of consecutively more stringent controls was performed for BSP Unit I. Installing and operating any contro l technology beyond SOFA would co st more than 24 million dollars per dV of visibility impairment improvement and woul d only improve predicted visibility impacts by an amount that is not discernable to the human eye.

Based on the analysis, SOFA is recommended as BART for BSP Unit I. Application of SOFA for NO X control translates into a BART emission rate of 2,804 pounds per hour (0.50 pounds per million Btu of fuel heat input at 5,609 mmBtu/hr). The emission rate of 2,804 pounds per hour is recommended as the permit limit based upon a 30 day rolling average.



### 5.2 SO 2 

### BART
Three types of SO 2 control processes were identified for eval uation. While evaluating each process for
BSP SO 2 control, fuel switching was eliminated due to th e current use of low sulfur PRB coal. Wet FGD and semi-dry FGD at two levels of control were selec ted for further evaluation. A cost analysis of the remaining technologies eliminated wet FGD at the presu mptive emissions rate due to the higher cost for achieving the same emission rate as semi-dry FGD.

The difference in impacts between semi-dry FGD and wet FGD are 0.009 dV apart, 

### which is visibly
indiscernible. T he modeling also shows that semi-dry FGD at 90% control must be applied to reduce

### 51 11/2/2009 visibility impacts due to the SO 2 contribution below a discernable level of 0.5 dV. An analysis of the incremental cost-effectiveness of consecutively more stringent controls was performed for BSP Unit I. Installing and operating wet FGD over semi-dry FGD w ould cost 608 million dollars per dV of visibility impairment improvement and would only improve predicted visibility impacts by an amount that is not discernable to the human eye.

Based on the analysis, semi-dry FGD is recommended as BART for BSP Unit I. Application of semi-dry
FGD for SO 2 control translates into a BART emission ra te of 505 pounds per hour (0.09 pounds per million Btu of fuel heat input at 5,609 mmBtu/hr heat input). The emission rate of 505 pounds per hour is recommended as the permit limit based upon a 30 day rolling average.



### 5.3 PM BART
For the PM evaluation, three post combustion control technologies were selected for evaluation in addition to the existing pulse-jet fabric filter. While evaluating each technology for BSP Unit 1 PM control, a COHPAC baghouse was eliminated from the evaluation. A new fabric filter and ESP were eliminated in the analysis because the existing fabric filter provides a similar level of control effectiveness without the additional capital costs.

Because BSP Unit I currently uses a pulse-jet fabric filter that is the best technology available for particulate control and is the only technology rema ining in the analysis, the impact review can be
abbreviated.

Reviewing the cost of compliance, the energy and non-air quality environmental impacts, other pollution control equipment in use at the source, and the re maining useful life of the source would provide no additional information to change technologies from the existing fabric filter. The modeling was
conducted with a constant PM emi ssion rate of 84.1 pounds per hour.

Based upon selection of the best available PM contro l technology, maintaining the existing pulse-jet
fabric filter is recommended as BART for BSP Unit I. The corresponding BART emission rate for the existing fabric filter is 84.1 pounds per hour (0.015 pounds per million Bt u of fuel heat input at 5,609 mmBtu/hr heat input). The emission rate of 84.1 p ounds per hour is recommended as the permit limit based upon a 30 day rolling average.

### 52 11/2/2009 5.4 COMBINED BART
As indicated previously, this report presents the analysis of control technologies for NO X , SO 2 , and PM for BSP Unit I. The BART control technology reco mmendations for the individual pollutants are based upon the steps outlined in the EPA guideline. Modeling to determine visibility impairment was performed using the recommended BSP Unit I BART emission rates for NO X , SO 2 , and PM. The 98 th percentile results are provided in Table 5.4-1.

TABLE 5.4-1 – Visibility Impairment Impacts from Combined Emissions

Control Technique NO X Emission Rate (lb/hr) SO 2 Emission Rate (lb/hr) PM Emission Rate (lb/hr) Visibility Impairment Impact

(dV)
BART 2,804 505 84.1 0.493

The results of the visibility impairment modeling fo r BSP showed that the proposed BART emissions
rates for NO X , SO 2 and PM caused no Class I area to exceed 0.5 dV for predicted visibility impairment impact (98 th percentile) with Boundary Waters Canoe Area Wilderness (Boundary Waters) showing the highest predicted visibility impairment impact at 0. 493 dV for the 2007 modeled year. Modeled visibility impairment impacts decreased significantly with the addition of the BART controls.A-1 

### APPENDIX A Technical Feasibility Assessment Details for NO X Controls (A1) CUECost Input Summary (A2) Summary of Modeling Results (A3)A-2 11/2/2009 

### A1 Technical Feasibility Assessment of NO X 

### Control Alternatives

Uncontrolled NO X emissions from a coal-fired electric genera ting unit are highly dependent on type of firing method, amount of solid fuel fired per unit time and furnace volume, and the fuel’s basic combustion properties and elemental composition. The methods for reduction of such emissions:

• either prevent pollution, i.e., use inherently lower-emitting processes/practices which produce
fewer NO X emissions during the power generation process; or

• involve improvements to, or provide new add-on co ntrols that, reduce emissions after they are produced before they are emitted from the facility; or

• are combinations of inherently lo wer-emitting processes and add-on controls.

There are two basic categories of NO X emission control alternatives:

• Combustion controls; and

• Post-Combustion controls.

A significant number of the identified control options have been commercially-ava ilable, installed, and operating in many full-scale, permanent installations in the United States for five years or more. Similar to the dependency of the uncontrolled emissi ons being based on the unit type, the applicability of the control technologies are also dependent upon the type of coal-fired unit.

Combustion controls, such as over-fire air (OFA) or separated over-fire (SOFA) air are applicable to cyclone fired units. Low-NO X burners (LNBs), while commonly applie d to pulverized coal-fired boilers, are not applicable to cyclone fired units since initial combustion occurs in the barrel-shaped cyclone and not
in the furnace chamber as is the case fo r the pulverized coal-fired boiler.

Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR) are post-combustion technologies that have been applied on bituminous or sub-bituminous coal-fired boilers. Others, mostly comprised of a combination of available control technologies, are often referred to as “hybrid” or “layered” control technologies. Variations of SNCR, such as mo re recently developed “Ric h Reagent Injection” (RRI) technology, have only been demonstrated on a limited number of cyclone-fired boilers. In most of the “layered” control combination and emerging control cases, the NO X control technology has been demonstrated to be capable of controlli ng the targeted pollutant(s) on either:

• a full-scale basis, but only with temporary equipment; orA-3 11/2/2009 • a full-scale basis, with permanent equipment but in a limited number of installations.



### A1.1 Combustion Controls Nitrogen oxides (NO X ) are produced when nitrogen in the fuel and combustion air are exposed to high temperatures. Nitrogen oxide (NO) is the most predominant form of NO X emissions, along with nitrogen dioxide (NO 2 ). The formation of these compounds in utility powerplant boilers is sensitive to the method of firing and combustion controls utilized. The techniques employed for mixing the combustion air and fuel, which creates flames and high temperature com bustion products, results from the rapid oxidization of carbon, hydrogen, and other exothe rmic reactions. Cyclone-fired boilers, by design, create intense heat
release rates to melt and fluidize th e coal ash introduced into the ba rrel-shaped furnaces. This produces very high uncontrolled NO X emissions.

Combustion controls employ methods that reduce the amount of NO X emissions created in the combustion zone of the boiler prior to exhausti ng the flue gases from the furnace (upstream of the convective heat transfer zones). This results in fewer emissions that may re quire subsequent reduction from applicable post-combustion techniques.



### A1.1.1 Low-NOx Burners (LNB) LNBs are not applicable to cyclone-fired boilers 1 . This is due to the physical constraints imposed by the cyclone furnaces’ (barrels) length and diameter, and th e incompatibility with the amount of heat released and flame dispersion patterns, and insufficient amount of fine coal particles required to sustain stable combustion associated with air-staged firing of coal using low-NO X burners with pulverized fuel. This
alternative was eliminated from cons ideration for potential additional NO X emissions reductions from Big
Stone’s boiler.



### A1.1.2 Over-fire Air (OFA) or Separated Over-fire Air (SOFA) Over-fire Air (OFA) and Separated overf-ire air (S OFA) systems are commonly-applied, combustionrelated NO X emission reduction technology. Separated Ov erfire Air (SOFA) is an air-staging NO X reduction technique that is usuall y based on withholding 15 to 20 percent of the total combustion air conventionally supplied to the firing zone. It is believed that Big Stone’s boiler would be a suitable
candidate for the installation of SOFA and for additional NO X control, if this is necessary.A-4 11/2/2009 For typical cyclone coal-fired boilers, the operation of SOFA involves diverting approximately 20 percent of the secondary combustion air from the burner barrels , forcing the cyclones to operate fuel-rich. The diverted combustion air is then injected in the upper furnace, where combustion is completed.

SOFA can achieve significant NO X reduction, typically 30 to 70 percent on typical cyclone coal-fired boilers with this typical amount of air staging. A summary of several of the first OFA retrofits to cyclone-fired boilers is described in published technical papers 1,2 . At least thirty nine existing cyclonefired boilers, firing eastern bituminous, midwestern bituminous, and western subbituminous (“Powder River Basin”) coals in units ranging in size from 50 to 1150 MW, have been re trofitted with commercial
SOFA since 1998 3 . Additional cyclone-fired boilers have in stalled separated overfire air systems in conjunction with commercial fuel reburn retrofit projects 4 . Other NO X emission reduction demonstration projects, primarily sponsored by U.S. Department of Energy National Energy Technology Laboratory’s Clean Coal Technology Program 5 , and other fuel reburn retrofit projects 6 have also installed separated overfire air on cyclone boilers.

A basic form of separated overfire air (SOFA) can be applied and installed on Big Stone. There are potential impacts and limitations unique to cyclone boile rs firing PRB that should be recognized as part of this emission reduction technology application.

A key aspect of successfully applying and operating sepa rated overfire air on a cyclone-fired boiler is the ability to maintain adequate molten coal ash (slag) fo rmation and flow within th e barrels and slag taps. As secondary combustion air is diverted, less heat is released during air-staged combustion from the
intentional formation of carbon monoxi de, and temperatures within the cyclones decreases. The degree to which the cyclones can be operated with less than th eoretical (stoichiometric) combustion air directly
contributes to less NO X formation and further in-furnace emission reduction but also risks solidification
of the molten coal ash. There are several challe nges anticipated for implementing SOFA, primarily involving the ability to route large SOFA ductwor k for diverting secondary air from the windboxes.
These are believed to be solvable . Using a basic SOFA system, assuming a sustainable level of NO X emissions control with the operation of modestly air-staged cyclone furnaces with suitable combustion controls, is considered feasible for Big Stone.A-5 11/2/2009 

### A1.2 Post-Combustion Controls Post-combustion controls deal with techniques that th ermally or chemically-treat the flue gases to reduce
NO X emissions after they have exited the boiler’s lowe r furnace. In the case of Big Stone Unit I, this primarily involves forms of selective catalytic reduction (SCR) and selective non-catalytic reduction (SCR) technologies.



### A1.2.1 Selective Non-Catalytic Reduction (SNCR) Selective Non-Catalytic Reduction (SNCR) technologies are all post-combustion types of boiler NO X emission controls. These technologies promote NO X reduction with chemical reactions that are insensitive to the specific fuel ty pes whose combustion products are being treated. While the large majority of boiler applications to date have been on pulverized coal-fired units burning eastern bituminous fuels, SNCR has been used to reduce NO X emissions on utility boilers burning eastern bituminous coal, midwestern bituminous coal, and, to a lesser extent, western subbituminous coal. SNCR has also been used with fuel oil and natural g as-fired units. SNCR (and hydrocarbon-enhanced SNCR) technologies can each be applied to fossil fuel-fired boile rs with or without the use of a SOFA system. The ability to apply SNCR does not appear to be depende nt directly on the type of burners (wall-fired, tangentially-fired, and cyclone-fired) employed in the boilers where it has been installed, with or without overfire air in full operation. Operation at these plants has demonstrated that SNCR can decrease NO X emissions as much as 15-40% at full load, most typically between 25-35%. 7, 8, 9

In the conventional SNCR process, urea or ammonia is injected into the boiler in a region where the combustion gas temperature is in the 1700 to 2100 degrees F range. Under these temperature conditions, the urea reagent [CO(NH 2 ) 2 ] or ammonia [NH 3 ] reacts with the nitrogen oxides [NO X ], forming elemental nitrogen [N 2 ] and water, reducing NO X emissions.

SNCR can be applied and installed on the Big Stone boile r in combination with basic or separated form of over-fire air (OFA).



### A1.2.2 Rich Reagent Injection (RRI) Rich Reagent Injection (RRI) is a NO X control technology that has been developed and demonstrated specifically for use on cyclone boilers. Rich Reag ent Injection is an SNCR process that involves the injection of urea into the lower furnace between th e cyclones and the SOFA ports. RRI targets a highA-6 11/2/2009 temperature, fuel-rich zone within the boiler-furn ace environment immediately adjacent to the cyclone burners, and requires temperatures in the range of 2400 to 3100 degrees F. The combustion gases must be essentially devoid of free oxygen, in order to avoid oxidizing the nitrogen contained in the injected reagent, which would create NO X emissions instead of reducing them.

The RRI process for NO X reduction must be used in conjuncti on with air-starved (substoichiometric staged-air) cyclone combustion resu lting from the installation and operation of an OFA system. The cyclones’ air/fuel stoichiometry must be carefully co ntrolled to maintain fuel-rich conditions for the RRI process to be effective. This introduces oxygen in th e same vicinity as the reagent injection ports, and will disrupt the beneficial action of the fuel-rich zone and amine reagent to significantly reduce NO X emissions. Without SOFA, RRI will not contribute positively to NO X emissions control on Big Stone Unit I boiler. This places a large emphasis on the expe cted performance of SOFA in order for RRI to be successful in producing significant additional NOx em issions reduction on PRB-fired cyclone boilers.

The three zones of a Rich Reagent Injection SNCR app lication on a boiler with separated overfire air are
shown as a sectional side elevation view of the furnace 11 in Figure A.1-4.A-7 11/2/2009 

### Figure A.1-4 Rich Reagent Injection A pplication on Boiler With Overfire Air 10

The Rich Reagent Injection (RRI) process has been successfully demonstrated on at least two cyclonefired boilers, with the most recent installation at Ameren’s Sioux Unit I, a 500 MW boiler firing a blend
of PRB and midwestern bituminous coals.

The NO X emission reduction reagent injection for RRI processes must be precisely located and carefully controlled to be effective. Opera tion outside of the required operati ng ranges can even result in increased
NO X emissions. Extensive computational fluid dynami c (CFD) simulations are needed to determine the optimum injection points. Boiler operating conditions will change with unit load and varying fuel characteristics. The RRI process control systems must be able to adjust for these changing conditions. 

## 2400-3100 o 

## F
NOx N 2



## Chemical Injection NH i 

## NCO

Staged Combustion Zone Fuel Rich Zone Burnout Zone 

## OFA

Fuel 2400-3100 o 

## F
NOx N 2



## Chemical Injection NH i 

## NCO

Staged Combustion Zone Fuel Rich Zone Burnout Zone 

## OFA

FuelA-8 11/2/2009 RRI has the potential to provide a moderate degree of NO X reduction on coal-fired cyclone boilers. Rich Reagent Injection can be applied and installed on Big Stone boiler only with separated over-fire air (SOFA).



### A1.2.3 Selective Catalytic Reduction (SCR)
The lowest NOx emission levels from coal-fired utilit y boilers are typically achieved by installing and operating selective catalytic reduction (SCR) technology. In the SCR process, the gas stream is passed through a catalyst bed in the presence of ammonia to reduce NO X to molecular nitrogen and water. The process is termed “selective” because the ammonia preferentially reacts with the NO X rather than with the oxygen in the flue gas. A catalyst is used to enhance NO X reduction and ammonia utilization at appropriate flue gas temperatures. SCR is usually ap plied to flue gas in the 600°F to 750°F temperature range. There are variations in the SCR process for coal -fired boilers that mostly involve locations in the flue gas path where the catalyst is pl aced in order to promote the desired NO X emission reduction effect.
These are described below.

For coal-fired boilers, a conventiona l SCR reactor utilizes readily-available catalyst materials and reagent
in the form of ammonia. A conventional SCR react or is commonly installed in a high-dust, hot-side arrangement, located between the economizer outlet and ai r heater inlet, where the flue gas temperature is within the desired operating range for the SCR catalyst.

A schematic graphic diagram for a conventional high- dust, hot-side SCR system on a boiler with a flue gas desulfurization system and stack gas reheat is provided in Figure A.1-5.A-9 11/2/2009 

### Figure A.1-5 Conventional SCR Arrangement with FGD Scrubber Outlet Reheat

(figure copied from Wheelabrator Ai r Pollution Control literature)A-10 11/2/2009 SCR technology has been installed on several pulveri zed coal and cyclone boilers firing bituminous and
subbituminous coal in the United States. The in stallation of SCR systems has been completed on approximately 22 cyclone units. Several SCR installa tions have been retrofit on existing cyclone-fire boilers burning western subbituminous coal (or PRB blended with midwestern bituminous coal). For cyclone coal-fired utility boilers retrofitted with S CR technology, all were originally designed to burn
bituminous coal.

Two byproducts from the high-dust, hot-side SCR process are ammonia slip and SO 3 :

• Ammonia Slip : Slip is ammonia that is unreacted in the NO x emission reduction process. Maximum ammonia slip for a gas fired unit is usually 10 ppmvd whereas, on a coal fired unit, ammonia slip below 2 ppm is desired. For cer tain applications, this concentration can be problematic, therefore requiring more catalyst to reduce slip. Most new SCR applications have ammonia slip guaranteed at a 2 ppmvd maximum for an initial operating period, and are expected to continue to operate at these low ammonia slip s levels beyond the end of the initial period.

• SO 3 : Due to the composition of typical SCR cat alysts, a small percentage of inherent SO 2 will be
oxidized to SO 3 . This oxidation can be controlled by cat alyst selection and can be less than 1%.
SO 2 to SO 3 oxidation must be carefully controlled to avoid creating SO 3 levels sufficiently high to raise the possibility of air heater fouling. A unit firing high-sulfur coal with SCR technology is especially vulnerable to SO 2 oxidation and ammonia slip-related fouling problems. The deposition and fouling is due to formation of solid ammonium sulfate ((NH 4 ) 2 SO 4 ) and liquid ammonium bisulfate (NH 4 HSO 4 ). The most important design variable is optimizing the catalyst selection and amount of catalyst that will reduce NO X emissions, control ammonia slip, and minimize SO 2 oxidation.

As posted on Electric Power Research Institute Inc.’s ( EPRI’s) website regarding the impact of coal type on SCR catalyst life and performance, a recent EPRI study 11 produced field data analyzed from an “InSitu Mini SCR Reactor” system installed in a typical “high-dust” location at seven different test sites, including four firing PRB coal, one firing Texas lignite, one firing high-sulfur eastern bituminous coal, and one firing a PRB/eastern bituminous coal blend. The PRB/bituminous coal blend test was performed at AmerenUE’s Sioux Station, on one of the two 500 MW cyclone-fired boilers. This study found that the cyclone unit firing the PRB/bituminous coal bl end exhibited the fastest rate of catalyst activity degradation. Also, the higher deactivation rates seen at this site were due to economizer exit flue gas temperatures being significantly higher than at the other sites. A comparison of the Texas lignite and oneA-11 11/2/2009 of the PRB-fired sites of two different catalysts’ deac tivation was more a function of trace elements in the flue gas and flyash than the specific catalyst type or formulation.

Based upon this technical assessment that looked at th e various design and operational issues associated with the installation of hot-side, high-dust SCR technol ogy, SCR is considered a feasible option for Unit I at Big Stone.A-12 11/2/2009 References for Appendix A1:

1. “The State of the Art in Cyclone Boiler NOx Reduction”, by O’Connor, Dave, Himes, Rick, and Facchiano, Tony (Electric Power Research Institute), presented at the EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, Atlanta, GA, A ugust 16-20, 1999.

2. “B&W’s Advances on Cyclones NOx Control Via Fuel and Air Staging Technologies”, by Farzan, H., Maringo, G., Johnson, D. W., and Wong, D.K. (Babcock & Wilcox, Co.), Beard, C.T. (EastmanKodak Company), and Brewster, S.E. (Tennessee Valley Authority), presented at the EPRI-DOEEPA Combined Utility Air Pollutant Control Sy mposium, Atlanta, GA, August 16-20, 1999. Available at B&W’s internet website: http://www.babcock.com/pgg/tt/pdf/BR-1683.pdf

3. Burns & McDonnell internal database for NO X reduction projects.

4. B&W experience list September 18, 2002.

5. “Reburning Projects in the Department of En ergy’s Clean Coal Technology Demonstration Program”, by Mann, Al and Ruppel, Tom (Pars ons Corporation), and Sarkus, Tom (National Energy Technical Laboratory), presented at the 2004 DOE-NETL Conference on Reburning for NOx Control, Morgantown, WV, May 18, 2004. A reburn-related document (an updated version of a poster from the May 18 Conference) is titled “Sco recard on Reburning 6/1/2004” by Al Mann and Tom Ruppel, Parsons Corporation, available on-line at: http://www.netl.doe.gov/publications/proceedi ngs/04/NOx/posters/Reburning%20Scorecard.pdf

6. GE Energy (formerly GE-EER) experience list September 29, 2005.

7. Fuel Tech experience list dated 1/28/2005.

8. SNCR “White Paper”, Institute of Clean Air Companies, Inc. (ICAC), SNCR Committee, May 2000, Fuel Tech website http://www.fueltechnv.com/pdf/TPP-534.pdf

.

9. RJM experience list September 3, 2004.

10. “Improved Rich Reagent Injection (RRI) Perform ance For NOx Control In Coal Fired Utility Boilers” by Cremer, Marc A. and Wang, Huafeng D. (Reaction Engineering International), Boll, David E. (AmerenUE), Schindler, Edmund (RJM Co rporation), and Vasquez, Edmundo RMT, Inc. (Alliant Energy Corp.), presented at 2003 U.S. DOE Conference on SCR and SNCR for NOx Control, Pittsburgh, PA, October 29-30, 2003.

11. “Ash Impacts on SCR Catalyst Performance”, Energy & Environmental Research Center (EERC) of the University of North Dakota”, Benson, Steven A., Ph.D., October 2005.11/2/2009 

### A2 CUECost Input SummaryCUECost - Air Pollution Control Systems Economics Spreadsheet 

## APC Technology Choices

Description Units Case 1 Case 2 Case 3

FGD Process Integer 1 1 1 (1 = LSFO, 2 = LSD) Particulate Control Integer 1 1 1 (1 = Fabric Filter, 2 = ESP) NOx Control Integer 1 1 1 (1 = SCR, 2 = SNCR, 3 = LNBs, 4 = NGR)



## INPUTS

Description Units Case 1 Case 2 Case 3


### General Plant Technical Inputs

Location - State Abbrev. SD SD SD MW Equivalent of Flue Gas to Control System MW 475 475 475 Net Plant Heat Rate Btu/kWhr 11,809 11,809 11,809 Plant Capacity Factor % 85% 85% 85% Total Air Downstream of Economizer % 120% 120% 120% Air Heater Leakage % 10% 10% 10% Air Heater Outlet Gas Temperature °F 320 320 320 Inlet Air Temperature °F 70 70 70 Ambient Absolute Pressure In. of Hg 28.75 28.75 28.75 Pressure After Air Heater In. of H2O -15 -15 -15 Moisture in Air lb/lb dry air 0.013 0.013 0.013 Ash Split: Fly Ash % 80% 80% 80% Bottom Ash % 20% 20% 20% Seismic Zone Integer 0 0 0 Retrofit Factor Integer 1.5 1.5 1.5 (1.0 = new, 1.3 = medium, 1.6 = difficult) Select Coal Integer 1 1 1 Is Selected Coal a Powder River Basin Coal? Yes / No Yes Yes Yes


### Economic Inputs

Cost Basis -Year Dollars Year 2008 2008 2007 Sevice Life (levelization period) Years 30 30 30 Inflation Rate % 3% 3% 3% After Tax Discount Rate (current $'s) % 9% 9% 9% AFDC Rate (current $'s) % 11% 11% 11% First-year Carrying Charge (current $'s) % 10% 10% 10% Levelized Carrying Charge (current $'s) % 10% 10% 10% First-year Carrying Charge (constant $'s) % 10% 10% 10% Levelized Carrying Charge (constant $'s) % 10% 10% 10% Sales Tax % 6% 6% 0% Escalation Rates: Consumables (O&M) % 3% 3% 3%

BSGS 102709 CUECost Rev15PrelimR4.XLS, Input & Calculation Summary 1 11/2/2009, 1:01 PMCUECost - Air Pollution Control Systems Economics Spreadsheet Capital Costs: Is Chem. Eng. Cost Index available? Yes / No Yes Yes Yes If "Yes" input cost basis CE Plant Inde x Integer 575.4 575.4 575.4 If "No" input escalation rate. % 3% 3% 3% Construction Labor Rate (Not Used N Calc) $/hr $35 $35 $35 Prime Contractor's Markup % 3% 3% 3% Operating Labor Rate $/hr $48 $48 $48 Power Cost Mills/kWh 25 25 25 Steam Cost $/1000 lbs 3.5 3.5 3.5


### Limestone Forced Oxidation (LSFO) Inputs

Any By-Pass around the scrubber 2 2 2 (1 = yes, 2 = no) Percent of By-Passed Gas % 0.0% 0.0% 0.0%
SO2 Removal Required % 95.0% 83.0% 95.0% L/G Ratio gal / 1000 acf 125 125 110 Design Scrubber with Dibasic Acid Addition? Integer 2 2 2 (1 = yes, 2 = no) Adiabatic Saturation Temperature °F 132 132 135 Reagent Feed Ratio Factor 1.05 1.05 1.03 (Mole CaCO3 / Mole SO2 removed) Scrubber Slurry Solids Concentration Wt. % 15% 15% 15% Stacking, Landfill, Wallboard Integer 2 2 3 (1 = stacking, 2 = lanfill, 3 = wallboard) Number of Absorbers Integer 1 1 1 (Max. Capacity = 700 MW per absorber) Absorber Material Integer 1 1 1 (1 = alloy, 2 = RLCS) Absorber Pressure Drop in. H2O 6 6 6 Reheat Required ? Integer 2 2 2 (1 = yes, 2 = no) Amount of Reheat °F 0 0 0 Reagent Bulk Storage Days 60 60 30 Reagent Cost (delivered) $/ton $24 $24 $12 Landfill Disposal Cost $/ton $4 $4 $30 Stacking Disposal Cost $/ton $2 $2 $6 Credit for Gypsum Byproduct $/ton $0 $0 $0 Maintenance Factors by Area (% of Installed Cost) Reagent Feed % 3% 3% 3% SO2 Removal % 3% 3% 3% Flue Gas Handling % 3% 3% 3% Waste / Byproduct % 3% 3% 3% Support Equipment % 3% 3% 3% Contingency by Area (% of Installed Cost) Reagent Feed % 20% 20% 20% SO2 Removal % 20% 20% 20% Flue Gas Handling % 20% 20% 20% Waste / Byproduct % 20% 20% 20% Support Equipment % 20% 20% 20% General Facilities by Area (% of Installed Cost) Reagent Feed % 10% 10% 10% SO2 Removal % 10% 10% 10%

BSGS 102709 CUECost Rev15PrelimR4.XLS, Input & Calculation Summary 2 11/2/2009, 1:01 PMCUECost - Air Pollution Control Systems Economics Spreadsheet Flue Gas Handling % 10% 10% 10% Waste / Byproduct % 10% 10% 10% Support Equipment % 10% 10% 10% Engineering Fees by Area (% of Installed Cost) Reagent Feed % 10% 10% 10% SO2 Removal % 10% 10% 10% Flue Gas Handling % 10% 10% 10% Waste / Byproduct % 10% 10% 10% Support Equipment % 10% 10% 10%


### Lime Spray Dryer (LSD) Inputs

SO2 Removal Required % 90% 83% 90% Adiabatic Saturation Temperature °F 132 132 135 Flue Gas Approach to Saturation °F 20 20 25 Spray Dryer Outlet Temperature °F 152 152 160 Reagent Feed Ratio Factor 0.92 0.85 0.92 (Mole CaO / Mole Inlet SO2) Recycle Rate Factor 30 30 30 (lb recycle / lb lime feed) Recycle Slurry Solids Concentration Wt. % 35% 35% 35% Number of Absorbers Integer 2 2 1 (Max. Capacity = 300 MW per spray dryer) Absorber Material Integer 1 1 2 (1 = alloy, 2 = RLCS) Spray Dryer Pressure Drop in. H2O 5 5 5 Reagent Bulk Storage Days 60 60 30 Reagent Cost (delivered) $/ton $145 $145 $60 Dry Waste Disposal Cost $/ton $4 $4 $30 Maintenance Factors by Area (% of Installed Cost) Reagent Feed % 2% 2% 2% SO2 Removal % 2% 2% 2% Flue Gas Handling % 2% 2% 2% Waste / Byproduct % 2% 2% 2% Support Equipment % 2% 2% 2% Contingency by Area (% of Installed Cost) Reagent Feed % 20% 20% 20% SO2 Removal % 20% 20% 20% Flue Gas Handling % 20% 20% 20% Waste / Byproduct % 20% 20% 20% Support Equipment % 20% 20% 20% General Facilities by Area (% of Installed Cost) Reagent Feed % 10% 10% 10% SO2 Removal % 10% 10% 10% Flue Gas Handling % 10% 10% 10% Waste / Byproduct % 10% 10% 10% Support Equipment % 10% 10% 10% Engineering Fees by Area (% of Installed Cost) Reagent Feed % 10% 10% 10% SO2 Removal % 10% 10% 10% Flue Gas Handling % 10% 10% 10% Waste / Byproduct % 10% 10% 10% Support Equipment % 10% 10% 10%

BSGS 102709 CUECost Rev15PrelimR4.XLS, Input & Calculation Summary 3 11/2/2009, 1:01 PMCUECost - Air Pollution Control Systems Economics Spreadsheet 

### Particulate Control Inputs

Outlet Particulate Emission Limi t lbs/MMBtu 0.015 0.015 0.015 Fabric Filter: Pressure Drop in. H2O 9 9 9 Type (1 = Reverse Gas, 2 = Pulse Jet) Integer 1 2 1 Gas-to-Cloth Ratio ACFM/ft 2 2.3 3.5 2.3 Bag Material (RGFF fiberglass only) Integer 1 3 1 (1 = Fiberglass, 2 = Nomex, 3 = Ryton) Bag Diameter inches 12 6 12 Bag Length feet 30 26 30 Bag Reach 3 3 3 Compartments out of Service % 10% 10% 10% Bag Life Years 5 3 5 Maintenance (% of installed cost) % 5% 5% 5% Contingency (% of installed cost) % 20% 20% 20% General Facilities (% of installed cost) % 10% 10% 10% Engineering Fees (% of installed cost) % 10% 10% 10% ESP: Strength of the electric field in the ESP = E kV/cm 10.0 10.0 10.0 Plate Spacing in. 12 12 16 Plate Height ft. 36 36 36 Pressure Drop in. H2O 3 3 2 Maintenance (% of installed cost) % 5% 5% 5% Contingency (% of installed cost) % 20% 20% 20% General Facilities (% of installed cost) % 10% 10% 10% Engineering Fees (% of installed cost) % 10% 10% 10% 

### NOx Control Inputs

Selective Catalytic Reduction (SCR) Inputs

NH3/NOX Stoichiometric Ratio NH3/NOX 0.8 0.8 0.800641299 NOX Reduction Efficiency Fraction 0.80 0.84 0.70 Inlet NOx lbs/MMBtu 0.5 0.65 0.15 Space Velocity (Calculated if zero) 1/hr 0 0 0 Overall Catalyst Life years 2 2 3 Ammonia Cost $/ton 325 325 325 Catalyst Cost $/ft3 150 150 150 Solid Waste Disposal Cost $/ton 11.48 11.48 11.48 Maintenance (% of installed cost) % 1.5% 1.5% 1.5% Contingency (% of installed cost) % 20% 20% 20% General Facilities (% of installed cost) % 5% 5% 5% Engineering Fees (% of installed cost) % 10% 10% 10% Number of Reactors integer 2 2 2 Number of Air Preheaters integer 2 2 2
Selective NonCatalytic Reduction (SNCR) Inputs

Reagent 1:Urea 2:Ammonia 1 1 1 Number of Injector Levels integer 3 3 3 Number of Injectors integer 18 18 18 Number of Lance Levels integer 0 0 0

BSGS 102709 CUECost Rev15PrelimR4.XLS, Input & Calculation Summary 4 11/2/2009, 1:01 PMCUECost - Air Pollution Control Systems Economics Spreadsheet Number of Lances integer 0 0 0 Steam or Air Injection for Ammonia integer 1 1 1 NOX Reduction Efficiency Fraction 0.30 0.60 0.46 Inlet NOx lbs/MMBtu 0.5 0.5 0.65 NH3/NOX Stoichiometric Ratio NH3/NOX 2 4 2 Urea/NOX Stoichiometric Ratio Urea/NOX 2 4 2 Urea Cost $/ton 380 380 380 Ammonia Cost $/ton 325 325 325 Water Cost $/1,000 gal 0.407 0.407 0.407 Maintenance (% of installed cost) % 1.5% 1.5% 1.5% Contingency (% of installed cost) % 20% 20% 20% General Facilities (% of installed cost) % 5% 5% 5% Engineering Fees (% of installed cost) % 10% 10% 10%
Low NOX Burner Technology Inputs

NOX Reduction Efficiency fraction 0.35 0.35 0.35 Boiler Type T:T-fired, W:Wall T T T

Retrofit Difficulty L:Low, A:Average, H:High A A A Maintenance Labor (% of installed cost) % 0.8% 0.8% 0.8% Maintenance Materials (% of installed cost) % 1.2% 1.2% 1.2%
Natural Gas Reburning Inputs

NOX Reduction Efficiency fraction 0.61 0.61 0.61 Gas Reburn Fraction fraction 0.15 0.15 0.15 Waste Disposal Cost $/ton 11.48 11.48 11.48 Natural Gas Cost $/MMBtu 2.31 2.31 2.31 Maintenance (% of installed cost) % 1.5% 1.5% 1.5% Contingency (% of installed cost) % 20% 20% 20% General Facilities (% of installed cost) % 2% 2% 2% Engineering Fees (% of installed cost) % 10% 10% 10% 

### Sulfuric Acid Mist Control Inputs

BSGS 102709 CUECost Rev15PrelimR4.XLS, Input & Calculation Summary 5 11/2/2009, 1:01 PM11/2/2009 

### A3 Summary of Modeling Results

# Modeling Report for a BART Assessment of the Big Stone I Coal-Fired Power Plant, Big Stone City, South Dakota Part 2 – BART Controls

October 2009

Prepared For:
Big Stone I Otter Tail Power Company, Big Stone City, South Dakota

Prepared By:
TRC Environmental Corporation 650 Suffolk Street Lowell, Massachusetts 01854 (978) 970-5600i 

### TABLE OF CONTENTS
Page

1. INTRODUCTION .................................................................................................................. ........ 1-1
2. SOURCE DESCRIPTION ............................................................................................................ 2-1
3. GEOPHYSICAL AND METEOROLOGICAL DATA, AIR QUALITY MODELING OPTIONS ....................................................................................................................... ................. 3-1
4. RESULTS ....................................................................................................................... ................ 4-1
5. REFERENCES .................................................................................................................... ........... 5-1



### LIST OF FIGURES
Page
Figure 3-1. Terrain elevations for the CALMET and CALPUFF modeling domain at 4 km resolution. The locations of the Big Stone f acility and Class I areas are also shown. ..... 3-3



### LIST OF TABLES
Page

Table 2-1: Point Source Parame ters and Emission Rates .................................................................. 2-2 Table 2-2: PM 10 Size Distri bution ..................................................................................................... 2-3 Table 2-3: PM 10 Speciation and Size Distribution ............................................................................. 2-4 Table 4-1. Visibility Impacts for 2002 ........................................................................................ ...... 4-2 Table 4-1. Visibility Imp acts for 2002 (continued). .......................................................................... 4-3 Table 4-2. Visibility Impacts for 2006. ....................................................................................... ...... 4-4 Table 4-2. Visibility Imp acts for 2006 (continued). .......................................................................... 4-5 Table 4-3. Visibility Impacts for 2007. ....................................................................................... ...... 4-6 Table 4-3. Visibility Imp acts for 2007 (continued). .......................................................................... 4-7Introduction 1-1 

## 1. INTRODUCTION

TRC Environmental Corporation has conducted a site-specific BART (Best Available Retrofit Technology) modeling assessment of the Big Stone I coal-fired power plant facility located near Milbank and Big Stone City in South Dakota to de termine if this facility is subject to BART controls on emissions. Part I of the Octobe r 2009 report presented a modeling assessment of baseline emissions from the Big Stone I power plan t facility to determine whether the facility is subject to BART controls. This report (Part 2) represents the results of 10 emission control scenarios.
On July 6, 2005 the U.S. Environmental Protection Agency (U.S. EPA) published in the Federal Register the “Regional Haze Regulations and Gu idelines for Best Available Retrofit Technology (BART) Determinations” (40 CFR Part 51). Th e regional haze rule requires States to submit implementation plans (SIPs) to address regiona l haze visibility impairment in 156 Federallyprotected parks and wilderness areas, commonly referred to as “Class 1 Areas”. The final rule addresses BART-eligible sources, which are defined as sources that have the potential to emit 250 tons or more of a visibility-impairing air po llutant, were put in place between August 7, 1962 and August 7, 1977 and whose opera tions fall within one or more of 26 specifically listed source categories, of which Coal-Fired Power Plants are one.
The modeling described in this report is consiste nt with modeling described in baseline report. All CALMET/CALPUFF switches used in this BART analysis are identical with the switches used and described in previous report. In this report, ten BART control scenarios were analyzed and results of these modeling presented.
The purpose of the modeling is to assess the visibility impacts of sulfur dioxide (SO 2 ), particulate matter (PM) and nitrogen oxides (NO x ) emissions from the Big Stone I boiler and compare the impacts to the 0.5 change in deciview threshold at all the federally mandatory Class I areas. Since there is no Class I area within the 300 km radius us ually applied, the South Dakota Department of Environment and Natural Resources requested that the Class I areas between 300 km and up to 625 km away from the Big Stone I facility sources be modeled. A total of eight Class I areas are located between these distances: two wilderness areas: Boundary Waters Canoe Area Wilderness and Rainbow Lake Wilderness, one National W ildlife Refuge (NWR): Lostwood and five National Parks: Voyageurs NP, Theodore Rooseve lt NP, Badlands NP, Wind Cave NP and Isle Royale NP. However, Rainbow Lake Wilderness is one of two Class I areas where the visibility analysis is not required ( http://www.dnr.state.wi.us/org /aw/air/modeling/ psd.htm ), so it is not included in the modeling analysis. The MM5 dat asets distributed by WRAP did not extend far enough in the East to include the Isle Royale NP or cover all of the Boundary Waters Class I area. The re-extracted MM5 data for 2002 and ne w MM5 domains for 2006 and 2007 include these

areas.
The CALMET and CALPUFF non-steady-state models (Scire et al., 2000a,b) are recommended by the U.S. EPA ( Federal Register , 6 July 2005) to perform source-specific subject-to-BARTIntroduction 1-2 screening. The CALPUFF system was therefore used for this modeling analysis. The U.S. EPA has promulgated the CALPUFF modeling system as a Guideline Model for Class I impact assessments and other long range transport appli cations or near field applications involving complex flows (U.S. EPA, 2000), and the mode l is recommended by both the Federal Land Managers (FLM) Air Quality Workgroup (FLAG, 2000) and the Interagency Workgroup on Air Quality Modeling (IWAQM, 1998). The CALPUFF m odeling system is also recommended in new proposed guidance by the FLMs (FLAG, 2008). On August 31, 2009 EPA issued new recommendations on CALMET switch settings. The current modeling is based on the August 2009 recommendations.
The Big Stone I BART modeling analysis was pe rformed with the EPA-approved Version 5.8 of the CALMET and CALPUFF models. Version 6.221 of CALPOST was used because it contains the FLM-approved implementation of Method 8 (FLA G, 2008), but in other respects is identical to the EPA-approved Version 5.6394.
CALMET is a diagnostic meteorological model that produces three-dimensional wind fields based on parameterized treatments of terrain e ffects such as slope flows and terrain blocking effects. Normally, meteorological observations are blended with gridded data from the NCARPSU Mesoscale Model, Version 5 (MM5). For th is evaluation, MM5 data were generated by TRC with a 12-km grid spacing for two years ( 2006 and 2007) to define the initial guess wind fields. For 2002, 12-km MM5 data were re-extr acted from the EPA MM5 dataset to cover entire region including the Isle Royale NP to the east.
CALPUFF is a non-steady-state puff dispersion mode l. It accounts for spatial changes in the CALMET-produced meteorological fields, variab ility in surface conditions (elevation, surface roughness, vegetation type, etc.), chemical transf ormation, wet removal due to rain and snow, dry deposition, and terrain in fluences on plume interaction with the surface. CALPUFF contains a module to compute visibility effects, based on a humidity-dependent relationship between particulate matter concentrations and light ex tinction, as well as wet and dry acid deposition fluxes. The meteorological and dispersion mode ling simulations were conducted for three years (2002, 2006 and 2007). SO 2 , SO 4 , PM, and NO x , emissions and their secondary products resulting from chemical conversions from the Big Stone I facility were modeled and their impacts on visibility evaluated at receptors in the Class I areas. Visibi lity impacts were estimated with the new FLM-recommended visibility algorithm and monthly average relative humidity adjustment factors (Method 8 in Version 6.221).
This report outlines the techniques and data sources used in the BART analyses. In Section 2, a general description of the source configurations for the baseline case and 10 control scenarios are provided. Section 3 refers to the baseline report where descriptions of the site characteristics and data bases (meteorological, geophysical, and aerom etric) were provided, as well as an overview of the CALMET and CALPUFF models settings and pa rameters that were used in the analysis. The results of the control scenario eval uations are summarized in Section 4.Source Description 2-1 

## 2. SOURCE DESCRIPTION

The 450-megawatt Big Stone I facility is a coal-fired power plant situated close to Big Stone City and Milbank in Grant County, South Dakota, at the border of Minnesota State. A BART applicability analysis was completed for the facility to determin e those sources subject to the BART controls. The BART-eligible source is the Big Stone I cyclone-fire d boiler with one stack 152 meters (498 feet) high.
The proposed emissions for the BART analysis were described in a Modeling Pr otocol dated June 2009. These emissions were reviewed and approved by SD DENR. In addition, 10 different control scenarios were modeled. Table 2-1 shows th e source parameters and emission rates for the source considered in this report both for the baseline case and ten c ontrol scenarios. The highest 24-hour average actual emission rates of SO 2 , NOx and PM under normal conditions ove r the 2001-2003 period were used for the baseline case in this analysis.

As shown in Table 2-2, the filterable PM 10 are divided into a particle size distribution based on AP-42, Table 1.1-6 for baghouse controlled emissions because the facility currently uses a fabric filter for PM control. Approximately 57.6% of the filterable mass is in the fine (PM2.5) size category, and 42.4% in the coarse (2.5 to 10 μm diameter) size range. E ach of the particle size categories was modeled as a separate PM species in CALPUFF. The filterable PM 10 emission rate is reported by the facility at 10.48 g/s (83.2 lb/hr). Based on AP-42 Table 1.1-5, the total condensable PM 10 is approximately 0.01 lb/mmBtu based on approximately 0.4% sulfur coal or 7.07 g/sec (56.1 lb/hr) assuming an heat input of 5609 mmBtu/hr. This estimate is consistent w ith the stack test data (August, 2006) at Otter Tail Power’s Hoot Lake Plant, Unit 2, (which burns P RB coal) where the ratio of the filterable/total PM 10 ratio was 0.66, resulting in a 2/3 filterabl e and 1/3 condensable split to the total PM 10 . 1

Elemental Carbon (EC) emissions were assumed to be 3.7% of the fine filterable fraction based on U.S. EPA (2002) and were assigned to the smallest particle size category. The primary H 2 SO 4 emissions are 0.454 g/s (3.604 lb/hr) based on annual emission inve ntories and Toxic Release Inventory reports. The remaining condensable emissions were assigned to or ganic carbon and distributed equally into the two smallest particle size categories.
Table 2-3 provides a summary of the PM 10 speciation and size distribution.

Note that since all Class I areas are more than 50 km away from the facility, as recommended by the Federal Land Managers (FLMs) (US Fi sh and Wildlife, National Park Service and U.S. Forest Service), no downwash computations was performed.

1 AP-42 Table 1.1-8 was not used to estimate the particulat e matter size distribution for Big Stone I because the emission factors were derived for cyclones burning bituminous coal, not sub-bituminous coal which is burned at Big Stone I.Source Description 2-2Table 2-1: Point Source Parameters and Emission RatesMain StackLCC1East(km)LCC1North(km)StackHt(m)BaseElevation(m)StackDiameter(m)ExitVelocity(m/s)ExitTemp.(K)2SO2EmissionRate(g/s)H2SO4EmissionRate(g/s)NOxEmissionRate(g/s)FilterablePM102EmissionRate(g/s)CondensablePM10EmissionRate(g/s)Baseline Case38.141 587.875 151.79 328.90 7.37 20.14 423.1 608.9 0.454 611.7 10.48 7.07Control 1Over-fire Air (OFA)Presumptive Dry FGD'' '' '' '' ''19.57 352.6 106.0''459.4'' ''Control 2OFAPresumptive Wet FGD'' '' '' '' '' 18.23 330.4 106.0 '' 459.4 '' ''Control 3OFADry FGD at 90% Control'' '' '' '' ''19.57 352.6 63.6''459.4'' ''Control 4OFAWet FGD at 95% Control'' '' '' '' '' 18.23 330.4 30.4 '' 459.4 '' ''Control 5Separated OFA (SOFA)Presumptive Dry FGD'' '' '' '' '' 19.57 352.6 106.0 '' 353.4 '' ''Control 5aSOFADry FGD at 90% Control'' '' '' '' ''19.57 352.6 63.6''353.4'' ''Control 5bSOFAWet FGD at 95% Control'' '' '' '' '' 18.23 330.4 30.4 '' 353.4 '' ''Control 6SNCR with SOFA,Presumptive Dry FGD'' '' '' '' ''19.57 352.6 106.0''247.4'' ''Control 7RRI+SNCR with SOFAPresumptive Dry FGD'' '' '' '' ''19.57 352.6 106.0''141.3'' ''Control 8SCR with SOFAPresumptive Dry FGD'' '' '' '' '' 19.57 352.6 106.0 '' 70.7 '' ''1Lambert Conformal Projection with an origin of 40.0N, 97.0Wand standard parallels at33N and 45N. Datum is NWS-84.2The PM technology for all modeling scenarios is the existing pulse-jet fabric filter.Source Description 2-3Table 2-2: PM10Size Distribution1Particle Size2(μm)Cumulative Mass(PM)(%)Cumulative Mass(PM10)(%)15 97 -10 92 1006 77 83.72.5 53 57.61.25 31 33.71.00 25 27.21From AP-42, Table 1.1-6, Cumulative particle size distribution and size-specificemission factors for dry bottom boilers burning pulverizedbituminous and subbituminous coal.2Expressed as aerodynamic equivalent diameter.Source Description 2-4Table 2-3: PM10Speciation and Size Distributioninput Data: H2SO4PM10PM2.5g/sg/sg/sPM10and H2SO4Emissions(g/s)0.45417.55013.106filterablecondensablecondensable %59.7%40.3%g/sg/s10.480 7.070non H2SO4condensableg/s6.616AP-42, Table 1.1-6coarse coarse soil soil soil soil EC H2SO4OC OC IC (soil) IC (soil)PM800 PM425 PM187 PM112 PM081 PM056 PM056 PM081 PM056 PM081 PM0566.00 -10.00 2.50-6.001.25-2.501.00-1.25 0.625-1.000.50-0.625 0.50-0.6250.625-1.000.50-0.6250.625-1.000.50-0.62516.3% 26.1% 23.9% 6.5% 12.0% 15.2%57.6% 50.0% 50.0% 50.0% 50.0%EC % of filterable96.3% 3.7%100% 0%inorganic % of g/s g/s g/s g/s g/s g/s g/s g/s g/s g/scondensable 1.708 2.735 2.412 0.656 1.211 1.534 0.223 0.454 3.308 3.308inputs to POSTUTIL:Extinction coefficient 0.6 0.6 1 1 1 1 10 3*f(RH) 4 4coarse coarse soil soil soil soil EC H2SO4OC OCPM800 PM425 PM187 PM112 PM081 PM056 PM056 PM081 PM056g/s g/s g/s g/s g/s g/s g/s g/s g/s g/s1.708 2.735 2.412 0.656 1.211 1.534 0.223 0.454 3.308 3.308Geophysical and Meteorological Data 3-1 

## 3. GEOPHYSICAL AND METEOROLOGICAL DATA, AIR QUALITY MODELING OPTIONS

The South Dakota Department of Environment and Natural Resources requested that the eight Class I areas shown in Figure 3-1 be considered in the BART analysis. Rainbow Lake Wilderness is one of two Class I areas where the visibility analysis is not required so it has been removed from the present analysis (see http://www.dnr.state.wi.us/org /aw/air/modeling/psd.htm ). The MM5 dataset for this analysis were extended to include the Isle Royale National Park as well as all of the Boundary Waters Class I area.
Processing of the topography and land use for the doma in shown in Figure 3-1 w as described in detail in Section 3 of the October 2009 Big Stone Report (Repor t). In the same Report, all meteorological data and ozone data used in the modeling have been discu ssed. Locations of the stations were presented in Figures 3-3 and 3-4 of the Report.
CALMET was run with 4-km grid resolution usi ng 12-km MM5 data for initial guess fields. CALMET and CALPUFF use terrain-following coordinates. In or der to cover a large enough area for the refined analysis covering all seven Class I areas within a singl e domain, and including a buffer of at least 50 km around each Class I area, the domain dimensions of 1250 km x 720 km were used. For a 4-km grid spacing, this amounts to 313 x 181 grid cells. In th e vertical, a stretched grid was used with finer resolution in the lower layers and somewhat co arser resolution aloft thus allowing adequate representation of the mixed layer. The ten vertical le vels were centered at: 10, 30, 60, 120, 240, 480, 920, 1600, 2500 and 3500 meters.
CALMET and CALPUFF were run for three years, 2002, 2006 and 2007. A network of discrete receptors derived from the list of receptors develope d by the National Park Service (NPS) are located within the boundaries of the seven Class I areas modeled: Boundary Water Canoe Area Wilderness, Voyageur National Park, Badlands National Park , Wind Cave National Park, Lostwood National Wildlife Refuge, Theodore Roosevelt Nationa l Park and Isle Royale National Park.
Meteorological modeling options including initial guess fields and step 1 and 2 wind fields, dispersion modeling options and visibility calculations were all described in Section 4 of the October 2009 report.
Calculations of the impact of the simulated plume particulate matter component concentrations on light extinction were carried out with the CALPO ST postprocessor following the new proposed FLAG (2008) guidance. A revised new IMPROVE algorithm to compute the extinction (1/Mm) has been developed by the IMPROVE steering committee for estimating light extinction from particulate matter. That algorithm provides a better correspondence between the measured visibility and that calculated from particulate matter component concentrations (Tombach, 2006):
To represent background natural conditions, monthly b ackground concentrations must be entered into the CALPOST input control file for all aerosols defining the background. The WRAP Protocol (2006) recommendations for natural conditions background are to use all three types of EPA default Natural Conditions: Best 20% Days, Annual Average and Worst 20% Days. In “Guidance for Estimating Visibility Conditions Under the Regional Haze Ru le” (EPA, 2003), these three default values are defined only by their extinction coefficient in Mm -1 . For CALPOST Method 8, explicit backgroundGeophysical and Meteorological Data 3-2 concentrations are required to allow the computation of the small and large sulfate particulates, nitrate particulates and organic carbon. So, in this analys is, the annual averaged background conditions were used to define the natural background for each of the seven Class I areas, following FLAG (2008). The concentrations used as background for each of the seven Class I areas are summarized in Table 4-2 of the October 2009 report. These concentrations were used to compute the natural background light extinction following the revised IMPROVE formul ae described above, for each of the Class I areas.

Tables 4-3, 4-4, and 4-5 in Octobe r 2009 report, provide the monthly f(RH) values for each of the seven Class I areas, that are used to com pute extinction coefficients for hygr oscopic species, respectively for small ammonium sulfate and ammonium nitrate particles, large ammonium sulfate and ammonium nitrate particles, and sea salt particles.

The 8 th highest (98 th percentile) predicted light extinction cha nge for each year modeled was compared to the threshold value of 0.5 deciview.Geophysical and Meteorological Data 3-3Figure 3-1. Terrain elevations for the CALMET and CALPUFF modelingdomain at 4 km resolution. The locations of the Big Stone facility andClass I areas are also shown.-500 -400 -300 -200 -100 0 100 200 300 400 500 600 700LCC x (km), NWS-843004005006007008009001000

LCC x (km), NWS-84Projection:LCC; Center: 40N, 98WStandards: 20N, 60NDatum: NWS-84100200300400500600700800900100011001200130014001500160017001800190020002100FACILITYWindCaveBadlandsTheodoreRooseveltLostwoodVoyageursBoundaryWatersIsle RoyaleElevation(meters)Results 4-1 

## 4. RESULTS

The results for the BART analysis for the Big Stone I facility are presented in this section. The analysis consists of evaluating the visibility impact (per cent change in light extinction due to the sources measured in deciview) at all the Class I areas modele d. The results are presented in three tables for the baseline case and ten control scenarios, each table gath ering the impact at seven Class I areas for each of the years modeled: Table 4-1 for 2002, Table 4-2 for 2006 and Table 4-3 for 2007. The change in light extinction due to the source is compared to the annu al average natural backgr ound light extinction. The interpretation of the results is done by comparing the 98 th percentile of delta deciview for each year to the 0.5 delta deciview threshold. Analysis is performed by using CALPOST Method 8.Results 4-2 Table 4-1. Visibility Impacts for 2002

Park Max Delta Deciview 4th Highest (99%) 8th Highest (98%) Nb. Exceed.

> 5% Nb. Exceed. > 10%

Baseline Boundary Waters 1.315 0.837 0.574 14 1 Voyageurs 2.162 0.690 0.623 9 3 Wind Cave 0.873 0.475 0.305 3 0 Theodore Roosevelt 1.390 0.555 0.215 4 1 Lostwood 0.564 0.388 0.232 2 0 Badlands 0.762 0.671 0.452 7 0 Isle Royale 1.182 0.789 0.629 10 2

Control 1 Boundary Waters 0.685 0.563 0.330 5 0 Voyageurs 1.252 0.541 0.329 4 1 Wind Cave 0.485 0.258 0.101 0 0 Theodore Roosevelt 0.530 0.298 0.092 1 0 Lostwood 0.329 0.171 0.111 0 0 Badlands 0.462 0.342 0.223 0 0 Isle Royale 0.780 0.471 0.377 2 0

Control 2 Boundary Waters 0.716 0.639 0.360 5 0 Voyageurs 1.191 0.586 0.349 5 1 Wind Cave 0.417 0.262 0.095 0 0 Theodore Roosevelt 0.476 0.278 0.099 0 0 Lostwood 0.320 0.155 0.118 0 0 Badlands 0.549 0.315 0.234 1 0 Isle Royale 0.809 0.497 0.367 3 0

Control 3 Boundary Waters 0.647 0.542 0.319 5 0 Voyageurs 1.210 0.534 0.307 4 1 Wind Cave 0.473 0.244 0.093 0 0 Theodore Roosevelt 0.453 0.287 0.087 0 0 Lostwood 0.317 0.150 0.109 0 0 Badlands 0.441 0.326 0.219 0 0 Isle Royale 0.758 0.448 0.363 2 0

Control 4 Boundary Waters 0.687 0.593 0.350 5 0 Voyageurs 1.121 0.574 0.312 4 1 Wind Cave 0.379 0.237 0.080 0 0 Theodore Roosevelt 0.421 0.260 0.084 0 0 Lostwood 0.298 0.138 0.103 0 0 Badlands 0.505 0.281 0.225 1 0 Isle Royale 0.762 0.456 0.351 2 0Results 4-3 Table 4-1. Visibility Impacts for 2002 (continued).

Park Max Delta Deciview 4th Highest (99%) 8th Highest (98%) Nb. Exceed. > 5% Nb. Exceed. > 10%

Control 5 Boundary Waters 0.551 0.449 0.264 2 0 Voyageurs 0.997 0.426 0.263 3 0 Wind Cave 0.385 0.206 0.083 0 0 Theodore Roosevelt 0.458 0.237 0.076 0 0 Lostwood 0.263 0.144 0.089 0 0 Badlands 0.370 0.272 0.169 0 0 Isle Royale 0.618 0.375 0.298 2 0

Control 5a Boundary Waters 0.513 0.428 0.250 2 0 Voyageurs 0.955 0.419 0.249 3 0 Wind Cave 0.372 0.191 0.074 0 0 Theodore Roosevelt 0.380 0.227 0.069 0 0 Lostwood 0.251 0.124 0.085 0 0 Badlands 0.349 0.256 0.165 0 0 Isle Royale 0.595 0.355 0.285 2 0

Control 5b Boundary Waters 0.537 0.465 0.274 2 0 Voyageurs 0.876 0.449 0.244 2 0 Wind Cave 0.296 0.184 0.063 0 0 Theodore Roosevelt 0.325 0.204 0.066 0 0 Lostwood 0.234 0.109 0.081 0 0 Badlands 0.396 0.219 0.174 0 0 Isle Royale 0.594 0.357 0.274 2 0

Control 6 Boundary Waters 0.418 0.335 0.200 0 0 Voyageurs 0.740 0.309 0.196 2 0 Wind Cave 0.283 0.154 0.072 0 0 Theodore Roosevelt 0.384 0.176 0.063 0 0 Lostwood 0.196 0.118 0.075 0 0 Badlands 0.278 0.203 0.120 0 0 Isle Royale 0.464 0.275 0.221 0 0

Control 7 Boundary Waters 0.285 0.221 0.137 0 0 Voyageurs 0.481 0.192 0.130 0 0 Wind Cave 0.180 0.104 0.070 0 0 Theodore Roosevelt 0.309 0.115 0.050 0 0 Lostwood 0.129 0.085 0.051 0 0 Badlands 0.187 0.135 0.090 0 0 Isle Royale 0.310 0.174 0.142 0 0

Control 8 Boundary Waters 0.198 0.143 0.097 0 0 Voyageurs 0.309 0.125 0.086 0 0 Wind Cave 0.119 0.072 0.053 0 0 Theodore Roosevelt 0.262 0.074 0.036 0 0 Lostwood 0.085 0.053 0.037 0 0 Badlands 0.127 0.102 0.079 0 0 Isle Royale 0.207 0.113 0.092 0 0Results 4-4 Table 4-2. Visibility Impacts for 2006.

Park Max Delta Deciview 4th Highest (99%) 8th Highest (98%) Nb. Exceed.

> 5% Nb. Exceed. > 10%

Baseline Boundary Waters 2.572 1.183 0.790 16 5 Voyageurs 1.578 0.862 0.574 11 2 Wind Cave 0.454 0.302 0.120 0 0 Theodore Roosevelt 2.232 0.772 0.459 6 3 Lostwood 1.110 0.662 0.385 5 1 Badlands 1.002 0.519 0.481 7 1 Isle Royale 1.806 0.635 0.506 8 2

Control 1 Boundary Waters 1.375 0.799 0.548 9 3 Voyageurs 1.262 0.554 0.399 5 1 Wind Cave 0.273 0.162 0.024 0 0 Theodore Roosevelt 1.234 0.469 0.247 3 1 Lostwood 0.619 0.355 0.168 2 0 Badlands 0.504 0.319 0.176 1 0 Isle Royale 1.010 0.467 0.296 2 1

Control 2 Boundary Waters 1.405 0.830 0.546 11 3 Voyageurs 1.549 0.594 0.494 7 2 Wind Cave 0.266 0.162 0.027 0 0 Theodore Roosevelt 1.116 0.454 0.244 3 1 Lostwood 0.588 0.366 0.171 3 0 Badlands 0.482 0.326 0.199 0 0 Isle Royale 1.014 0.462 0.273 3 1

Control 3 Boundary Waters 1.319 0.780 0.534 8 3 Voyageurs 1.218 0.540 0.391 5 1 Wind Cave 0.260 0.150 0.023 0 0 Theodore Roosevelt 1.196 0.455 0.234 3 1 Lostwood 0.594 0.339 0.153 2 0 Badlands 0.482 0.308 0.172 0 0 Isle Royale 0.983 0.454 0.287 2 0

Control 4 Boundary Waters 1.313 0.793 0.521 10 3 Voyageurs 1.469 0.571 0.464 6 1 Wind Cave 0.244 0.139 0.025 0 0 Theodore Roosevelt 1.052 0.431 0.230 3 1 Lostwood 0.554 0.335 0.144 2 0 Badlands 0.443 0.306 0.191 0 0 Isle Royale 0.966 0.440 0.250 3 0Results 4-5 Table 4-2. Visibility Impacts for 2006 (continued).

Park Max Delta Deciview 4th Highest (99%) 8th Highest (98%) Nb. Exceed. > 5% Nb. Exceed. > 10%

Control 5 Boundary Waters 1.109 0.635 0.433 6 2 Voyageurs 1.013 0.440 0.314 2 1 Wind Cave 0.216 0.132 0.019 0 0 Theodore Roosevelt 0.987 0.372 0.199 2 0 Lostwood 0.494 0.281 0.136 0 0 Badlands 0.401 0.252 0.137 0 0 Isle Royale 0.804 0.366 0.235 2 0

Control 5a Boundary Waters 1.051 0.615 0.419 6 2 Voyageurs 0.967 0.426 0.306 2 0 Wind Cave 0.204 0.120 0.018 0 0 Theodore Roosevelt 0.948 0.358 0.186 2 0 Lostwood 0.468 0.265 0.124 0 0 Badlands 0.378 0.242 0.133 0 0 Isle Royale 0.777 0.355 0.226 2 0

Control 5b Boundary Waters 1.036 0.622 0.407 6 2 Voyageurs 1.160 0.449 0.365 3 1 Wind Cave 0.189 0.109 0.019 0 0 Theodore Roosevelt 0.827 0.336 0.180 2 0 Lostwood 0.430 0.259 0.114 0 0 Badlands 0.344 0.237 0.147 0 0 Isle Royale 0.758 0.342 0.195 1 0

Control 6 Boundary Waters 0.837 0.468 0.318 3 0 Voyageurs 0.759 0.325 0.228 2 0 Wind Cave 0.161 0.103 0.016 0 0 Theodore Roosevelt 0.736 0.274 0.150 1 0 Lostwood 0.369 0.209 0.103 0 0 Badlands 0.297 0.186 0.098 0 0 Isle Royale 0.595 0.268 0.174 1 0

Control 7 Boundary Waters 0.560 0.299 0.202 1 0 Voyageurs 0.502 0.204 0.157 1 0 Wind Cave 0.107 0.071 0.014 0 0 Theodore Roosevelt 0.479 0.176 0.101 0 0 Lostwood 0.244 0.138 0.082 0 0 Badlands 0.227 0.120 0.066 0 0 Isle Royale 0.382 0.169 0.115 0 0

Control 8 Boundary Waters 0.373 0.186 0.136 0 0 Voyageurs 0.328 0.128 0.107 0 0 Wind Cave 0.071 0.047 0.012 0 0 Theodore Roosevelt 0.306 0.111 0.070 0 0 Lostwood 0.162 0.092 0.064 0 0 Badlands 0.188 0.079 0.060 0 0 Isle Royale 0.239 0.104 0.077 0 0Results 4-6 Table 4-3. Visibility Impacts for 2007.

Park Max Delta Deciview 4th Highest (99%) 8th Highest (98%) Nb. Exceed.

> 5% Nb. Exceed. > 10%

Baseline Boundary Waters 3.574 1.351 1.079 25 9 Voyageurs 2.062 1.376 0.724 19 5 Wind Cave 1.671 0.591 0.325 4 2 Theodore Roosevelt 0.744 0.491 0.322 3 0 Lostwood 0.959 0.722 0.409 6 0 Badlands 2.202 0.698 0.471 6 2 Isle Royale 1.224 0.745 0.665 13 2

Control 1 Boundary Waters 2.018 0.874 0.657 9 2 Voyageurs 1.260 0.750 0.460 7 2 Wind Cave 0.950 0.334 0.130 3 0 Theodore Roosevelt 0.393 0.211 0.190 0 0 Lostwood 0.547 0.415 0.245 1 0 Badlands 1.292 0.395 0.241 3 1 Isle Royale 0.665 0.436 0.339 2 0

Control 2 Boundary Waters 1.959 0.890 0.667 11 2 Voyageurs 1.232 0.768 0.521 8 2 Wind Cave 1.030 0.355 0.130 2 1 Theodore Roosevelt 0.395 0.228 0.161 0 0 Lostwood 0.558 0.426 0.253 2 0 Badlands 1.369 0.440 0.254 2 1 Isle Royale 0.720 0.439 0.323 2 0

Control 3 Boundary Waters 1.944 0.848 0.620 9 1 Voyageurs 1.225 0.717 0.450 7 1 Wind Cave 0.902 0.317 0.120 2 0 Theodore Roosevelt 0.380 0.204 0.173 0 0 Lostwood 0.520 0.394 0.226 1 0 Badlands 1.234 0.378 0.230 2 1 Isle Royale 0.641 0.418 0.323 2 0

Control 4 Boundary Waters 1.844 0.840 0.611 10 1 Voyageurs 1.171 0.705 0.502 8 1 Wind Cave 0.938 0.323 0.117 2 0 Theodore Roosevelt 0.373 0.197 0.138 0 0 Lostwood 0.509 0.381 0.234 1 0 Badlands 1.261 0.405 0.234 2 1 Isle Royale 0.677 0.406 0.290 2 0Results 4-7 Table 4-3. Visibility Impacts for 2007 (continued).

Park Max Delta Deciview 4th Highest (99%) 8th Highest (98%) Nb. Exceed. > 5% Nb. Exceed. > 10%

Control 5 Boundary Waters 1.630 0.699 0.524 8 1 Voyageurs 0.997 0.602 0.364 4 0 Wind Cave 0.763 0.268 0.106 1 0 Theodore Roosevelt 0.311 0.175 0.156 0 0 Lostwood 0.439 0.328 0.211 0 0 Badlands 1.039 0.315 0.191 2 1 Isle Royale 0.525 0.349 0.272 2 0

Control 5a Boundary Waters 1.554 0.671 0.493 6 1 Voyageurs 0.961 0.569 0.354 4 0 Wind Cave 0.715 0.251 0.096 1 0 Theodore Roosevelt 0.299 0.160 0.141 0 0 Lostwood 0.412 0.314 0.178 0 0 Badlands 0.979 0.298 0.180 2 0 Isle Royale 0.503 0.331 0.256 1 0

Control 5b Boundary Waters 1.459 0.667 0.478 6 1 Voyageurs 0.915 0.554 0.393 6 0 Wind Cave 0.735 0.253 0.091 1 0 Theodore Roosevelt 0.291 0.155 0.108 0 0 Lostwood 0.399 0.301 0.182 0 0 Badlands 0.991 0.316 0.182 2 0 Isle Royale 0.527 0.319 0.227 1 0

Control 6 Boundary Waters 1.233 0.520 0.388 4 1 Voyageurs 0.737 0.454 0.267 3 0 Wind Cave 0.575 0.202 0.085 1 0 Theodore Roosevelt 0.230 0.143 0.121 0 0 Lostwood 0.331 0.241 0.157 0 0 Badlands 0.781 0.236 0.143 1 0 Isle Royale 0.388 0.259 0.199 0 0

Control 7 Boundary Waters 0.825 0.339 0.256 2 0 Voyageurs 0.501 0.304 0.176 1 0 Wind Cave 0.389 0.137 0.071 0 0 Theodore Roosevelt 0.149 0.112 0.080 0 0 Lostwood 0.223 0.155 0.101 0 0 Badlands 0.524 0.157 0.099 1 0 Isle Royale 0.268 0.172 0.134 0 0

Control 8 Boundary Waters 0.549 0.217 0.170 1 0 Voyageurs 0.383 0.205 0.123 0 0 Wind Cave 0.265 0.093 0.055 0 0 Theodore Roosevelt 0.102 0.090 0.064 0 0 Lostwood 0.152 0.122 0.063 0 0 Badlands 0.352 0.105 0.070 0 0 Isle Royale 0.189 0.124 0.098 0 0References 5-1 

## 5. REFERENCES

FLAG, 2000. Federal Land Manager' Air Qu ality Related Values Workgroup (FLAG). Phase I Report. U.S. Forest Service, National Park Service, U.S. Fish and Wildlife Service.
FLAG, 2008. Federal Land Manager' Air Qu ality Related Values Workgroup (FLAG). Phase I Report -Revised. U.S. Forest Servi ce, National Park Service, U.S. Fish and Wildlife Service, June 27, 2008, Draft

. Scire, J.S., D.G. Strimaitis, and R.J. Yamartino, 2000a: A User’s Guide for the CALPUFF Dispersion Model (Version 5). Earth Tech, Inc., Concord, MA

Scire, J.S., F.R. Robe, M.E. Fernau, and R.J. Yamartino, 2000b: A User’s Guide for the CALMET Meteorological Model (Version 5) . Earth Tech, Inc., Concord, MA.
Tombach, I, 2006: Instructions: A Postpr ocessor for Recalculating CALPOST Visibility Outputs with the New IMPROVE Algorithm, Version 2, 14 October, 2006.
U.S. EPA, 1998: Interagency Workgroup on Air Quality Modeling (IWAQM), Phase 2 Report: Summary Report and Recomme ndation for Modeling Long Range Transport and Impacts on Regional Visibility. EPA-454/R-98-019.
U.S. EPA, 2000: Federal Register Notice dated April 21, 2001.
U.S. EPA, 2003: Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program. EPA-454/ B-03-005, September 2003.
U. S. EPA, 2005: Regional Haze Regulati ons and Guidelines for Best Available Technology (BART) Determin ations. Fed. Reg./Vol. 70, No. 128/Wed. July 6, 2005, Rules and Regulations, pp. 39104-39172. 40 CFR Part 51, FRL-7925-9, RIN AJ31.

U.S. EPA, 2009: Clarification on EPA-FLM Recommended Settings for CALMET. EPA Memo by T. Fox dated August 31, 2009.
WRAP Air Quality Modeling Forum RMC, 2006: CALMET/CALPUFF Protocol for the BART Exemption Screening Analysis for Class I Areas in the Western United States, August 15, 2006.B-1 11/2/2009 

### APPENDIX B Technical Description of SO 2 Controls (B1)B-2 11/2/2009 

### B1 Technical Description of SO 2 

### Controls B1.1 Fuel Switching

Fuel switching can be a viable method of fuel sulfur content reduction in certain situations. The PRB burned by BSP Unit I is one of the lower sulfur co als available in the U.S. and switching to a lower sulfur coal (if available) would achie ve little to no additional reduction in SO 2 emissions. Therefore, for the purpose of this BART analysis, fuel sw itching is not considered a viable option for SO 2 control.



### B1.2 Wet Flue Gas Desulfurization Wet FGD technology utilizing lime or limestone as the reagent and employing forced oxidation to produce gypsum (calcium sulfate dihydrate, CaSO 4 ·2H 2 O) as the byproduct, is commonly applied to coal-fired boilers. The gypsum byproduct is e ither landfilled or sold for commercial reuse.

A flow diagram of the wet FGD process is provided in Figure B-1. In the wet FGD process, a slurry of finely ground limestone (CaCO 3 ) in water is recirculated through an absorber tower where it is brought into turbulent contact with the flue gas. The contact between the flue gas and the slurry cools and saturates the gas via evaporation of water from the slurry. SO 2 is simultaneously absorbed into the slurry where it forms sulfurous acid which reacts with the limestone, forming calcium sulfite hemihydrate (CaSO 3 •1⁄2H 2 O) which can then be disposed of as a waste product or oxidized to calcium sulfate dihydrate or gypsum (CaSO 4 •2H 2 O) before disposal or for commercial reuse. No commercial uses for sulfite waste products have been identified.B-3 11/2/2009 Figure B-1. Wet FGD Process Flow Diagram

Chemical reactions between the limestone and the absorbed SO 2 take place within the slurry in the absorber, and in the absorber reaction tank, r esulting in the formation of particles of CaSO 3 ·1⁄2 H 2 O. Some of the oxygen in the flue gas may participat e in the reaction, resulting in the formation of particles of CaSO 4 •2H 2 O as well. Air may be injected into the absorber sump to promote the formation of gypsum and minimize the formation of calcium sulfite solids where a gypsum product is desired, either for ease of disposal or commercial use. The resultant slurry is then processed in a dewatering system prior to disposal or commercial use.

As the limestone reagent in the recirculating slurry is depleted, it is replenished with fresh slurry prepared by wet grinding of crushed limestone us ing reclaimed liquid from the dewatering system. Fresh water is also required to replace water lost to evaporation in the flue gas cooling process. Fresh water is often used to wash the mist eliminators, devices located at the scrubber exit to capture slurry droplets entrained in the exiting flue gas stream and return them to the scrubber. The mist eliminator
wash removes accumulated materials from the mist eliminator chevrons, thus preventing solids buildup and pluggage. In additi on, depending upon the mineral content of the coal, a portion of the reclaimed liquid from the dewatering process may be blown down, or disposed of, to prevent excessive accumulation of mineral salts in the slurry which could result in mineral scaling within the absorber equipment. The blow down rate varies w ith each plant. Fresh water makeup, both through the mist eliminator wash system and in the limestone grinding process, replaces the blow down and evaporative losses. Stack Flue Gas from Air Heater ESP

Booster Fan
Recycle Pump

Water Limestone

To Dewatering System Oxidation Air Reaction Tan k Absorbe r

Tower Mist EliminatorsB-4 11/2/2009 Lime scrubbers are very similar to limestone scrubbe rs. The use of lime rather than limestone can reduce the liquid-to-gas ratio and/or absorb er size required to achieve a given SO 2 removal rate. Lime is sometimes used in wet FGD systems where extremely high SO 2 removal rates are desired or where limestone is not readily available. However, since lime is more expensive than limestone, the reagent cost is much higher for a lime system. Ther efore, the vast majority of wet FGD systems are designed to use limestone as the neutralizing reagent.

Tow advantages of the wet FGD systems include lower reagent costs, primarily due to the ability to use limestone instead of lime as a reagent and the production of a salable by-product and high removal efficiency. Also, wet FGD systems have a high turndown capability and plant operational flexibility is not hindered to the same degree as th e semi-dry processes. This last advantage is important where wet FGD systems are applied to load following units. Disadvantages of wet FGD systems include corrosion due to a wet environmen t with corrosive chemicals including salts of
sulfurous and sulfuric acid and hydrochloric acid. Also, because the wet systems are more mechanically complex, they typically require larg er maintenance staff than the semi-dry, CFB and FDA alternatives. The greater mechanical complex ity also contributes to a greater capital cost for wet FGD systems. Finally, because wet FGD systems completely saturate the flue gas stream, nearly
all the SO 3 or H 2 SO 4 vapor in the entering flue gas is condensed into aerosol droplets which are too small to be efficiently captured in the scrubber. Fifty percent or more of these droplets pass right through the scrubber. Where units are burning high sulfur fuels, this can cause a plume opacity problem. Wet FGD systems commonly achieve 95% percent SO 2 removal efficiencies in commercial applications.



### B1.3 Semi-Dry Flue Gas Desulfurization As an alternative to wet FGD technology, the control of SO 2 emissions can be accomplished using semi-dry FGD technology. The most common se mi-dry FGD system is the lime Spray Dryer Absorber (SDA) using a fabric filter for downstr eam particulate collection. The semi-dry FGD process became popular in the U.S. beginning in the late 1970s as a way to comply with the New Source Performance Standards (NSPS) for electri c utility steam generating units for which construction commenced after September 18, 1978 (40 CFR Part 60, Subpart Da). These standards require that all new coal-fired electric utility boi lers be equipped with a “continuous system of
emission reduction” for SO 2 . However, the standards allowed SO 2 removal efficiency as low as 70B-5 11/2/2009 percent for facilities burning low-sulfur coal . The semi-dry FGD process could meet this requirement, and was often selected as the SO 2 control technology for many new coal-fired power plants that were built in the 1970s and 1980s and designed to burn low-sulfur western coal. In the late 1980s and through the 1990s, most of the new coal -fired boilers built in the U.S. were for small Independent Power Producer (IPP) projects, and many of these also selected the semi-dry/lime FGD

process.

There are several variations of the semi-dry pr ocess in use today. This section addresses the spray dryer FGD process. Two other variations, the N ovel Integrated Desulfurization and Circulating Fluidized Bed absorber are similar processes. They primarily differ by the type of reactor vessel used, the method in which water and lime are intr oduced into the reactor and the degree of solids recycling. They are considered similar technologies and are not discussed further.

A schematic diagram of the spray dryer FGD process is provided in Figure B-2. In the spray dryer FGD process, boiler flue gas is introduced into a Spray Dryer Absorber (SDA) into which hydrated lime (calcium hydroxide, Ca(OH) 2 ) and water are added as dispersed droplets. The Ca(OH) 2 reacts with SO 2 that has been absorbed into the water to form primarily calcium sulfite and some calcium
sulfate. The heat from the flue gas causes the water to evaporate, cooling the gas and drying the reaction products. Because the total water feed rate is much lower than that of the wet FGD process, the reaction products are dried in the SDA and the fl ue gas is only partially saturated. The amount of water added to the process is carefully controlled so that the flue gas temperature is maintained well above the saturation, or dewpoint, temperature (typically 30-40 0 F above saturation) to avoid corrosion problems. Cooling the gas to this point significantly increases the SO 2 control efficiency over injection into hot, dry flue gas. The reaction product leaves the SDA as fine dry particles entrained in the flue gas. The flue gas enters th e SDA at the top and flows downward, co-current with the introduced neutralizing agent. This character istic is the opposite of the wet FGD system which introduces flue gas into the bottom of the absorber, countercurrent to the falling slurry spray.B-6 11/2/2009 Figure B-2 Spray Dryer FGD Process Flow Diagram

In the lime spray drying process, quicklime (CaO) is sl aked with water to form lime slurry which is then injected into the SDA along with additional wa ter through a rotary atomizer or dual fluid nozzle or similar apparatus. Recycled PM from the PM control equipment downstream of the SDA is often mixed with the lime slurry before injection into the SDA to provide additional surface area for SO 2 absorption. The flue gas is in troduced into the SDA in a manner designed to maximize the contact between the gas and the droplets and to prevent sl urry impingement on the walls of the SDA. The turbulent mixing of the flue gas and the slurry droplets promotes rapid absorption of SO 2 into the water of the slurry droplets. The chem ical reactions between the absorbed SO 2 and the calcium hydroxide take place within the droplet as the flue gas moves through the SDA. The flue gas is cooled and partially humidified as the water evaporates, leaving a mixture of fly ash and dry powdered reaction product entrained in the flue gas. Some of the solid particles fall to the bottom of the reactor and are collected by a waste handling sy stem. Entrained particles are collected in an electrostatic precipitator (ESP) or fabric filter (FF) downstream of the SDA.

An additional distinguishing characteristic of the SDA is that it must be located upstream of a particulate control device, as opposed to the wet FGD process which is normally the last flue gas treatment process before discharge to the stack. Fo r new plants, this point is not of such great importance. However, when retrofitting FGD equi pment to an existing coal-fired plant, which Flue Gas from Air Heater Lime Slurry Preparation Lime

Water

Spray Dryer

To Solids Recycling Fabric Filter

To Solids Recycling or Disposal Stack I.D. Booster Fan Water or Ash Recycle SlurryB-7 11/2/2009 already has particulate control equipment installed, this becomes an important point. If a suitable location exists for the insertion of a new SDA upstrea m of an existing PM control device, and if the performance of the existing PM control device would not be overly degraded by the additional PM loading, then the retrofit process would consist only of installation of the SDA, reagent preparation and waste handling systems. However, many times one, or both, of these conditions do not exist and the choice to utilize an SDA requires the installati on of a new PM control device, such as an ESP or fabric filter. Where this situation exists, the capital cost of the SDA option increases significantly.

Semi-dry processes have some notable advantag es compared to wet FGD processes including a dry byproduct which can be handled with conventional ash handling systems. Because the semi-dry system does not have a truly wet zone, corrosion prob lems in the SDA are eliminated, or significantly reduced, to the point exotic materials of construc tion are not required. Spray dryer systems utilize less complex equipment resulting in a reduced capital cost and allowing somewhat smaller operations
and maintenance staff. Where a fabric filter is utilized as the downstream particulate control device for a semi-dry process, the lime content of the filte r cake on the fabric filter reacts with condensed
SO 3 in the flue gas stream capturing and neutralizi ng the acid aerosol. Consequently, semi-dry FGD options, paired with a fabric filter for PM control, have virtually zero emissions of acid aerosols.

The primary disadvantages of the lime spray dryer pr ocess make it less likely to be applied to large power plant boilers, especially those firing high-sulfur coal. The lime spray dryer requires the use of lime, which is much more expensive than limest one. While lime contains approximately 1.8 times more calcium than limestone on a mass basis, lime can cost up to five times more than limestone on a mass basis. Therefore, reagent costs for a lime based process are typically higher than a limestonebased process for a given application.

Wastes from semi-dry processes have very limited possi bility for reuse due to fly ash contamination. Also, where fly ash might be sold for other uses, contamination with the semi-dry FGD reaction products typically eliminates commercial options for re use. Where fly ash sales are to be maintained, a second PM control device would be required fo r the semi-dry FGD system exhaust stream, increasing both capital and O&M costs.

SDAs have much more stringent size limitations than wet FGD scrubbers. Typically units larger than 250 to 300 MW will require at least two SDAs, thus driving up capital costs and system complexity for larger units, while wet FGD systems can handle up to 1000 MW in a single absorber module.B-8 11/2/2009 SDAs do not have the same turndown capabilities as wet FGD absorbers, further limiting applicability for load following units. Finally, lime spray dryer systems do not have the same level of experience with high SO 2 removal requirements in high sulfur applications that wet FGD systems
have.

No variation of semi-dry FGD systems has cl early demonstrated the ability to achieve SO 2 removal levels similar to wet FGD systems in the U.S. Table B-1 lists many of the recent lime spray dryer system installations in the U.S. The in formation in Table B-1 was obtained from the RACT/BACT/LAER Clearing House. As can be seen in the column titled Efficiency, two units were permitted with an SO 2 removal efficiency of 94.5% and on e with 95%. However, these units typically use a lower sulfur fuel and achieve an emissions limit in the range of 0.12 to 0.17 lb
SO 2 /mmBtu.B-9 11/2/2009Table B-1 – Recent Dry FGD Permits From RBLCRBLCIDFacility Process Fuel Size Unit Control DeviceEmissionLimit(lb/mmBtu)EstimatedEfficiencyPermit Date*NE0018Whelan EnergyCenterUnit 2UtilityBoiler PRB coal 2,210 mmBtu/hrSpray Dryer Absorber(SDA)0.12 NA 3/30/2004AR-0074 Plum Point EnergyBoiler , Unit1 - SN-01 Bituminous Coal 800 MWDry Flue GasDesulfurization 0.16 NA 8/20/2003MT-0022Boiler, PCNo. 1 Coal 390 MWDry Flue GasDesulfurization (FGD) 0.12 94.5 7/21/2003MT-0022Bull Mountain, No.1, LLC - RoundupPower ProjectBoiler, PCNo. 2Coal 390 MWDry Flue GasDesulfurization (FGD)0.12 94.5 7/21/2003IA-0067MidAmericanEnergy CompanyCBEC 4Boiler PRB Coal 7,675 mmBtu/hrLime Spray Dryer FlueGas Desulfurization 0.1 92 6/17/2003KS-0026 Holcomb Unit #2 Boiler, PCSubbituminousCoal 660 MWDry Flue GasDesulfurization 0.12 94 10/08/2002WY0057WYGEN 2500 MW PCBoilerSubbituminousCoal500 MWSemi-Dry Lime SprayDryer Absorber0.1 NA 9/25/2002MO0050Kansas City Power& Light Co. -Hawthorn StationPC Boiler, Coal 384 T/HDry Flue GasDesulfurization 0.12 NA 8/17/1999WY0039Two Elk GenerationPartners, LimitedPartnershipPC FiredBoiler Coal 250 MWLime Spray DryScrubber 0.17 91 2/27/1998WY0047Encoal CorporationEncoal NorthRochelle FacilityPC FiredBoilerSubbituminousCoal3,960 mmBtu/hr Lime Spray Dryer 0.2 73 10/10/1997WY0048Wygen, Inc. -Wygen Unit One Boiler, PCSubbituminousCoal 80 MWCirculating DryScrubber 0.2 92 9/6/1996PA-0133Mon Valley EnergyLimited PartnershipPC FiredBoiler Bituminous Coal 966 mmBtu/hr Spray Dry Absorption 0.25 92 8/8/1995B-10 11/2/2009Table B-1 – Recent Dry FGD Permits From RBLC (cont.)RBLCIDFacility Process Fuel Size Unit Control DeviceEmissionLimit(lb/mmBtu)EstimatedEfficiencyPermit DateVA-0213 SEI Birchwood, Inc.PC FiredBoilerCoal 2,200 mmBtu/hrLime Spray DryingSystem (FGD System)220 94 8/23/1993WY0046Black Hills P&LNeil Simpson UPC FiredBoilerCoal 80 MWCirculating DryScrubber0.17 95 4/14/1993MI-0228Indelk EnergyServices Of OtsegoBoiler(Coal) Coal 778 mmBtu/hr Dry Scrubber 0.32 90 3/16/1993NC-0057Roanoke ValleyProject IiBoiler, PCFired Coal 517 mmBtu/hr Dry Lime Scrubbing 0.187 93 12/7/1992SC-0027Boiler, PCFiredUnit No. 1Coal 385 MW Spray Dryer Absorber 0.25 93 7/15/1992SC-0027PC-FiredBoiler,Unit No. 2Coal 385 MW Spray Dryer Absorber 0.17 93 7/15/1992SC-0027South CarolinaElectric And GasCompanyPC-FiredBoiler,Unit No. 3 Coal 385 MW Spray Dryer Absorber 0.17 93 7/15/1992NJ-0015KeystoneCogenerationSystems, Inc.PC-FiredBoilerCoal,Bituminous2,116 mmBtu/hr Spray Dryer Absorber 0.16 93 9/6/1991NC-0054Roanoke ValleyProjectBoiler, PCFiredCoal 1,700 mmBtu/hr Dry Lime FGD 0.213 92 1/24/1991NJ-0014ChambersCogenerationLimited Partnership2 PC-FiredBoilers Coal 1,389mmBtu/hr(each) Spray Dryer Absorber 0.22 93 12/26/1990VA-0176 Hadson Power 13 Boiler Coal 30,228 lb/hr coal Lime Spray Dryer 0.162 92 8/17/1990VA-0171MecklenburgCogenerationLimited PartnershipPC Fired,Boiler, 4UnitsBituminous Coal 834.5 mmBtu/hrSpray Dryer, FabricFilter0.172 92 5/9/1990C-1 11/2/2009 

### APPENDIX C Technical Description of Particulate Matter Controls (C1)C-2 11/2/2009 Appendix C1 – Technical Description of Particulate Matter Controls

C1.0 FABRIC FILTER (FF) A fabric filter or baghouse removes particulate by passing flue gas through filter bags. A pulsejet fabric filter (PJFF) unit (like the current Bi g Stone PM controls) consists of isolatable compartments with common inlet and outlet manifold s containing rows of fabric filter bags. The filter bags are made from a synthetic felted materi al that are suspended from a tube sheet mounted at the top of each fabric filter compartment. Th e tube sheet separates the particulate laden flue gas from the clean flue gas. This tube sheet is a flat sheet of carbon steel with holes designed to accommodate filter bags through which the bags ar e hung. The flue gas passes through the PJFF by flowing from the outside of the bag to the inside, up the center of the bag through the hole in the tube sheet and out the PJFF. Fly ash particl es are collected on the outside of the bags, and the cleaned gas stream passes through the fabric filte r and on to the chimney. A long narrow wire cage is located within the bag to prevent collap se of the bag as the flue gas passes through it. Each filter bag alternates between relatively lo ng periods of filtering and short periods of cleaning. During the cleaning period, fly ash th at has accumulated on the bags is removed by pulses of air and then falls into a hoppe r for storage and subsequent disposal.

Cleaning is either initiated at a preset differen tial pressure across the tubesheet or based on a maximum time between cleanings. Bags in a PJFF are cleaned by directing a pulse of pressurized air down the filter bag countercurrent to the flue gas flow to induce a traveling ripple (pulse) in the filter bag. This pulse travels the length of the bag, deflecting the bag outward and separating
the dust cake as it moves.

An advantage of a fabric filter over an ESP is that a fabric filter is not dependent on the resistivity of the fly ash. Since the fabric filter uses bags instead of an electric charge to remove the particles, the resistivity of the particles is not an issue. Fabric filters also have a lower dependence on particle size than ESPs. A disadvant age of fabric filters is that they have a tendency to corrode and clog with high sulfur co al applications. The high sulfur coals produce
more SO 3 , which tends to create problems with the fabr ic filters. Therefore, ESPs are typically used on high sulfur coal applications instead of fabric filters. Another disadvantage of fabric filters is the associated pressure drop. The ba gs, which collect a cake of particles, create an obstruction to the gas path. Fabric filters typi cally have approximately three times the pressureC-3 11/2/2009 drop of an ESP. Fabric filter s have been proven to control PM removal efficiency in excess of
99%.

C1.1 ELECTROSTATIC PRECIPITATOR (ESP) ESPs are commonly used as the primary filterable PM control device on coal fired units. The ESP discharge electrodes generate a high voltage elect rical field that gives the particulate matter an electric charge (positive or negative). The charged particles will then be collected on a collection plate. A rapper or hammer system will be utilized to vibrate the collected particles off of the plates so they can fall into the hop pers for storage and subsequent disposal.

The advantages of an ESP include the fact that an ESP can be applied to high sulfur coals, and the pressure drop across an ESP is relatively low comp ared to other alternatives such as a fabric filter. Unlike the fabric filter, which uses ba gs as the filter media, an ESP does not contain elements that can plug in the presence of SO 3 . The unobstructed design of the ESP results in a pressure drop that is approximately 1/3 of a corr esponding fabric filter. The disadvantage of the ESP is that its effectiveness to remove particulate is dependant on the resistivity of the fly ash and particle size. ESPs have been proven to cont rol PM removal efficiency in excess of 99%.

C1.1 COMPACT HYBRID PARTICULATE COLLECTOR (COHPAC) A COmpact Hybrid PArticulate Collector (COHPAC) is a high air-to-cloth ratio pulse jet fabric filter located downstream of an existing ESP. The COHPAC acts as a polishing device for control of particulate emissions. The differ ence between a COHPAC and the fabric filter
described above is that a COHPAC is installed after an ESP. The ESP prior to the COHPAC will remove the majority of the fly ash. This allows the COHPAC to have a higher air-to-cloth ratio than a typical fabric filter. The air-to-cloth ratio for a COHPAC unit is typically greater than or equal to 6 ACFM/ft 2 while the air-to-cloth ratio for a typical pulse jet fabric filter is approximately 3.5 to 4.0 ACFM/ft 2 . Because Big Stone Plant does not have an ESP and already uses a fabric filter for particulate control, the use of a COHPAC is not considered further.