NOx BEST AVAILABLE CONTROL TECHNOLOGY 

ANALYSIS STUDY - SUPPLEMENTAL REPORT 

for 

Milton R. Young Station Unit 2 

Minnkota Power Cooperative, Inc. 

Operating Agent for 

Square Butte Electric Cooperative 

Owner 

November 2009 

31777 
NOx Best Available 

Control Technology 

Analysis Study 

 SUPPLEMENTAL REPORT 

for 

Milton R. Young Station Unit 2 

prepared for 

Minnkota Power Cooperative, Inc. and 

Square Butte Electric Cooperative 

November 2009 

Project No. 31777 

prepared by 

Burns & McDonnell Engineering Company, Inc. 

Kansas City, Missouri 

COPYRIGHT 2009 © BURNS & McDONNELL ENGINEERING COMPANY, INC. 

Supplemental BACT Control and Cost-Effectiveness Table of Contents 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative TOC-1 Burns & McDonnell 

TABLE OF CONTENTS 

4.0 SUPPLEMENTAL NOx BACT ANALYSIS CONTROLS & COSTS – 

MRY STATION UNIT 2................................................................................. 4-1 

4.01 ADDITIONAL NOx CONTROLS......................................................................4-2 

4.1 RANK OF NOx CONTROL OPTIONS BY EFFECTIVENESS................................4-3 

4.1.1 ESTIMATING CONTROL-EFFECTIVENESS OF NOx EMISSIONS CONTROL 

OPTIONS....................................................................................................4-4 

4.2 NOx CONTROLS ANALYSIS AND IMPACTS EVALUATION.................................4-8 

4.2.1 NOx CONTROL ECONOMIC IMPACTS FOR MRY STATION UNIT 2.....................4-8 

4.2.1.1 CAPITAL COST ESTIMATES FOR NOx CONTROL ALTERNATIVES..................4-9 

4.2.1.1.1 CAPITAL COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF 

SCR NOx CONTROL ALTERNATIVES.......................................................4-12 

4.2.1.2 O&M COST ESTIMATES FOR NOx CONTROL ALTERNATIVES.......................4-18 

4.2.1.2.1 O&M COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF 

SCR NOx CONTROL ALTERNATIVES.......................................................4-21 

4.2.1.3 LEVELIZED TOTAL ANNUAL COST ESTIMATES FOR MRY STATION NOx 

CONTROLS.............................................................................................4-29 

4.2.2 ENERGY IMPACTS OF HYPOTHETICALLY-APPLIED NOx CONTROL 

ALTERNATIVES FOR MRY STATION UNIT 2..................................................4-42 

4.2.3 ENVIRONMENTAL IMPACTS OF HYPOTHETICALLY-APPLIED 

SCR NOx CONTROL ALTERNATIVES FOR MRY STATION UNIT 2.....................4-45 

4.2.4 SUMMARY OF ECONOMIC, ENERGY, AND ENVIRONMENTAL IMPACTS OF 

HYPOTHETICALLY-APPLIED SCR NOx CONTROL ALTERNATIVES FOR MRY 

STATION UNIT 2.........................................................................................4-46 

4.2.5 CONCLUSIONS .........................................................................................4-48 

REFERENCES.....................................................................................................4-53 
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Square Butte Electric Cooperative TOC-2 Burns & McDonnell 

LIST OF TABLES

Table 4-1 – Ranked NOX Control Options for MRY Station Unit 2 Boiler with Expected Control 

Performance 

Table 4-2 – Expected Annual NOX Control Performance for MRY Station Unit 2 Alternatives 

Table 4-3SA – Unit Capital Cost Factors of NOX Control Alternatives for MRY Station Unit 2 – 

Stand Alone SCR Projects 

Table 4-3SF – Unit Capital Cost Factors of NOX Control Alternatives for MRY Station Unit 2 – 

Shared Facilities SCR Projects 

Table 4-4SA – Estimated Capital Costs for NOX Control Alternatives - MRY Station Unit 2 – 

Stand Alone SCR Projects 

Table 4-4SF – Estimated Capital Costs for NOX Control Alternatives - MRY Station Unit 2 – 

Shared Facilities SCR Projects 

Table 4-5SA – Estimated Capital Costs for Hypothetically-Applied SCR Alternatives - 

MRY Station Unit 2 – Stand Alone SCR Projects

Table 4-5SF – Estimated Capital Costs for Hypothetically-Applied SCR Alternatives - 

MRY Station Unit 2 – Shared Facilities SCR Projects 

Table 4-6SA – Estimated O&M Costs for NOX Control Alternatives – MRY Station Unit 2 – 

Stand Alone SCR Projects

Table 4-6SF – Estimated O&M Costs for NOX Control Alternatives – MRY Station Unit 2 – 

Shared Facilities SCR Projects

Table C.4-1 – Expected Availability Reductions for MRYS Unit 2 NOX Controls 

Table C.4-2 – Expected Capacity Reductions for MRYS Unit 2 NOX Controls 

Table C.4-3 – Expected Auxiliary Electrical Power Demand Changes for MRYS Unit 2 NOX Controls 

Table C.4-4 – Expected Auxiliary Electrical Power Demand and Generation Reduction Cost Changes for 

MRYS Unit 2 NOX Controls 

Table 4-7SA – Estimated Annual Emissions and Levelized Total Annual Cost for NOX Control 

Alternatives– MRY Station Unit 2 – Stand Alone SCR Projects 

Table 4-7SF – Estimated Annual Emissions and Levelized Total Annual Cost for NOX Control 

Alternatives– MRY Station Unit 2 – Shared Facilities SCR Projects 

Table 4-8SA – Dominant Controls Cost Curve Points for NOX Control Alternatives – MRY Station Unit 2 

– Stand Alone SCR Projects 

Table 4-8SF – Dominant Controls Cost Curve Points for NOX Control Alternatives – MRY Station Unit 2 

– Shared Facilities SCR Projects 

Table 4-9SA – Estimated Emissions and Economic Impacts Summary for NOX Control Alternatives – 

MRY Station Unit 2 – Stand Alone SCR Projects 

Table 4-9SF – Estimated Emissions and Economic Impacts Summary for NOX Control Alternatives – 

MRY Station Unit 2 –Shared Facilities SCR Projects 

Table 4-10 – Energy Impacts for NOX Control Alternatives – MRY Station Unit 2 
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Square Butte Electric Cooperative TOC-3 Burns & McDonnell 

Table 4-11SA – Summary of Supplemental BACT Analysis Impact Results for Dominant NOX Control 

Alternatives – MRY Station Unit 2 – Stand Alone SCR Projects 

Table 4-11SF – Summary of Supplemental BACT Analysis Impact Results for Dominant NOX Control 

Alternatives – MRY Station Unit 2 – Shared Facilities SCR Projects 

LIST OF FIGURES 

Figure 4-1SA – NOX Control Cost Effectiveness – MRY Station Unit 2 – Stand Alone SCR Projects 

Figure 4-1SF – NOX Control Cost Effectiveness – MRY Station Unit 2 – Shared Facilities SCR Projects 

Figure 4-2SA – MRY Station Unit 2 NOX Control Alternatives BACT Dominant Controls Cost Curve – 

Stand Alone SCR Projects 

Figure 4-2SF – MRY Station Unit 2 NOX Control Alternatives BACT Dominant Controls Cost Curve – 

Shared Facilities SCR Projects 

* * * * * 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-1 Burns & McDonnell 

4.0 SUPPLEMENTAL NOx BACT ANALYSIS CONTROLS & COSTS – MRY 

STATION UNIT 2 

This supplement to the NOX BACT analysis for Milton R. Young Station (MRYS) Unit 2 has been 

prepared in response to a request of the North Dakota Department of Health1

. The NDDH requested 

completion of a “full” BACT analysis for two specific technologies that had been eliminated at step 2 of 

the BACT analysis process2

 in the October 2006 NOX BACT Analysis Study report3. These two 

technologies are low-dust selective catalytic reduction (SCR) and tail-end SCR. The approach taken in 

this supplemental NOX BACT Analysis Study report for MRYS Unit 2 includes ranking by control 

effectiveness and an impacts analysis of alternate control technologies for NOX emissions that follows the 

third and fourth steps of a “top down” BACT analysis as described in the EPA’s Draft New Source 

Review Workshop Manual4

. The initial NOX BACT Analysis Study for Milton R. Young Station 

identified potentially available NOX control techniques and technologies, summarized in Table 3-35

 of the 

October 2006 report. Commonly-applied and novel NOX control techniques and technologies, including a 

technical description of the specific emission reduction processes and capabilities, were summarized in 

Section 3.26

 and detailed in Appendix A1 of the October 2006 NOX BACT Analysis Study report. This 

supplemental analysis report does not include the details of the technical feasibility discussion previously 

provided in the initial NOX BACT Analysis Study report for MRYS Unit 2. 

SCR technology is considered technically infeasible by Minnkota for application at MRYS, so this 

information for the hypothetical application of low-dust and tail end SCR alternatives is included for 

comparative purposes only. Cost estimates and emission rates shown for such hypothetically-applied 

SCR systems are based on assumptions that known or expected reasons for technical infeasibility for 

installation, operation and maintenance of the SCR equipment on this boiler are solvable. There is no 

available information on recently-completed similar tail-end or low-dust SCR projects on coal-fired 

powerplants in the United States that could be used, with adjustments, to represent total installed costs 

that could be expected for MRYS Unit 2. Site-specific needs and challenges identified for applying tail 

end and low-dust SCR technologies to Milton R. Young Station Unit 2 significantly influence the capital 

cost estimate for variations of these hypothetical applications of SCR alternatives. Furthermore, the 

 

1

 See Reference number 1, July 2009 and August 2009. 

2

 As described in the EPA’s Draft New Source Review Workshop Manual. See Reference number 2, October 1990. 

3

 See Reference number 3, October 2006. This Supplement commences with Section 4.0, which places it at the end 

of the October 2006 Analysis, which ended at Section 3.5.2. 

4

 As described in the EPA’s Draft New Source Review Workshop Manual. Ibid Reference number 2, October 1990. 

5

 Ibid Reference number 3, October 2006, page 3-5. 

6

 Ibid Reference number 3, October 2006, page 3-6 through page 3-13, and pages A1-1 through A1-55. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-2 Burns & McDonnell 

“EPA Air Pollution Control Cost Manual” is not applicable for use in estimating control equipment costs 

for these hypothetical applications of SCR technologies, as the EPA Control Cost Manual states: 

“The costs for the tail-end arrangement, however, cannot be estimated from this report because 

they are significantly higher than the high-dust SCR systems due to flue gas reheating 

requirements.”7

 

This requirement for flue gas reheating also applies to the hypothetical application of low-dust SCR to 

MRYS, due to the cold-side arrangement (downstream of the electrostatic precipitator) instead of a hotside ESP assumed in the EPA Control Cost Manual. Therefore, the equations in the EPA Control Cost 

Manual cannot be used for estimating either of the hypothetical application of SCR configurations for 

which NDDH has requested economic analyses. Thus it was necessary to prepare independent sitespecific cost estimates. 

The site-specific control costs estimated for application of hypothetical tail-end and low-dust SCR 

alternatives to MRYS Unit 2 are significantly higher than the EPA’s cost-effectiveness analysis for 

conventional SCR technologies included in the technical support document issued with the final Regional 

Haze Regulations and BART Guidelines8

. Low-dust and tail end SCR technologies should be excluded 

from consideration for NOX control at MRYS due to unacceptably high average and incremental cost per 

ton of pollutant removal based on the supplemental analysis provided herein. The October 2006 NOX

BACT Analysis Study report, and additional subsequent arguments included in responses to comments by 

the EPA, Department of Justice (DOJ), NDDH, and other parties9

, also present reasons for technical 

infeasibility of all SCR technologies considered for application at MRYS not included in this 

supplemental analysis report. In addition, the fact that catalyst vendors will not guarantee catalyst life on 

such SCR technologies without successful results from extensive pilot slipstream testing bolsters the 

previous submitted arguments of technical infeasibility of these NOX control alternatives at MRYS. 

4.0.1 ADDITIONAL NOx CONTROLS 

The inclusion of hypothetical emissions control alternatives employing tail-end and low-dust SCR 

technologies in this supplemental NOX BACT Analysis Study report does not constitute agreement by 

 

7

 See Reference number 10, Section 4.2, Chapter 2, page 2-41, October 2000. 

8

 See Reference number 4, June, 2005. 

9

 Responses submitted by Minnkota in 2007-2009. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-3 Burns & McDonnell 

Minnkota or Square Butte that it is technically feasible to install these technologies on Unit 2 at Milton R. 

Young Station. The rationale for rejection of all forms of SCR technology in this specific case, based on 

an interpretation of the EPA’s Draft New Source Review Workshop Manual10, has previously been 

submitted to the North Dakota Department of Health11 and is not repeated herein. Nevertheless, this 

supplemental NOX BACT Analysis Study report has been completed based on the hypothetical 

assumption that these two technologies pass the test for technical feasibility. The development of NOX

emissions control alternatives involving hypothetical application of technologies such as low-dust and tail 

end SCR systems at MRYS is based on preliminary plant layout design concepts that require pilot-scale 

slipstream SCR testing and more detailed equipment design for confirmation that all technical 

infeasibility issues previously raised have been, or can be, satisfactorily resolved. This supplemental 

analysis includes estimated capital costs and operating and maintenance (O&M) costs for four variations 

of alternatives involving hypothetical applications of tail-end and low-dust SCR technologies. Cost 

effectiveness for each hypothetically-applied SCR control technology case was plotted with previouslyanalyzed feasible control alternatives. 

For the techniques and technologies considered for determining MRYS Unit 2 NOX control costeffectiveness, estimates were produced for predicted NOX reductions that represent long-term 

expectations of the reduction techniques and technologies being presented in the technical analysis. Each 

evaluated alternative was tabulated and graphed. 

It should be noted that as of October 2006, when the initial BACT Analysis Study report was completed, 

MRYS Unit 2 did not employ combustion-related or post-combustion NOX emission reduction 

technology. However, the installation of an advanced form of a separated overfire air system (ASOFA), 

designed specifically for this boiler, was implemented for operation starting prior to December 31, 2007. 

A summary of the available alternate NOX emission control technologies is discussed below. 

4.1 RANK OF NOX CONTROL OPTIONS BY EFFECTIVENESS 

The first step12 in this supplemental “top-down” BACT evaluation is to determine the expected control 

effectiveness of the hypothetical application of tail end and low-dust SCR technology alternatives, so that 

they may be compared and ranked relative to the technically-feasible NOX control techniques and 

 

10 Ibid Reference number 3, October 1990. 

11 See Reference number 5, November 2007. 

12 Step 3 per the NSR Manual, Ibid Reference 2, October 1990. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-4 Burns & McDonnell 

technologies included from the initial NOX BACT Analysis Study report. To do this, we start with the 

basis for determining the NOx emissions control effectiveness, which is the historic baseline emissions 

expressed in pounds per million Btu of heat input from the five-year lookback period. 

Unit 2 boiler’s baseline pre-control emissions at Milton R. Young Station are based upon the same 

highest rolling 12-month average unit emission rate (lb/mmBtu) and corresponding highest rolling 12-

month average gross heat input rate (mmBtu/hr) that were reported in 2001-2005: 

• MRYS Unit 2’s highest 12-month NOX mass emissions averaged 0.786 lb/mmBtu at a 

corresponding average unit heat input rate of 4,885 mmBtu/hr and unit gross electrical output of 

440 MWg. 

• During this lookback time period, Unit 2 at Milton R. Young Station was typically operated in a 

base-loaded manner. 

4.1.1 ESTIMATING CONTROL-EFFECTIVENESS OF NOX EMISSIONS 

CONTROL OPTIONS 

The estimated emission control performance for NOX control techniques and technologies included from 

the initial NOX BACT Analysis Study report is assumed to be the same as previously stated in Table 3-

713. The expected control effectiveness of the hypothetical application of tail end and low-dust SCR 

technology alternatives was added to the listing of highest-performing NOX control alternatives remaining 

in consideration following the initial technical infeasibility determinations. These alternatives are ranked 

in declining order of expected emission reduction. These combined control options refer to “advanced” 

separated overfire air (ASOFA), and include the expected reduction from operating with modestly airstaged cyclone furnaces and relocated lignite drying system vent ports as applied to this Milton R. Young 

cyclone boiler without incurring potential significant negative impacts of this technique. This level of 

expected NOX reduction from ASOFA operation is approximately thirty eight percent below the precontrol baseline emissions rate of 0.786 lb/mmBtu. 

 

13 Ibid Reference number 3, October 2006, page 3-18. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-5 Burns & McDonnell 

TABLE 4-1 – Ranked NOX Control Options for MRY Station 

Unit 2 Boiler with Expected Control Performance 

Alt. 

Label(1) NOX Control Alternative 

Emission Rate 

(lb/mmBtu) 

Control 

Percentage(2) 

T2 Hypothetical Tail-End SCR w/ ASOFA – Scenario A(3) 0.049 93.8(4) 

T1 Hypothetical Tail-End SCR w/ ASOFA – Scenario B(3) 0.049 93.8(4)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(3) 0.049 93.8(4)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(3) 0.049 93.8(4) 

E SNCR (using urea) w/ ASOFA 0.330 58.0 

D Gas Reburn with ASOFA 0.350 55.4 

C Lignite Reburn w/ ASOFA 0.360 54.2 

B Fuel Lean Gas Reburn with ASOFA 0.432 45.0 

A Advanced Separated Overfire Air (ASOFA) 0.489 37.7 

- Baseline 0.786 - 

(1) - Alternative designation assigned from highest to lowest unit NOx emission rate. 

(2) - Control percentages are relative to an average pre-control emission baseline of 0.786 lb/mmBtu based on annual operation at 

highest pre-control 12-month rolling NOx summation mass emissions divided by the 12-month heat input summation. 

(3) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The emission rate shown for a hypotheticallyapplied SCR system is based on assumptions that known or expected reasons for technical infeasibility for installation of the 

SCR equipment on this boiler are solvable. SCR technology is considered technically infeasible by Minnkota for 

application at MRYS per the October 2006 NOx BACT Analysis Study report and subsequent submittals in response to 

comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application of SCR 

alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that 

assumes replacement of SCR catalyst after a specified number of hours of unit operation. 

(4) - The stated overall control percentage includes the anticipated long-term emission reduction of 90% design removal from a 

baseline of 0.49 lb/mmBtu resulting from an advanced separated overfire air system, with air-staged low-NOX cyclone 

combustion. Without a separated overfire air system operation or any other technique employed, the assumed emission rate 

for hypothetically-applied SCR alternatives would be 0.079 lb/mmBtu, for an overall reduction of 90 percent from a 

baseline of 0.786 lb/mmBtu. 

All hypothetical applications of tail-end and low-dust SCR technology alternatives were assumed to 

achieve a NOX emission level of 0.049 lb/mmBtu, which is approximately a 90% reduction from a 0.49 

lb/mmBtu level representing ASOFA when operating modestly air-staged cyclone furnaces with suitable 

combustion controls. 

Hourly mass emission rates for the baseline pre-control condition were calculated by multiplying the unit 

emission rate (lb/mmBtu) by the average hourly gross heat input rate (mmBtu/hr), both calculated from 

Unit 2’s highest 12-month NOX mass emissions and heat inputs during the 5-year lookback period. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-6 Burns & McDonnell 

Equivalent annual NOX emissions (tons) were calculated by multiplying the 12-month summation for unit 

operating hours during the same period as the highest NOX emissions by the 12-month average mass 

emission rate (lb/hr) and dividing by 2000 lb/ton. 

The annual tons for the control options were calculated by multiplying the alternative’s equivalent 

average annual hourly mass emission rate (lb/h) by the equivalent annual unit operating hours [8,760 h/yr 

maximum possible operating time, adjusted by an annual uptime (availability) factor]. Scheduled and 

unplanned maintenance outages are expected to occur due to each hypothetically-applied SCR system. 

Catalyst cleaning and replacement events have been estimated, with two frequencies showing a range of 

possible results. Due to the variability and possible severity of fouling characteristics of gaseous and 

aerosol particulate emissions generated by cyclone combustion of lignite supplied from the Center mine, 

and the dependency of the fouling within the hypothetically-applied SCR systems on sodium, potassium, 

sulfur, and ammonia slip emission levels, conditions may occur during operation of the hypotheticallySCR systems that exceed the ability to adjust operational practices sufficiently to avoid forced outages to 

remove the deposits or prevent significant catalyst deactivation. Table C.4-1 in Section 4.2.1.2.1 includes 

estimated unit availability and corresponding operating time and outage time due to the four hypothetical 

applications of SCR technology cases, along with the ASOFA and baseline numbers from the referenced 

Appendix C3 of the initial NOX BACT Analysis Study report14. Based on these calculations, the 

estimated annual emissions for M.R. Young Station Unit 2 and the emission reduction corresponding to 

each technology alternative are shown in Table 4-2. 

 

14 Ibid Reference number 3, October 2006, pages C3-1 through page C3-11. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions _________________________________________________________________________________________________________________________________ Square Butte Electric Cooperative 4-7 Burns & McDonnell 

TABLE 4-2 – Expected Annual NOX Control Performance for MRY Station Unit 2 Alternatives 

EMISSIONS

Emission 

Rate 

Hourly 

Emission(2) 

Annual 

Emission(3) 

Emission 

Reduction(4) Alt. 

Label(1) NOx Control Alternative lb/mmBtu lbs/hr tons/yr tons/yr 

NOx 

Removal 

Efficiency(5) 

%

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(6) 0.049 239 936 14,857 93.8(7)T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(6) 0.049 239 813 14,980 93.8(7)L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(6) 0.049 239 931 14,862 93.8(7)L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(6) 0.049 239 813 14,980 93.8(7)

E SNCR (using urea) w/ ASOFA 0.330 1,612 6,421 9,372 58.0 

D Gas Reburn w/ ASOFA 0.350 1,710 6,882 8,910 55.4 

C Lignite Reburn w/ ASOFA 0.360 1,759 6,964 8,829 54.2 B Fuel Lean Gas Reburn w/ ASOFA 0.432 2,110 8,490 7,303 45.0 

A Advanced Separated Overfire Air (ASOFA) 0.489 2,391 9,621 6,172 37.7 

- Baseline 0.786 3,839 15,793 0 - 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Hourly NOX emission estimates (lb/hr) were calculated based upon average annual unit emission rate (lb/mmBtu) x 4,885 mmBtu/hr heat input. (3) - Estimated annual emission tons assume an annual unit availability factor specific to each alternative; 93.9% was assumed for the baseline case. 

See Appendix C3 of the October 2006 NOX BACT Analysis Study report. Hypothetically-applied tail end SCR case T2 assumes an annual unit availability factor of 89.5% (approx. 7,842 operating hours per year) and case T1 assumes an annual unit availability factor of 77.8% (approx. 6,813 operating hours per year. Hypotheticallyapplied low-dust SCR case L2 assumes an annual unit availability factor of 89.0% (approx. 7,801 operating hours per year) and case L1 assumes an annual unit availability factor of 77.8% (approx. 6,813 operating hours per year). 

(4) - Estimated annual tons of emission reduction is the difference between annual baseline tons and each alternative’s annual emissions (tons). (5) - Estimated NOX control level percentage reductions relative to 0.786 lb/mmBtu emission baseline at 4,885 mmBtu/hr MCR heat input. (6) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 2 

at Milton R. Young Station. The emission rate shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical infeasibility for installation and operation and maintenance of the SCR equipment on this boiler are solvable. SCR technology is considered technically infeasible by 

Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, 

DOJ, and other parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for 

details of Scenario A and Scenario B that assume replacement of SCR catalyst after a specified number of hours of unit operation. 

(7) - The stated overall control percentage includes the anticipated long-term emission reduction of 90% design removal from a baseline of 0.49 lb/mmBtu resulting from an 

advanced separated overfire air system, with air-staged low-NOX cyclone combustion. Without a separated overfire air system operation or any other technique 

employed, the assumed emission rate for hypothetically-applied SCR alternatives would be 0.079 lb/mmBtu, for an overall reduction of 90 percent from a baseline of 

0.786 lb/mmBtu. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-8 Burns & McDonnell 

4.2 NOX CONTROLS ANALYSIS AND IMPACTS EVALUATION 

The next step15 of this supplemental “top-down” BACT analysis is to evaluate the impacts of the 

hypothetical application of SCR alternatives’ NOX emission controls. Energy, economic, and 

environmental impacts are to be considered in the control technology evaluation. The purpose of the 

evaluation is to determine if there are any energy, economic or environmental impacts that would eliminate 

the top control technologies from consideration. 

This evaluation of the effectiveness of the hypothetically-applied SCR alternatives, as well as that of the 

other control technologies previously considered technically feasible, was performed prospectively, i.e., 

assuming that none of the control technologies has been implemented. This approach assumes that the 

hypothetical application of SCR technology cases are considered to have been added to the previous NOX

BACT Analysis Study report submitted in October, 2006. The actual costs incurred and performance 

achieved for an installed advanced separated overfire air system, or firm price equipment quotes with 

performance guarantees for SNCR alternatives, that have been determined after the submittal of the 2006 

NOX BACT Analysis Study report, have not been used to adjust the control effectiveness or cost impacts of 

the previously analyzed control alternatives. The approach taken in this supplemental analysis uses 

installed capital costs estimated in calendar year 2009 escalated to project completion forecast in 2017 

adjusted to calendar year 2006 basis for the hypothetically-applied tail end SCR and low-dust SCR 

technology cases that have been added to the list of alternatives previously evaluated. 

4.2.1 NOX CONTROL ECONOMIC IMPACTS FOR MRY STATION UNIT 2 

An evaluation was performed to determine the various cost impacts of installing previously-analyzed 

feasible NOX control alternatives and hypothetical application of low-dust and tail end SCR technologies on 

Milton R. Young Unit 2. This evaluation includes estimated: 

• Capital costs; 

• Fixed and variable operating and maintenance costs; and 

• Levelized total annual costs 

to engineer, design, procure, construct, install, startup, test, and place into commercial operation the 

particular control technology. The results of this evaluation are summarized in Tables 4-3 through 4-11. 

 

15 Step 4 per the NSR Manual, Ibid Reference 2, October 1990. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-9 Burns & McDonnell 

4.2.1.1 CAPITAL COST ESTIMATES FOR NOX CONTROL ALTERNATIVES 

The range of estimated capital costs to implement some of the various NOX control technologies were 

derived from unit output capital cost factors ($/kW) published in technical papers discussing those control 

technologies. For MRY Station Unit 2, for the cases involving the use of advanced separated overfire air 

and SNCR alternatives, preliminary project cost estimates using vendor budgetary cost information were 

developed and used in place of, or to adjust, the published unit output cost factors. A discussion of the 

reburn alternatives’ estimated capital costs was included in the 2006 NOX BACT Analysis Study report and 

has not been repeated here. These cost estimates were considered to be study grade, which is + or – 30% 

accuracy. 

For the hypothetical application of low-dust and tail end SCR alternatives at MRYS, there is no available 

information on recently-completed similar projects on coal-fired powerplants in the United States that could 

be used, with adjustments, to properly represent total installed costs that could be expected for MRYS Unit 

2. For these alternatives, site-specific detailed preliminary (conceptual) designs were developed and 

budgetary cost information for major equipment was obtained for the development of the estimated 

installed capital cost. 

The unit nameplate output capacity (gross electrical output in megawatts) assumed for the installed capital 

cost estimate basis of the NOX control technologies evaluated was 477 MWg for MRY Station Unit 216. 

A review of the unit capital cost factor range and single point factors applicable to MRY Station Unit 2 

NOX control technologies are presented in Tables 4-3SA and 4-3SF. Note that the capital cost estimates for 

the hypothetical application of SCR alternatives were developed separately based on two different 

assumptions. In one case it was assumed that all costs for the hypothetically-applied Unit 2 SCR (tail end 

or low-dust) system would be accounted for as if the SCR equipment were being provided for Unit 2 only. 

This is referred to as the “stand alone” (SA) case, and all tables showing those costs are identified with that 

suffix. In the other case, it was assumed that the retrofit of hypothetically-applied SCR systems was being 

done for both Unit 1 and Unit 2, and there are some components that could be shared between the two units. 

This is referred to as the “shared facilities” (SF) case, and all tables showing those costs are identified with 

that suffix. 

 

16 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 390. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

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Square Butte Electric Cooperative 4-10 Burns & McDonnell 

Per the EPA’s NSR Manual, a BACT analysis is done on a “case-by-case basis”17. The “stand alone” 

estimated total project capital costs for the hypothetical application of SCR alternatives reflect the economic 

impacts incurred as a result of implementing such technologies on each individual unit at MRYS 

independent of what may be determined or assumed for other units at this facility or similar units at other 

facilities. The “shared facilities” estimated total project capital costs for the hypothetical application of 

SCR alternatives do not account for all economic impacts borne strictly by the unit subject to the analysis, 

and as such, are subsidized by the unit(s) involved with the shared facilities. In this “shared facilities” 

approach, a BACT would be performed more in the manner of a “case-within-a-case” instead of on a “caseby-case” basis. Additionally, BACT is not to be applied on a facility basis. Units having different 

characteristics, (size, etc.) may have different technologies as BACT. Therefore, each unit should be 

treated as a separate “stand alone” case. Although the authors believe the “stand alone “case is the proper 

approach to use, information for both cases has been provided. 

TABLE 4-3SA – Unit Capital Cost Factors of 

NOX Control Alternatives for MRY Station Unit 2 - Stand Alone SCR Projects 

Alt. 

Label(1) NOX Control Alternative 

Range(2)

($/kW) 

Single Point Unit 

Capital Cost 

Factor(3), ($/kW) 

MRYS Unit 2

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(4) (4) 714(4),(5) 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) (4) 714(4),(5)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) (4) 568(4),(5)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) (4) 568(4),(5)

E SNCR (using urea) w/ ASOFA 20-35(6) 35.9(5),(6)

D Gas Reburn w/ ASOFA 15-30(7) 74.4(5),(7),(8) 

C Lignite Reburn w/ ASOFA 30-60(7) 170.2(5),(7),(9) 

B Fuel Lean Gas Reburn w/ ASOFA --(6) 45.7(5),(6),(8) 

A Advanced Separated Overfire Air (ASOFA) 5-10(7) 21.0(5) 

(1) - Alternative designation has been assigned from highest to lowest unit NOx emission rate. 

(2) - Unit capital cost factors ($/kW) of these individual technologies combined by simple addition. Actual installed costs may 

differ from this due to positive or negative synergistic effects. Range based on published values or vendor proposals. 

(3) - Single point cost factor is best estimate for determination of total capital cost for a particular technology or combination,

assuming maximum unit capacity is based on EPA’s nameplate rating. Single point cost figures in 2006 dollars.

(4) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The single point unit capital cost factor shown 

for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical 

 

17 Ibid Reference 2, October 1990, Chapter B. Introduction page B1. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-11 Burns & McDonnell 

infeasibility for installation of the SCR equipment on this boiler are solvable. SCR technology is considered technically 

infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent 

submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical 

application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A 

and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation. Due to the 

site-specific nature of factors influencing cost, no comparable cost data ranges for these technologies exist in the 

literature. A cost range for conventional high-dust SCR technology published in the 2005 EPA Report “Multipollutant 

Emission Control Technology Options for Coal-fired Power Plants”, EPA-600/R-05/03418 was $55 to $150/kW. Single 

point unit capital cost factors were derived from Burns & McDonnell internal database and cost estimates prepared 

specifically for MRYS Unit 2 in 2017 dollars converted to 2006$ as described in the text. 

(5) - The single point unit capital cost factor shown for the “advanced” version of SOFA derived from Burns & McDonnell 

internal database and cost estimate for North Dakota lignite-fired cyclone boilers.

(6) - Estimated capital cost for SNCR point estimate and FLGR point estimate derived from December 2004 budgetary 

proposal by Fuel Tech. The unit capital cost factor range for FLGR applications on boilers without an existing a highpressure natural gas supply was not found in available technical literature. See Appendix C2 of the October 2006 NOX

BACT Analysis Study report for details19. 

(7) - NESCAUM 2005 Technical Paper20; reburn alternatives on page 2-22, overfire air on page 2-23; posted at their website. 

See technical references in Appendix A1 of the October 2006 NOX BACT Analysis Study report for details..

(8) - The single point unit capital cost factor shown for a conventional or fuel-lean gas reburn system includes the estimated 

capital cost to install a high-pressure natural gas supply pipeline (31.4 $/kW or 15.7 $/kW, respectively), and that both 

MRYS boilers share the capital cost in proportion to their respective rated MW gross output capacities.

(9) - The single point unit capital cost factor shown for a lignite reburn system is highly site-specific, and assumes that new 

pulverizers and building enclosures are required. The general cost range for pulverized coal-fired boilers is included in 

the NESCAUM 2005 Technical Paper; for cyclone boilers is included in the 2005 WRAP Draft Report21, posted at their 

website. The single point unit capital cost factor for this alternative for increased PM collection capacity included in 

lignite reburn option is 75.5 $/kW. See technical references in Appendix A1 of the October 2006 BACT Analysis report 

for details. 

TABLE 4-3SF – Unit Capital Cost Factors of 

NOX Control Alternatives for MRY Station Unit 2 – Shared Facilities SCR Projects 

Alt. 

Label(1) NOX Control Alternative 

Range(2)

($/kW) 

Single Point Unit 

Capital Cost 

Factor(3), ($/kW) 

MRYS Unit 2

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(4) (4) 671(4),(5) 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) (4) 671(4),(5)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) (4) 525(4),(5)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) (4) 525(4),(5)

E SNCR (using urea) w/ ASOFA 20-35(6) 35.9(5),(6)

D Gas Reburn w/ ASOFA 15-30(7) 74.4(5),(7),(8) 

C Lignite Reburn w/ ASOFA 30-60(7) 170.2(5),(7),(9) 

B Fuel Lean Gas Reburn w/ ASOFA --(6) 45.7(5),(6),(8) 

A Advanced Separated Overfire Air (ASOFA) 5-10(7) 21.0(5) 

 

18 See Reference number 6, March 2005, page 3-63. 

19 See Reference number 3, October 2006, pages C2-3 and C2-7. 

20 See Reference number 7, March 2005. 

21 See Reference number 8, April 2005, page 3-9. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-12 Burns & McDonnell 

(1) - Alternative designation has been assigned from highest to lowest unit NOx emission rate. 

(2) - Unit capital cost factors ($/kW) of these individual technologies combined by simple addition. Actual installed costs 

may differ from this due to positive or negative synergistic effects. Range based on published values or vendor proposals. 

(3) - Single point cost factor is best estimate for determination of total capital cost for a particular technology or combination,

assuming maximum unit capacity is based on EPA’s nameplate rating. Single point cost figures in 2006 dollars. 

(4) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The single point unit capital cost factor shown 

for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical 

infeasibility for installation of the SCR equipment on this boiler are solvable. SCR technology is considered technically 

infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent 

submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical 

application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A 

and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation. Due to the 

site-specific nature of factors influencing cost, no comparable cost data ranges for these technologies exist in the 

literature. A cost range for conventional high-dust SCR technology published in the 2005 EPA Report “Multipollutant 

Emission Control Technology Options for Coal-fired Power Plants”, EPA-600/R-05/03422 was $55 to $150/kW. Single 

point unit capital cost factors were derived from Burns & McDonnell internal database and cost estimates prepared 

specifically for MRYS Unit 2 in 2017 dollars converted to 2006$ as described in the text. 

(5) - The single point unit capital cost factor shown for the “advanced” version of SOFA derived from Burns & McDonnell 

internal database and cost estimate for North Dakota lignite-fired cyclone boilers. 

(6) - Estimated capital cost for SNCR point estimate and FLGR point estimate derived from December 2004 budgetary 

proposal by Fuel Tech. The unit capital cost factor range for FLGR applications on boilers without an existing a highpressure natural gas supply was not found in available technical literature. See Appendix C2 of the October 2006 NOX

BACT Analysis Study report for details23. 

(7) - NESCAUM 2005 Technical Paper24; reburn alternatives on page 2-22, overfire air on page 2-23; posted at their website. 

See technical references in Appendix A1 of the October 2006 NOX BACT Analysis Study report for details..

(8) - The single point unit capital cost factor shown for a conventional or fuel-lean gas reburn system includes the estimated 

capital cost to install a high-pressure natural gas supply pipeline (31.4 $/kW or 15.7 $/kW, respectively), and that both 

MRYS boilers share the capital cost in proportion to their respective rated MW gross output capacities. 

(9) - The single point unit capital cost factor shown for a lignite reburn system is highly site-specific, and assumes that new 

pulverizers and building enclosures are required. The general cost range for pulverized coal-fired boilers is included in 

the NESCAUM 2005 Technical Paper; for cyclone boilers is included in the 2005 WRAP Draft Report25, posted at their 

website. The single point unit capital cost factor for this alternative for increased PM collection capacity included in 

lignite reburn option is 75.5 $/kW. See technical references in Appendix A1 of the October 2006 BACT Analysis report 

for details. 

4.2.1.1.1 CAPITAL COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF 

SCR NOX CONTROL ALTERNATIVES 

There is no available information on recently-completed similar tail-end or low-dust SCR projects on coalfired powerplants in the United States that could be used, with adjustments, to represent total installed costs 

that could be expected for MRYS Unit 2. Site-specific needs and challenges identified for applying tail end 

and low-dust SCR technologies to Milton R. Young Station Unit 2 significantly influence the capital cost 

estimate for variations of these hypothetical alternatives. Furthermore, the “EPA Air Pollution Control Cost 

Manual” is not applicable for use in estimating control equipment costs for these hypothetical applications 

of SCR technology cases, as the EPA Control Cost Manual states: 

 

22 See Reference number 6, March 2005, page 3-63. 

23 See Reference number 3, October 2006, pages C2-3 and C2-7. 

24 See Reference number 7, March 2005. 

25 See Reference number 8, April 2005, page 3-9. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-13 Burns & McDonnell 

“The costs for the tail-end arrangement, however, cannot be estimated from this report because they 

are significantly higher than the high-dust SCR systems due to flue gas reheating requirements.”26 

This requirement for flue gas reheating also applies to the hypothetical application of low-dust SCR to 

MRYS, due to the cold-side arrangement (downstream of the electrostatic precipitator) instead of a hot-side 

ESP assumed in the EPA Control Cost Manual. Therefore, the equations in the EPA Control Cost Manual 

cannot be used for estimating either of the hypothetical SCR configurations for which NDDH has requested 

economic analyses. Thus it was necessary to prepare independent site-specific cost estimates. 

The installed capital costs for hypothetical application of tail end and low-dust SCR alternatives were 

estimated by Burns & McDonnell with inputs from an SCR system supplier with recent design experience 

involving these SCR configurations, equipment suppliers, and catalyst suppliers with significant European 

project experience in such technology. Both hypothetically-applied low-dust and tail end SCR designs for 

MRYS Unit 2 assume two reactor / gas reheat systems installed in parallel, each connecting to one of the 

two existing wet lime flue gas desulfurization absorbers also arranged in parallel configuration. Each 

alternative includes flue gas reheat equipment that is typical for these applications but not required for 

conventional high-dust/hot side SCRs. The estimated flue gas volume at a gross boiler heat input and 

oxygen content corresponding to unit gross nameplate output capacity determined the size of the two 

hypothetically-applied SCR reactors for these cases. Structures, foundations, ductwork, balance of plant 

equipment and materials were quantified and included with the hypothetically-applied SCR equipment, 

which were factored for installation costs. Escalation of project costs, including equipment, materials, 

engineering and labor costs, is included, along with interest during construction, due to the expected project 

execution duration being significantly longer than for the other alternatives. Price and scope contingencies 

were included to account for the uncertainties that the current preliminary design scope and pricing fully 

reflects what would be necessary to complete implementation of these hypothetically-applied alternatives. 

Total project costs were considered to be a future value from a financial perspective, which were returned to 

a 2009 calendar year basis using a present value factor at the 2.5% per year annual discount rate previously 

assumed in the 2006 NOX BACT Analysis Study report. A ratio of regional construction cost indices for 

public utility construction costs between 2006 and 2009 was used to adjust the 2009 total estimated project 

costs to a 2006 calendar year basis for each of the hypothetically-applied SCR alternatives. 

 

26 See Reference number 10, Section 4.2, Chapter 2, page 2-41, October 2000. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-14 Burns & McDonnell 

The estimated installed and levelized annual capital costs for the hypothetically-applied SCR systems and 

previously-analyzed highest-performing form of the various feasible NOX emission reduction technologies 

evaluated for cost-effectiveness are shown in Table 4-4SA and Table 4-4SF. These technologies are listed 

in order of control effectiveness, with the highest ranked option at the top. 

TABLE 4-4SA – Estimated Capital Costs for 

NOX Control Alternatives - MRY Station Unit 2 - Stand Alone SCR Projects 

Alt. 

Label(1) NOx Control Alternative

Installed 

Capital 

Cost(2) 

$1,000 

Annualized 

Capital 

Cost(3) 

$1,000 

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(4) 340,733(4) 29,707(4) 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) 340,733(4) 29,707(4)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 270,785(4) 23,608(4)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) 270,785(4) 23,608(4) 

E SNCR w/ ASOFA 17,128 1,493 

D Gas Reburn w/ ASOFA(5) 35,490 3,094 

C Lignite Reburn w/ ASOFA(6) 81,167 7,077 

B Fuel Lean Gas Reburn w/ ASOFA(5) 21,817 1,902 

A Advanced SOFA (ASOFA) 10,008 873 

 Baseline 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. 

(2) - Installed capital cost is estimated for determination of total capital cost for a particular technology or 

combination, assuming 477 MWg unit capacity rating. All cost figures in 2006 dollars. See Table 4-5SA for 

presentation of installed capital costs determined for hypothetical application of SCR alternatives. 

(3) - Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. 

(4) - The inclusion of tail end and low-dust SCR technologies in this table does not constitute agreement that it is 

technically feasible to install these technologies on Unit 2 at Milton R. Young Station. The installed capital 

cost shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons 

for technical infeasibility for installation of the SCR equipment on this boiler are solvable. Costs are derived 

from Burns & McDonnell internal database and cost estimates prepared specifically for MRYS Unit 2 in 

2017 dollars converted to 2006$ as described in the text. SCR technology is considered technically infeasible 

by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and 

subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this 

information for the hypothetical application of SCR alternatives is included for comparative purposes only. 

See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after 

a specified number of hours of unit operation. 

(5) - Costs for gas reburn options include high-pressure natural gas supply pipeline installed capital cost of 

$14,988,000 for CGR and $7,494,000 for FLGR; and annualized capital cost of $1,307,000/yr for CGR and 

$653,000 for FLGR. See footnote number 8 under Table 4-3SA. 

(6) - Costs for increased PM collection capacity included in lignite reburn option are $36,013,000 for installed 

capital cost, and $3,140,000/yr annualized capital cost. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-15 Burns & McDonnell 

TABLE 4-4SF – Estimated Capital Costs for 

NOX Control Alternatives - MRY Station Unit 2 – Shared Facilities SCR Projects 

Alt. 

Label(1) NOx Control Alternative

Installed 

Capital 

Cost(2) 

$1,000 

Annualized 

Capital 

Cost(3) 

$1,000 

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(4) 320,279(4) 27,923(4) 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) 320,279(4) 27,923(4)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 250,487(4) 21,839(4)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 250,487(4) 21,839(4) 

E SNCR w/ ASOFA 17,128 1,493 

D Gas Reburn w/ ASOFA(5) 35,490 3,094 

C Lignite Reburn w/ ASOFA(6) 81,167 7,077 

B Fuel Lean Gas Reburn w/ ASOFA(5) 21,817 1,902 

A Advanced SOFA (ASOFA) 10,008 873 

 Baseline 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. 

(2) - Installed capital cost is estimated for determination of total capital cost for a particular technology or 

combination, assuming 477 MWg unit capacity rating. All cost figures in 2006 dollars. See Table 4-5SF for 

presentation of installed capital costs determined for hypothetical application of SCR alternatives. 

(3) - Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. 

(4) - The inclusion of tail end and low-dust SCR technologies in this table does not constitute agreement that it is 

technically feasible to install these technologies on Unit 2 at Milton R. Young Station. The installed capital cost 

shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for 

technical infeasibility for installation of the SCR equipment on this boiler are solvable. Costs are derived from 

Burns & McDonnell internal database and cost estimates prepared specifically for MRYS Unit 2 in 2017 dollars 

converted to 2006$ as described in the text. SCR technology is considered technically infeasible by Minnkota 

for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals in 

response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical 

application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of 

Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit 

operation. 

(5) - Costs for gas reburn options include high-pressure natural gas supply pipeline installed capital cost of 

$14,988,000 for CGR and $7,494,000 for FLGR; and annualized capital cost of $1,307,000/yr for CGR and 

$653,000 for FLGR. See footnote number 8 under Table 4-3SF. 

(6) - Costs for increased PM collection capacity included in lignite reburn option are $36,013,000 for installed 

capital cost, and $3,140,000/yr annualized capital cost. 

The Total Project Costs estimated for tail end and low-dust SCR technologies hypothetically-applied to 

MRYS Unit 2 are shown in Table 4-5SA and Table 4-5SF in 2017, 2009, and 2006 dollars. 

The estimated installed capital costs for the hypothetical application of tail end or low-dust SCR system 

retrofits on MRYS Unit 2 include the following equipment and components: 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-16 Burns & McDonnell 

• Two SCR reactors utilizing a “3 +1” arrangement of catalyst layers, in which three layers of 

catalyst are initially installed, and space for installation of a fourth layer is provided. 

• Sootblowers for each catalyst layer to maintain cleanliness of catalyst 

• Flue gas reheat equipment that is typical for these applications but not required for conventional 

high-dust/hot side SCRs. This reheat equipment includes rotary regenerative heat exchangers (gasto-gas heaters [GGH]) and natural gas-fired duct burners. 

• Underground high-pressure natural gas supply pipeline and pressure regulators and metering 

equipment 

• Hot air recirculation and heating equipment to maintain catalyst in a warm and dry condition during 

standby periods 

• Induced draft booster fan and dampers 

• Interconnecting ductwork 

• SCR bypass duct and dampers (used during times the boiler is off-line) 

• Storage tanks, building, and equipment for unloading and preparation of liquid urea solution 

• Circulation pumps and piping for urea solution 

• Urea-to-ammonia thermal conversion with urea conversion, metering, atomization, and injection 

equipment 

• Ammonia gas dilution/combustion air fans and burners for natural gas-firing to decompose the urea 

solution to ammonia 

• Service and sootblowing air compressors with dryers 

• Electrical motor control centers 

• Controls and instrumentation 

• Reinforced concrete foundations 

• Active coal yard storage modifications to regain lost live capacity and handling equipment due to 

space consumed by the SCR reactor structures 

• Installation labor, materials, and management 

Addition of new electrical loads to the existing plant facilities will be required for the reagent system and 

new induced draft booster fan power consumption. Based on recent plant electrical distribution equipment 

installations, additional plant auxiliary electrical power will be available for powering the new 

hypothetically-applied SCR equipment. Confirmation of these concepts and cost estimates prior to any 

subsequent plans for implementation requires successful completion of extensive pilot-scale slipstream 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-17 Burns & McDonnell 

testing, and more detailed plant layout and equipment design than has been performed as part of this 

supplemental update to the October 2006 NOX BACT Analysis Study report. 

The capital cost estimated individually for an ASOFA system retrofit on MRYS Unit 2 as previously 

described in the initial NOX BACT Analysis Study report was simply arithmetically added to the 

hypothetical application of SCR alternatives’ capital cost estimates. 

TABLE 4-5SA – Estimated Capital Costs for 

Hypothetically-Applied SCR Alternatives - MRY Station Unit 2 - 

Stand Alone SCR Projects 

Alt. 

Label(1) Hypothetical SCR Alternative(2) 

Estimated 

BMcD Study 

Total Project 

Cost(3), 

2017$ x 1000 

Estimated 

BMcD Study 

Modified 

TP Cost(4), 

2009$ x 1000 

Estimated 

BMcD Study 

Adjusted

TP Cost(5), 

2006$ x 1000

T2, T1 Tail End SCR 436,346 358,129 325,240 

Urea preparation and storage, 

building, and equipment(6) _ 6,040(6) 5,485(6)

 ASOFA _ _ 10,008 

T2, T1 TOTAL _ _ 340,733(6)

L2, L1 Low-Dust SCR 342,502 281,107 255,292 

Urea preparation and storage, 

building, and equipment 

_ 6,040(6) 5,485(6)

ASOFA _ _ 10,008 

L2, L1 TOTAL _ _ 270,785(6)

(1) All SCR alternatives are assumed to have the same SCR outlet NOx emission rate. 

(2) The inclusion of tail end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible 

to install these technologies on Unit 2 at Milton R. Young Station. 

(3) The Total Project Cost shown for each hypothetically-applied SCR system was estimated by Burns & McDonnell based on scope 

assumptions for installation of the SCR equipment on this boiler as described in the text, except as described in footnote 6 below. 

SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT 

Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this 

information for the hypothetical application of SCR alternatives is included for comparative purposes only Does not include 

installed capital cost for ASOFA, as shown in Table 4-4SA. 

(4) Modified Total Project Costs are converted from 2017$ to 2009$ as described in the text, except as described in footnote 6 

below. Present Value factor (discounted from future value) is 0.82075. 

(5) Adjusted Total Project Costs are converted from 2009$ to 2006$ as described in the text. Handy-Whitman Index of Public 

Utility Construction Costs ratio is 0.908. 

(6) Urea preparation and storage, building, and equipment installed capital costs were estimated separately in 2009$, and then 

adjusted using the Handy-Whitman cost ratio of 0.908 to get 2006$. The TOTAL numbers above are the sum of the Adjusted 

Total Project Cost; urea preparation and storage, building, and equipment; and total Installed Capital Costs (TICC) for ASOFA 

alternative = estimated TICC for the hypothetically-applied SCR alternatives in Table 4-4SA. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-18 Burns & McDonnell 

TABLE 4-5SF – Estimated Capital Costs for 

Hypothetically-Applied SCR Alternatives - MRY Station Unit 2 - 

Shared Facilities SCR Projects 

Alt. 

Label(1) Hypothetical SCR Alternative(2) 

Estimated 

BMcD Study 

Total Project 

Cost(3), 

2017$ x 1000 

Estimated 

BMcD Study 

Modified 

TP Cost(4), 

2009$ x 1000 

Estimated 

BMcD Study 

Adjusted

TP Cost(5),(6), 

2006$ x 1000

T2, T1 Tail End SCR 411,063 337,379 306,395 

Urea preparation and storage, 

building, and equipment(6) _ 4,268(6) 3,876(6) 

 ASOFA _ _ 10,008 

T2, T1 TOTAL _ _ 320,279(6)

L2, L1 Low-Dust SCR 317,429 260,529 236,603 

Urea preparation and storage, 

building, and equipment _ 4,268(6) 3,876(6)

ASOFA _ _ 10,008 

L2, L1 TOTAL _ _ 250,487(6)

(1) All SCR alternatives are assumed to have the same SCR outlet NOx emission rate. 

(2) The inclusion of tail end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. 

(3) The Total Project Cost shown for each hypothetically-applied SCR system was estimated by Burns & McDonnell based on 

scope assumptions for installation of the SCR equipment on this boiler as described in the text, except as described in footnote 

6 below. SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 

NOX BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other 

parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. 

Does not include installed capital cost for ASOFA, as shown in Table 4-4SF. 

(4) Modified Total Project Costs are converted from 2017$ to 2009$ as described in the text, except as described in footnote 6 

below. Present Value factor (discounted from future value) is 0.82075. 

(5) Adjusted Total Project Costs are converted from 2009$ to 2006$ as described in the text. Handy-Whitman Index of Public 

Utility Construction Costs ratio is 0.908. 

(6) Urea preparation and storage, building, and equipment installed capital costs were estimated separately in 2009$, and then 

adjusted using the Handy-Whitman cost ratio of 0.908 to get 2006$. The TOTAL numbers above are the sum of the Adjusted 

Total Project Cost; urea preparation and storage, building, and equipment; and total Installed Capital Costs (TICC) for ASOFA 

alternative = estimated TICC for the hypothetically-applied SCR alternatives in Table 4-4SF. 

4.2.1.2 O&M COST ESTIMATES FOR NOX CONTROL ALTERNATIVES 

Operational costs to implement the hypothetical application of SCR alternatives and previously-analyzed 

feasible NOX control alternatives for Milton R. Young Unit 2 were estimated using preliminary conceptual 

designs and budgetary vendor quotes in place of, or to adjust, the OAQPS cost factors established in the 

EPA’s Air Pollution Control Cost Manual (OAQPS) for SNCR27 and SCR28, and using other costs from 

 

27 See Reference number 9, October 2000. 

28 See Reference number 10, October 2000. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-19 Burns & McDonnell 

published technical papers discussing those control technologies. Maintenance costs were estimated as 

percentages of installed capital costs, with additional catalyst replacement costs using budgetary vendor 

quotes based on preliminary conceptual designs and expected design life. 

Fixed and variable operating and maintenance costs considered and included in each NOX control 

technology’s annual O&M costs are estimates of: 

• Auxiliary electrical power consumption (megawatt-hours) and incremental purchased power unit 

costs for operating the additional control equipment; 

• Natural gas consumption and unit cost for hypothetical application of SCR alternatives’ flue gas 

reheating and urea-to-ammonia thermal conversion systems and feasible fuel reburn alternatives; 

• Reagent consumption and reagent unit cost for hypothetical application of SCR alternatives and 

feasible SNCR alternatives; 

• Reagent dilution water consumption and unit cost for feasible SNCR alternatives. 

• Catalyst removal and replacement for hypothetical application of SCR alternatives. 

• Increases or savings in auxiliary electrical power consumption for changes in coal preparation 

equipment and loading, primarily for fuel reburn cases; 

• General operating labor, plus maintenance labor and materials devoted to the additional emission 

control equipment and its impact on existing boiler and plant equipment; 

• Costs for purchase of replacement electrical power expected to result from loss of unit availability, 

i.e., outages attributable to the control option which reduce annual net electrical generation 

available for distribution. 

For economic evaluation purposes, a 12-month rolling average running plant capacity factor of 95.2 percent 

(based on a historic (demonstrated) sustainable unit output capacity of 462 MWg) combined with a 12-

month rolling average availability (uptime) of 8,229 operating hours (93.9 percent of 8760 hours per year) 

resulting in an equivalent annual average unit capacity factor of 89.5% was assumed for Unit 2’s precontrol baseline annual operation. A 12-month rolling average heat input rate of 4,885 mmBtu/hr and a 12-

month rolling average NOX emission rate of 0.786 lb/mmBtu from pre-control maximum rolling 12 month 

summation of nitrogen oxides mass emissions were assumed for calculating equivalent annual average 

control and cost-effectiveness for MRY Station Unit 2. 

Tables 4-6SA and 4-6SF show the estimated annual operating and maintenance costs and levelized annual 

O&M cost values for the hypothetically-applied SCR alternative cases and the highest-performing form of 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-20 Burns & McDonnell 

previously-evaluated feasible NOX emission reduction technologies. These are listed in order of control 

effectiveness, with the highest ranked options at the top. The cost methodology summarized in Appendix 

C3 of the 2006 NOx BACT Analysis Study report provides more details for the levelized annual O&M cost 

calculations and cost factors for the previously-analyzed feasible NOX control alternatives29. 

TABLE 4-6SA – Estimated O&M Costs for 

NOX Control Alternatives - MRY Station Unit 2 - 

Stand Alone SCR Projects 

Alt. 

Label(1)

NOx Control Alternative

Annual 

O&M 

Cost(2) 

$1,000 

Levelized 

Annual 

O&M 

Cost(2),(3) 

$1,000 

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(4) 31,512 39,350 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) 55,345 69,111 

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 29,048 36,273 

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) 52,424 65,463 

E SNCR w/ ASOFA 8,108 10,125 

D Gas Reburn w/ ASOFA 48,688 60,798 

C Lignite Reburn w/ ASOFA(5) 9,929 12,398 

B FLGR w/ ASOFA 21,954 27,415 

A Advanced SOFA (ASOFA) 2,805 3,503 

 Baseline 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. 

(2) - Annual operating and maintenance cost for a particular technology or combination is compared to unit 

baseline operation at an average unit output (462 MWg) and assumes a 94.7% average annual availability, 

which is highest consecutive 12-months of operation from 2001-2005. All cost figures in 2006 dollars. 

(3) - Levelized annual O&M cost = Annual O&M cost x 1.24873 annualized O&M cost factor. 

(4) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual O&M cost shown for a 

hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical infeasibility for 

installation and operation and maintenance of the SCR equipment on this boiler are solvable. Costs are derived from 

Burns & McDonnell internal database and cost estimate specific to MRYS Unit 2 in 2017 dollars. SCR technology is 

considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study 

report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties,, so this 

information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 

4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of 

hours of unit operation. 

(5) - Costs for increased PM collection capacity included in lignite reburn option are $3,358,000/yr for annual O&M cost, 

and $4,194,000/yr annualized O&M cost.

 

29 Ibid Reference number 3, October 2006, pages C3-1 through C3-11. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-21 Burns & McDonnell 

TABLE 4-6SF – Estimated O&M Costs for 

NOX Control Alternatives - MRY Station Unit 2 – 

Shared Facilities SCR Projects 

Alt. 

Label(1)

NOx Control Alternative

Annual 

O&M 

Cost(2) 

$1,000 

Levelized 

Annual 

O&M 

Cost(2),(3) 

$1,000 

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(4) 30,898 38,583 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) 54,731 68,345 

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 28,439 35,512 

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) 51,815 64,703 

E SNCR w/ ASOFA 8,108 10,125 

D Gas Reburn w/ ASOFA 48,688 60,798 

C Lignite Reburn w/ ASOFA(5) 9,929 12,398 

B FLGR w/ ASOFA 21,954 27,415 

A Advanced SOFA (ASOFA) 2,805 3,503 

 Baseline 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. 

(2) - Annual operating and maintenance cost for a particular technology or combination is compared to unit 

baseline operation at an average unit output (462 MWg) and assumes a 94.7% average annual availability, 

which is highest consecutive 12-months of operation from 2001-2005. All cost figures in 2006 dollars. 

(3) - Levelized annual O&M cost = Annual O&M cost x 1.24873 annualized O&M cost factor. 

(4) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual O&M cost shown for a 

hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical infeasibility for 

installation and operation and maintenance of the SCR equipment on this boiler are solvable. Costs are derived from 

Burns & McDonnell internal database and cost estimate specific to MRYS Unit 2 in 2017 dollars. SCR technology is 

considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study 

report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties,, so this 

information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 

4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of 

hours of unit operation. 

(5) - Costs for increased PM collection capacity included in lignite reburn option are $3,358,000/yr for annual O&M cost, 

and $4,194,000/yr annualized O&M cost. 

4.2.1.2.1 O&M COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF SCR 

NOX CONTROL ALTERNATIVES 

The hypothetical application of tail-end and low-dust SCR w/ ASOFA alternatives will involve significantly 

higher operating costs compared with the existing operation of MRYS Unit 2. The system uses an amine 

reagent in the form of concentrated aqueous urea solution, which is thermally converted to gaseous 

ammonia, carbon dioxide, and water vapor. The estimated unit cost of this urea was assumed to average 

$379/ton (delivered to the plant site via truck-tanker trailers; unit pricing based on 50% concentration as 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-22 Burns & McDonnell 

established for the 2006 NOX BACT Analysis Study report). Consumption of urea converted to ammonia 

reagent was based upon recent equipment vendor budgetary proposals and SCR consultant inputs. 

For the hypothetically-applied SCR cases, using the existing induced draft fans is not expected to 

significantly change the overall fan horsepower demand on those fans’ electric motors. There will be new 

plant electrical power demand due to new induced draft booster fans required to overcome the estimated 

additional flue gas pressure drop resulting from reactor, ductwork, and gas-to-gas heat exchanger equipment 

assumed for the hypothetically-applied SCR systems. The additional auxiliary electric power demand for 

the hypothetically-applied tail end SCR systems was calculated to be 14.9 MW, using estimated annual 

average electrical loads of the booster fan, direct flue gas reheat burner combustion air fans, urea-toammonia conversion dilution/combustion air fans, and SCR sootblower and service air compressor 

equipment based on preliminary equipment vendor budgetary proposals developed from Burns & 

McDonnell ductwork sizing and designs. Estimated annual average electrical power demands for 

hypothetically-applied low-dust SCR systems were calculated to be 12.4 MW. Replacement of electrical 

power resulting from these reductions in net unit electrical output was included as a cost, assuming $35 per 

megawatt-hour. 

Hypothetically-applied tail end and low-dust SCR equipment requiring annual maintenance includes 

booster fans, gas-to-gas heat exchangers, flue gas reheat duct burners, and compressor equipment. This 

general annual maintenance cost was estimated as 3 percent of installed capital costs. 

To account for the possible range of O & M costs due to catalyst replacement, two variations (Scenario A 

and Scenario B) were applied. These two scenarios were used for both hypothetical applications of tail-end 

and low-dust SCR technology alternatives. Each scenario was based on scheduled additions and/or 

replacement of the exposed catalyst after a certain number of hours of operation, repeated throughout the 20 

year operating span considered in the analysis. The current installed unit cost of replacement catalyst 

assumed for the hypothetical application of full-time tail end or low-dust SCR alternatives is $7,500 per 

cubic meter in 2006 dollars. The basis for development of the two scenarios is described below. 

During preparation of the cost estimate, Burns & McDonnell consulted with two SCR catalyst vendors 

experienced with biomass-fired boiler SCRs and European coal-fired boilers with low-dust and tail end 

SCR systems. However, neither of these vendors was willing to guarantee a catalyst replacement schedule 

for cyclone boilers firing North Dakota lignite without results following successful extensive pilot-scale 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-23 Burns & McDonnell 

slipstream testing that confirm the deactivation and fouling rates. According to these catalyst suppliers, 

there is no SCR operating experience in the world found to be directly comparable to the hypotheticallyapplied tail end and low-dust SCR cases on North Dakota lignite-fired cyclone boilers being evaluated. 

Thus they were unable to offer a guaranteed catalyst replacement schedule based on their experience. 

Based on information obtained in discussions with the catalyst vendors, the longest catalyst replacement 

schedule they would both agree upon as an estimated (not guaranteed) value was 16,000 hours. Both 

vendors indicated that actual experience could result in a shorter replacement cycle, and that the actual 

guarantee value could not be developed until extensive pilot testing had been completed. This led Burns & 

McDonnell to develop two hypothetically-applied SCR catalyst replacement scenarios to bracket possible 

outcomes. 

Scenario A assumed a catalyst replacement schedule of 16,000 hours. Specifically for MRYS Unit 2, this 

scenario is based on the replacement of one catalyst layer in each reactor every 16,000 operating hours. 

Scenario B assumed that the fouling of the catalyst would be severe, and that it would be necessary for 

Minnkota to perform catalyst maintenance at each scheduled boiler cleaning outage. The current schedule 

of boiler cleaning outages on Unit 2 is four times per year. Therefore, Scenario B for Unit 2 is based on the 

replacement of one catalyst layer in each reactor at each boiler cleaning outage. This means that each 

catalyst layer in the four layer SCR reactor is exposed to flue gas during approximately 12 months of 

operation and then is replaced. By assuming that catalyst management activities would coincide with 

scheduled boiler cleaning outages, Scenario B provides some minimization of the impact of catalyst 

replacement on unit operation. 

As noted above, it is not known what the actual frequency of catalysts replacement would need to be for a 

hypothetically-applied tail-end or low dust SCR system operating on a cyclone-fired boiler burning North 

Dakota lignite, but the two scenarios described above are the catalyst replacement numbers assumed for this 

comparative economic analysis. 

SCR catalyst replacements are additive to the general annual hypothetically-applied low-dust and tail end 

SCR equipment maintenance. Catalyst replacement costs are based on catalyst vendor quotation of volume 

of catalyst, estimated to be three layers initially (top, middle-upper and middle-lower) at 256 cubic meters 

per layer per reactor for two reactors in parallel. A fourth (bottom) layer at 342 cubic meters is expected to 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-24 Burns & McDonnell 

be required after initial operation of hypothetically-applied full-time tail end or low-dust SCR alternatives, 

as part of the catalyst replacement program. Catalyst replacement costs for the hypothetical application of 

SCR alternatives were estimated for the two different catalyst management scenarios described above. 

Annual unit operating time will be reduced as a result of the expected outages and maintenance of the 

hypothetically-applied SCR equipment, including catalyst cleaning and management practices. Additional 

outage time of 206 hours per year was estimated to be attributable to the hypothetical application of tail end 

SCR Scenario A alternative (assuming 16,000 hour catalyst life), and 1,235 hours per year for the Scenario B 

TESCR case (assuming four layers are replaced every year) over and above the outage time assumed for 

ASOFA impacts. Additional outage time of 247 hours per year was estimated to be attributable to the 

hypothetical application of low-dust SCR Scenario A alternative, and 1,235 hours per year for the Scenario B 

LDSCR case over and above outage time assumed for ASOFA impacts. The expected loss of electrical power 

generation from these reductions in net output was included as a cost, assuming $35 per megawatt-hour for 

replacement power. 

Table C.4-1 provides the estimated unit availability and corresponding operating time and outage time due to 

the four hypothetically-applied SCR technology cases, along with the ASOFA and baseline numbers from the 

referenced Appendix C3 of the initial NOX BACT Analysis Study report30. 

 

30 Ibid Reference number 3, October 2006, pages C3-1 through C3-11. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-25 Burns & McDonnell 

TABLE C.4-1 – Expected Availability Reductions for MRYS Unit 2 NOX Controls 

Estimated Annual Average Unit Operating Time 

 

 

Alt.1

 

 

 

NOx Control Alternative 

 

Unit 

Availability2

Unit 

Operating 

Time3

, 

hrs/yr 

Unit 

Outage 

Time4, 

hrs/yr 

Unit 

Operating 

Time Reduction5, 

hrs/yr 

T2 Hypothetical Tail End SCR 

w/ ASOFA – Scenario A(6) 0.895 7,842 918 387 

T1 Hypothetical Tail End SCR 

w/ ASOFA – Scenario B(6) 0.778 6,813 1,947 1,416 

L2 

Hypothetical Low-Dust 

SCR w/ ASOFA – Scenario 

A(6) 0.890 7,801 959 428 

L1 

Hypothetical Low-Dust 

SCR w/ ASOFA – Scenario 

B(6) 0.778 6,813 1,947 1,416 

E SNCR w/ ASOFA 0.909 7,965 795 264 

D Gas Reburn w/ ASOFA 0.919 8,048 712 181 

C Coal Reburn w/ ASOFA 0.904 7,916 844 313 

B FLGR w/ ASOFA 0.919 8,048 712 181 

A Advanced SOFA (ASOFA) 0.919 8,048 712 181 

 Baseline 0.939 8,229 531 0 

(1) – Alternative number has been previously assigned from least removal to highest removal percentage. 

(2) – 12-month baseline availability is assumed at 93.9 percent. These values reflect estimated amounts of negative reliability 

impact expected from the implementation of the individual NOx control technology. 

(3) – Annual operating time is annual average availability multiplied by 8760 hrs/yr of possible uptime. 

(4) – Annual outage time is 8760 hrs/yr possible operating time minus estimated annual operating time. 

(5) – Annual operating time reduction resulting from the implementation of the individual NOx control technique is the 

difference between the baseline and expected annual outage times. 

(6) – The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual unit availability factors 

shown for hypothetically-applied SCR systems are based on assumptions that known or expected reasons for technical 

infeasibility for installation and operation and maintenance of the SCR equipment on this boiler are solvable. SCR 

technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT 

Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties,, so 

this information for the hypothetical application of SCR alternatives is included for comparative purposes only. See 

Section 4.2.1.2.1 for details of Scenario A and Scenario B that assume replacement of SCR catalyst after a specified 

number of hours of unit operation. 

Table C.4-2 includes estimated equivalent average annual unit running plant capacity ratios and unit 

generation reductions due to the four hypothetically-applied SCR cases, along with the ASOFA and 

baseline numbers from the referenced Appendix C3 of the initial NOX BACT Analysis Study report31. 

These numbers assume the reduction in annual plant output is a combination of a reduction of annual 

operating time and capacity reductions associated with the control alternatives. 

 

31 Ibid Reference number 3, October 2006, pages C3-1 through C3-11. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-26 Burns & McDonnell 

TABLE C.4-2 – Expected Capacity Reductions for MRYS Unit 2 NOX Controls 

Estimated Annual Average Unit Electrical Power 

Generation Reduction from Operating Time Reduction 

 

 

Alt. 

Label(1) 

 

 

NOx Control Alternative 

Unit 

Running Plant 

Capacity Ratio(2)

Unit 

Generation 

Reduction(3)

kW-hrs/yr 

 

Unit Generation 

Reduction Cost(4), 

1000$/yr 

T2 Hypothetical Tail End SCR w/ 

ASOFA – Scenario A(5) 0.924 170,167,448 5,956 

T1 Hypothetical Tail End SCR w/ 

ASOFA – Scenario B(5) 0.924 622,740,448 21,796 

L2 Hypothetical Low-Dust SCR w/ 

ASOFA – Scenario A(5) 0.929 188,270,368 6,589 

L1 Hypothetical Low-Dust SCR w/ 

ASOFA – Scenario B(5) 0.929 622,740,448 21,796 

E SNCR w/ ASOFA 0.951 110,176,095 3,856 

D Gas Reburn w/ ASOFA 0.943 81,416,590 2,850 

C Lignite Reburn w/ ASOFA 0.948 130,375,506 4,563 

B FLGR w/ ASOFA 0.949 81,910,024 2,867 

A Advanced SOFA (ASOFA) 0.952 75,859,855 2,655 

 Baseline 0.952 0 0 

(1) - Alternative designation has been previously assigned from least removal to highest removal percentage. 

(2) - 12-month baseline running plant capacity ratio is assumed at 95.2 percent (= 440/462). These values reflect estimated 

amounts of negative annual output capacity impact expected from the implementation of the individual NOx control 

technique. Used only for calculation of annual power usage in Table C.4-3. 

(3) - Annual electricity generation reduction is annual unit operating time reduction multiplied by the 12-month average 

gross output of 440 MW. 

(4) - Annual electricity generation reduction cost is the annual electricity generation reduction (kW-hrs/yr) resulting from the 

implementation of the individual NOx control technique multiplied by the incremental value of electricity generation, 

assumed to be $35.00/MW-hr. All cost figures in 2006 dollars. 

(5) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual unit running plant 

capacity ratios shown for hypothetically-applied SCR systems are based on assumptions that known or expected reasons 

for technical infeasibility for installation and operation and maintenance of the SCR equipment on this boiler are solvable. 

SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX

BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other 

parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. 

See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified 

number of hours of unit operation. 

Table C.4-3 includes estimated unit gross and net electrical power demands (kilowatts) and annual usage 

(kW-hrs per year) used to calculate unit generation reductions and replacement electrical power costs due to 

the four hypothetically-applied SCR cases, along with the ASOFA numbers from the referenced Appendix 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-27 Burns & McDonnell 

C3 of the initial NOX BACT Analysis Study report 32. These numbers assume that the reductions of annual 

operating time and capacity associated with the control alternatives are also applied. 

TABLE C.4-3 – Expected Auxiliary Electrical Power Demand Changes 

for MRYS Unit 2 NOX Controls 

Estimated Annual Average APC NOx Equipment 

Auxiliary Electrical Power Demand and Usage 

 

 

Alt. 

Label(1) 

 

 

NOx Control Alternative 

Gross

Demand (2) 

kW 

Credit(3) 

kW 

Total Net 

Demand(4) 

kW 

Power 

Usage(5)

kW-hrs/yr 

Power Usage 

Cost(6), 

1000$/yr 

T2 Hypothetical Tail End SCR w/ 

ASOFA – Scenario A(7) 14,925 0 14,925 108,122,807 3,784 

T1 Hypothetical Tail End SCR w/ 

ASOFA – Scenario B(7) 14,925 0 14,925 93,941,913 3,288 

L2 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario A(7) 12,389 0 12,389 89,740,378 3,141 

L1 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario B(7) 12,389 0 12,389 78,381,807 2,743 

E SNCR w/ ASOFA 133 0 133 1,008,774 35 

D Gas Reburn w/ ASOFA 1 (228) (227) (1,724,428) (60) 

C Lignite Reburn w/ ASOFA 8,342 (448) 7,894 59,217,554 2,073 

B FLGR w/ ASOFA 1 (125) (124) (949,051) (33) 

A Advanced SOFA (ASOFA) 1 0 1 7,664 0.3 

(1) - Alternative designation has been previously assigned from least removal to highest removal percentage. 

(2) - The APC NOx equipment gross auxiliary electrical power demand of alternatives is the sum of the demand for individual 

technologies combined by simple addition. Actual power demands may differ from this due to positive or negative 

synergistic effects. Coal reburn includes 2,484 kW for feed preparation and conveying equipment demand plus 5,857 kW 

for the COHPAC system addition for PM control. 

(3) - The APC NOx equipment auxiliary electrical power demand credit of coal reburn alternatives is the estimated result of 

lower cyclone coal preparation and feeder power demand due to lower boiler cyclone coal equipment loading. Actual 

power demands may differ from this due to accuracy of estimates for assumed amount of operating horsepower reduction. 

(4) - The total net auxiliary electrical power demand is the sum of the gross demand and credit. 

(5) - The annual change in APC NOx equipment auxiliary electrical power demand electricity usage in kW-hrs/yr for these 

alternatives is the net power demand multiplied by the estimated annual operating time and running plant capacity ratio 

which reflects the adjustment for any expected availability and capacity impacts from the implementation of the control 

technique. 

(6) - The annual change in APC NOx equipment auxiliary electrical power demand electricity cost is the annual change in kWhrs/yr for these alternatives resulting from the implementation of the individual NOx control technique multiplied by the 

incremental value of electricity generation, assumed to be $35.00/MW-hr. All cost figures in 2006 dollars. 

(7) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated power demand shown for 

hypothetically-applied SCR systems are based on Burns & McDonnell estimates developed from preliminary equipment 

and ductwork sizing and designs with vendor budgetary proposals. SCR technology is considered technically infeasible 

by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals 

in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application 

of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and 

Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation. 

 

32 Ibid Reference number 3, October 2006, pages C3-1 through C3-11. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-28 Burns & McDonnell 

Table C.4-4 includes estimated net unit electrical annual power usage (kW-hrs per year) and expected 

reductions in annual operating time to calculate unit generation reductions and replacement electrical power 

costs due to the four hypothetically-applied SCR cases, along with the ASOFA numbers from the 

referenced Appendix C3 of the initial NOX BACT Analysis Study report33. These numbers assume the 

reduction in annual plant output is a combination of a reduction of net unit generation because of electrical 

power usage and reductions in annual operating time and capacity associated with the control alternatives. 

TABLE C.4-4 – Expected Auxiliary Electrical Power Demand and Generation 

Reduction Cost Changes for MRY Unit 2 NOX Controls 

Estimated Annual Change in Unit Generation Due to APC NOx 

Equipment Auxiliary Power Electricity Demand and Generation 

Reduction 

 

 

Alt. 

Label(1) 

 

 

NOx Control Alternative 

APC 

Electrical 

Power 

Usage(2)

kW-hrs/yr 

Unit 

Generation 

Reduction(3)

kW-hrs/yr 

Total Unit 

Electrical Power 

Generation 

Change(4)

kW-hrs/yr 

Total Unit 

Electrical Power 

Generation 

Change Cost(5)

1000$/yr 

T2 Hypothetical Tail End SCR 

w/ ASOFA – Scenario A(6) 108,122,807 170,167,448 278,290,255 9,740 

T1 Hypothetical Tail End SCR 

w/ ASOFA – Scenario B(6) 93,941,913 622,740,448 716,682,361 25,084 

L2 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario A(6) 89,740,378 188,270,368 278,010,746 9,730 

L1 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario B(6) 78,381,807 622,740,448 701,122,255 24,539 

E SNCR w/ ASOFA 1,008,774 110,176,095 111,184,869 3,891 

D Gas Reburn w/ ASOFA (1,724,428) 81,416,590 79,692,162 2,789 

C Lignite Reburn w/ ASOFA 59,217,554 130,375,506 189,593,059 6,636 

B FLGR w/ ASOFA (949,051) 81,910,024 80,960,972 2,834 

A Advanced SOFA (ASOFA) 7,664 75,859,855 75,867,520 2,655 

(1) - Alternative designation has been previously assigned from least removal to highest removal percentage. 

(2) - The annual change in APC NOx equipment auxiliary electrical power demand electricity usage in kW-hrs/yr for these 

alternatives is the net power demand multiplied by the estimated annual operating time and running plant capacity ratio 

which reflects the adjustment for any expected availability and capacity impacts from the implementation of the control 

technique. 

(3) - Annual electricity generation reduction is annual operating time reduction multiplied by the 12-month average gross output 

of 440 MW. 

(4) - The total unit electrical power generation change is the sum of the annual change in APC NOx equipment auxiliary 

electrical power demand electricity usage plus the annual electricity generation reduction resulting from the 

implementation of the individual NOx control alternative. 

(5) - The total unit electrical power generation change cost is the total generation change (kw-hrs/yr) multiplied by the 

incremental value of replacement electricity generation, assumed to be $35.00/MW-hr. All cost figures in 2006 dollars. 

 

33 Ibid Reference number 2, October 2006, pages C3-1 through C3-11. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-29 Burns & McDonnell 

(6) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated power demand shown for 

hypothetically-applied SCR systems are based on Burns & McDonnell estimates developed from preliminary equipment 

and ductwork sizing and designs with vendor budgetary proposals. SCR technology is considered technically infeasible 

by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals 

in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application 

of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and 

Scenario B that assume replacement of SCR catalyst after a specified number of hours of unit operation. 

4.2.1.3 LEVELIZED TOTAL ANNUAL COST ESTIMATES FOR MRY STATION 

NOX CONTROLS 

A comparison of the control versus cost-effectiveness of two hypothetical SCR cases and previouslyanalyzed feasible NOX control alternatives on Milton R. Young Unit 2 was made. This is summarized as 

shown in Tables 4-7SA and 4-7SF, Figures 4-1SA and 4-1SF, and Figures 4-2SA and 4-2SF for MRY 

Station Unit 2. 

TABLE 4-7SA – Estimated Annual Emissions and Levelized Total Annual Cost 

for NOX Control Alternatives - MRY Station Unit 2 - Stand Alone SCR Projects 

Alt. 

Label(1) NOx Control Alternative 

Annual NOx 

Emissions(2) 

Tons/yr 

Annual NOx 

Emissions 

Reduction(3) 

Tons/yr 

Levelized 

Total 

Annual 

Cost(4) 

$1,000 

Average 

Control 

Cost(5) 

$/ton 

T2 Hypothetical Tail End SCR 

w/ ASOFA – Scenario A(6) 936 14,857 69,057 4,648 

T1 Hypothetical Tail End SCR 

w/ ASOFA – Scenario B(6) 813 14,980 98,818 6,597 

L2 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario A(6) 931 14,862 59,881 4,029 

L1 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario B(6) 813 14,980 89,072 5,946 

E SNCR w/ ASOFA 6,421 9,372 11,618 1,240 

D Gas Reburn w/ ASOFA 6,882 8,910 63,892(7) 7,171 

C Lignite Reburn w/ ASOFA 6,964 8,829 19,475(8) 2,206 

B FLGR w/ ASOFA 8,490 7,303 29,317(7) 4,014 

A Advanced SOFA (ASOFA) 9,621 6,172 4,376 709 

 Baseline 15,793 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. 

(2) - Estimated annual emission tons assume an annual unit uptime availability factor specific to each alternative; 15,793 (= 

0.939*8760*3,839/2000) was assumed for the baseline case. 

(3) - Estimated annual tons of emission reduction is the difference between annual baseline tons and each alternative’s annual 

emissions (tons). 

(4) - Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. See note 3 from Tables 

4-4SA and 4-6SA for annualized cost factors. Emissions are calculated from unit emission rates, control percentage, 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-30 Burns & McDonnell 

hourly heat input, and annual hrs/yr operation compared to pre-control baseline emissions based on annual operation at 

baseline pre-control NOx emission rate. 

(5) - Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost ($/yr) divided by Annual Emission 

Reduction (tons/yr). All cost figures in 2006 dollars. 

(6) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual NOx removal and 

LTAC shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for 

technical infeasibility for installation of the SCR equipment on this boiler are unsolvable. Costs are derived from Burns 

& McDonnell internal database and cost estimate specifically for MRYS Unit 2 in 2006 dollars. SCR technology is 

considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study 

report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information 

for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for 

details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit 

operation. 

(7) - LTAC for gas reburn options include high-pressure natural gas supply pipeline annualized capital cost of $1,307,000/yr for 

CGR and $653,000 for FLGR. See footnote number 8 under Table 4-3SA. 

(8) - LTAC for increased PM collection capacity included in lignite reburn option are approximately $3,140,000 for annualized 

capital cost plus $4,194,000/yr for annualized O&M cost, for a LTAC subtotal of $7,333,000/yr. 

TABLE 4-7SF – Estimated Annual Emissions and Levelized Total Annual Cost 

for NOX Control Alternatives - MRY Station Unit 2 - Shared Facilities SCR Projects 

Alt. 

Label(1) NOx Control Alternative 

Annual NOx 

Emissions(2) 

Tons/yr 

Annual NOx 

Emissions 

Reduction(3) 

Tons/yr 

Levelized 

Total 

Annual 

Cost(4) 

$1,000 

Average 

Control 

Cost(5) 

$/ton 

T2 Hypothetical Tail End SCR 

w/ ASOFA – Scenario A(6) 936 14,857 66,506 4,477 

T1 Hypothetical Tail End SCR 

w/ ASOFA – Scenario B(6) 813 14,980 96,268 6,427 

L2 

Hypothetical Low-Dust 

SCR w/ ASOFA – Scenario 

A(6) 931 14,862 57,351 3,859 

L1 

Hypothetical Low-Dust 

SCR w/ ASOFA – Scenario 

B(6) 813 14,980 86,542 5,777 

E SNCR w/ ASOFA 6,421 9,372 11,618 1,240 

D Gas Reburn w/ ASOFA 6,882 8,910 63,892(7) 7,171 

C Lignite Reburn w/ ASOFA 6,964 8,829 19,475(8) 2,206 

B FLGR w/ ASOFA 8,490 7,303 29,317(7) 4,014 

A Advanced SOFA (ASOFA) 9,621 6,172 4,376 709 

 Baseline 15,793 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. 

(2) - Estimated annual emission tons assume an annual unit uptime availability factor specific to each alternative; 15,793 (= 

0.939*8760*3,839/2000) was assumed for the baseline case. 

(3) - Estimated annual tons of emission reduction is the difference between annual baseline tons and each alternative’s annual 

emissions (tons). 

(4) - Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. See note 3 from 

Tables 4-4SF and 4-6SF for annualized cost factors. Emissions are calculated from unit emission rates, control 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-31 Burns & McDonnell 

percentage, hourly heat input, and annual hrs/yr operation compared to pre-control baseline emissions based on annual 

operation at baseline pre-control NOx emission rate. 

(5) - Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost ($/yr) divided by Annual Emission 

Reduction (tons/yr). All cost figures in 2006 dollars. 

(6) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual NOx removal and 

LTAC shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for 

technical infeasibility for installation of the SCR equipment on this boiler are unsolvable. Costs are derived from Burns 

& McDonnell internal database and cost estimate specifically for MRYS Unit 2 in 2006 dollars. SCR technology is 

considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study 

report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information 

for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for 

details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit 

operation. 

(7) - LTAC for gas reburn options include high-pressure natural gas supply pipeline annualized capital cost of $1,307,000/yr 

for CGR and $653,000 for FLGR. See footnote number 8 under Table 4-3SF. 

(8) - LTAC for increased PM collection capacity included in lignite reburn option are approximately $3,140,000 for 

annualized capital cost plus $4,194,000/yr for annualized O&M cost, for a LTAC subtotal of $7,333,000/yr. 

Figure 4-1SA – NOX Control Cost Effectiveness - MRY Station Unit 2(1)

Stand Alone SCR Projects

Milton R. Young Station Unit 2 NOx Control 

Annual Removal vs Levelized Total Annual Cost - Stand Alone Projects

0

20000

40000

60000

80000

100000

120000

0 2000 4000 6000 8000 10000 12000 14000 16000

Annual NOx Removal, tons/yr

Levelized Total Annual Cost for NOx Control, 

1000$/yr

A = Advanced Separated Overfire Air (ASOFA)

B = Fuel Lean Gas Reburn w/ ASOFA

C = Lignite Reburn w/ ASOFA

D = Gas Reburn w/ ASOFA 

E = SNCR w/ ASOFA

T1 = Hypothetical Tail-End SCR 

w/ ASOFA (Scenario B)

T2 = Hypothetical Tail-End SCR 

w/ ASOFA (Scenario A)

L1 = Hypothetical Low-Dust SCR 

w/ ASOFA (Scenario B)

L2 = Hypothetical Low-Dust SCR

 w/ ASOFA (Scenario A) 

B

A

C

D

E

T1

T2

L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-7SA. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-32 Burns & McDonnell 

(2) - The inclusion of tail-end and low-dust SCR technologies in this figure does not constitute agreement that it is 

technically feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual 

NOx removal and LTAC shown for a hypothetically-applied SCR system is based on assumptions that known 

or expected reasons for technical infeasibility for installation of the SCR equipment on this boiler are solvable. 

SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 

2006 NOX BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, 

EPA, DOJ and other parties, so this information for the hypothetical application of SCR alternatives is included 

for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes 

replacement of SCR catalyst after a specified number of hours of unit operation. 

Figure 4-1SF – NOX Control Cost Effectiveness - MRY Station Unit 2(1)

Shared Facilities SCR Projects 

Milton R. Young Station Unit 2 NOx Control 

Annual Removal vs Levelized Total Annual Cost - Shared Facilities Projects

0

20000

40000

60000

80000

100000

120000

0 2000 4000 6000 8000 10000 12000 14000 16000

Annual NOx Removal, tons/yr

Levelized Total Annual Cost for NOx Control, 

1000$/yr

A = Advanced Separated Overfire Air (ASOFA)

B = Fuel Lean Gas Reburn w/ ASOFA

C = Lignite Reburn w/ ASOFA

D = Gas Reburn w/ ASOFA 

E = SNCR w/ ASOFA

T1 = Hypothetical Tail-End SCR 

w/ ASOFA (Scenario B)

T2 = Hypothetical Tail-End SCR 

w/ ASOFA (Scenario A)

L1 = Hypothetical Low-Dust SCR 

w/ ASOFA (Scenario B)

L2 = Hypothetical Low-Dust SCR

 w/ ASOFA (Scenario A) 

B

A

C

D

E

T1

T2

L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-7SF. 

(2) - The inclusion of tail-end and low-dust SCR technologies in this figure does not constitute agreement that it is 

technically feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual 

NOx removal and LTAC shown for a hypothetically-applied SCR system is based on assumptions that known 

or expected reasons for technical infeasibility for installation of the SCR equipment on this boiler are solvable. 

SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 

2006 NOX BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, 

EPA, DOJ and other parties, so this information for the hypothetical application of SCR alternatives is included 

for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes 

replacement of SCR catalyst after a specified number of hours of unit operation. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-33 Burns & McDonnell 

The purpose of Figures 4-1SA and 4-1SF is to show the range of control and cost for four hypotheticallyapplied SCR cases and previously-analyzed feasible NOX control alternatives on Milton R. Young Unit 2 

alternatives evaluated. 

Data points for conventional gas reburn (Point D) and fuel-lean gas reburn (Point B) with advanced separated 

overfire air, and lignite reburn with ASOFA (Point C), in Figures 4-1SA and 4-1SF are inferior and therefore 

were eliminated from further control cost-effectiveness analysis. 

A dominant set of control alternatives was determined by generating what is called the “envelope of least-cost 

alternatives”. The dominant controls cost curve is the best fit line through the points forming the rightmost 

boundary of the data zone on a scatter plot of the annual NOX removal tonnage versus LTAC for the various 

remaining BACT alternatives. Average and incremental annual costs and NOX emission reductions for the 

dominant least-cost control alternatives remaining after the elimination of the obviously inferior options are 

listed in Tables 4-8SA and 4-8SF. 

TABLE 4-8SA – Dominant Controls Cost Curve Points for 

NOX Control Alternatives - MRY Station Unit 2 - Stand Alone Projects

Alt. 

Label(1) 

NOx 

Control Alternative 

Levelized 

Total 

Annual 

Cost(2),(3) 

($1,000/yr) 

Annual 

Emission 

Reduction(3) 

(tpy) 

Incremental 

Levelized 

Total 

Annual 

Cost(2),(4)

($1,000/yr) 

Incremental

Annual 

Emission 

Reduction(4)

(tpy) 

Incremental 

Control Cost 

Effectiveness 

($/ton)(2),(4)

T2 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario A(5) 

69,057 14,857 57,439 5,485 10,472 

T1 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario B(5)

98,818 14,980 87,200 5,608 15,550 

L2 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario A(5)

59,881 14,862 48,263 5,490 8,792 

L1 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario B(5) 

89,072 14,980 77,454 5,608 13,812 

E SNCR w/ ASOFA 11,618 9,372 7,242 3,200 2,263 

A Advanced SOFA 

(ASOFA) 4,376 6,172 4,376 6,172 709 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. Dominant controls cost curve points 

from lowest (ASOFA) to highest (TESCR w/ ASOFA-16,000 hrs) are labeled the same as in Table 4-7SA, and on the graphs 

that accompany this table (Points B, C, and D were eliminated). 

(2) - All cost figures in 2006 dollars. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-34 Burns & McDonnell 

(3) - Annual emission reduction and levelized control cost of these alternatives is relative to current costs and pre-control unit

MCR baseline emission rate. 

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

(5) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The annual NOx removal and LTAC shown for 

a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical infeasibility for 

installation of the SCR equipment on this boiler are solvable. SCR technology is considered technically infeasible by 

Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals in 

response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application of 

SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B 

that assumes replacement of SCR catalyst after a specified number of hours of unit operation. 

TABLE 4-8SF – Dominant Controls Cost Curve Points for 

NOX Control Alternatives - MRY Station Unit 2 - Shared Facilities Projects

Alt. 

Label(1) 

NOx 

Control Alternative 

Levelized 

Total 

Annual 

Cost(2),(3) 

($1,000/yr) 

Annual 

Emission 

Reduction(3) 

(tpy) 

Incremental 

Levelized 

Total 

Annual 

Cost(2),(4)

($1,000/yr) 

Incremental

Annual 

Emission 

Reduction(4)

(tpy) 

Incremental 

Control Cost 

Effectiveness 

($/ton)(2),(4)

T2 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario A(5) 

66,506 14,857 54,888 5,485 10,007 

T1 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario B(5)

96,268 14,980 84,650 5,608 15,096 

L2 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario A(5)

57,351 14,862 45,733 5,490 8,331 

L1 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario B(5) 

86,542 14,980 74,924 5,608 13,361 

E SNCR w/ ASOFA 11,618 9,372 7,242 3,200 2,263 

A Advanced SOFA 

(ASOFA) 4,376 6,172 4,376 6,172 709 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. Dominant controls cost curve 

points from lowest (ASOFA) to highest (TESCR w/ ASOFA-16,000 hrs) are labeled the same as in Table 4-7SF, and on 

the graphs that accompany this table (Points B, C, and D were eliminated). 

(2) - All cost figures in 2006 dollars. 

(3) - Annual emission reduction and levelized control cost of these alternatives is relative to current costs and pre-control 

unit MCR baseline emission rate. 

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

(5) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The annual NOx removal and LTAC shown 

for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical 

infeasibility for installation of the SCR equipment on this boiler are solvable. SCR technology is considered technically 

infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent 

submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical 

application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A 

and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-35 Burns & McDonnell 

Figures 4-2SA and 4-2SF contain a repetition of the levelized total annual cost and NOX control information 

from Figure 4-1SA and 4-2SF for MRY Station Unit 2, with Point B (FLGRTM with ASOFA), Point C 

(Lignite Reburn with ASOFA) and Point D (conventional gas reburn with ASOFA) removed. This is the 

dominant controls cost curve for MRY Station Unit 2 NOX emissions alternatives. 

Figure 4-2SA – MRY Station Unit 2 NOX Control Alternatives 

BACT Dominant Controls Cost Curve(1) - Stand Alone SCR Projects 

 Milton R. Young Station Unit 2 NOx Control 

Dominant Controls Cost Curve - Stand Alone Projects

0

20,000

40,000

60,000

80,000

100,000

120,000

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000

Annual NOx Removal, tons/yr

Levelized Total Annual Cost for NOx 

Control, 1000$/yr 

A

E

T2

$15,550/ton T1

$709/ton $8,792/ton

Slope = Incremental $/ton

(Points B, C, and D removed)

$2,263/ton

A = Advanced Separated Overfire Air (ASOFA)

E = SNCR w/ ASOFA

T1 = Hypothetical Tail-End SCR w/ ASOFA (Scenario B)

T2 = Hypothetical Tail-End SCR w/ ASOFA (Scenario A)

L1 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario B)

L2 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario A) 

L2

L1

$10,472/ton 

$13,812/ton

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-8SA. 

(2) - The inclusion of tail-end and low-dust SCR technologies in this figure does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual NOx removal and

LTAC shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for 

technical infeasibility for installation and operation and maintenance of the SCR equipment on this boiler are solvable. 

SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX

BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other 

parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. 

See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified 

number of hours of unit operation. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-36 Burns & McDonnell 

Figure 4-2SF – MRY Station Unit 2 NOX Control Alternatives 

BACT Dominant Controls Cost Curve(1) – Shared Facilities SCR Projects 

 Milton R. Young Station Unit 2 NOx Control 

Dominant Controls Cost Curve - Shared Facilities Projects

0

20,000

40,000

60,000

80,000

100,000

120,000

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000

Annual NOx Removal, tons/yr

Levelized Total Annual Cost for NOx 

Control, 1000$/yr 

A

E

T2

$15,096/ton T1

$709/ton $8,331/ton

Slope = Incremental $/ton

(Points B, C, and D removed)

$2,263/ton

A = Advanced Separated Overfire Air (ASOFA)

E = SNCR w / ASOFA

T1 = Hypothetical Tail-End SCR w / ASOFA (Scenario B)

T2 = Hypothetical Tail-End SCR w / ASOFA (Scenario A)

L1 = Hypothetical Low -Dust SCR w / ASOFA (Scenario B)

L2 = Hypothetical Low -Dust SCR w / ASOFA (Scenario A) 

L2

L1

$10,007/ton 

$13,361/ton

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-8SF. 

(2) - The inclusion of tail-end and low-dust SCR technologies in this figure does not constitute agreement that it is technically 

feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual NOx removal and LTAC 

shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical 

infeasibility for installation and operation and maintenance of the SCR equipment on this boiler are solvable. SCR technology 

is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study 

report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for 

the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of 

Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation. 

As can be seen from a review of Table 4-7SA and Table 4-7SF, the average control cost effectiveness 

(called the unit control cost in this report) ranges from approximately $709/ton to $7,171/ton of MRYS Unit 

2’s NOX emissions removed. The unit control cost for the hypothetically-applied Scenario A Tail End SCR 

w/ ASOFA case was $4,648/ton and for the hypothetically-applied Scenario B Tail End SCR w/ ASOFA 

case was $6,597/ton (stand alone projects). The unit control cost for the hypothetically-applied Scenario A 

Low-Dust SCR w/ ASOFA case was $4,029/ton and for the hypothetically-applied Scenario B Low-Dust 

SCR w/ ASOFA case was $5,946/ton (stand alone projects). The unit control cost for the hypotheticallyapplied Scenario A Tail End SCR w/ ASOFA case was $4,477/ton and for the hypothetically-applied 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-37 Burns & McDonnell 

Scenario B Tail End SCR w/ ASOFA case was $6,427/ton (shared facilities projects). The unit control cost 

for the hypothetically-applied Scenario A Low-Dust SCR w/ ASOFA case was $3,859/ton and for the 

hypothetically-applied Scenario B Low-Dust SCR w/ ASOFA case was $5,777/ton (shared facilities 

projects). Unit control cost for SNCR w/ ASOFA was $1,240/ton, nearly twice that of ASOFA ($709/ton). 

It should be noted, however, that very high estimated average control costs involve fuel lean gas reburn 

($4,014/ton) and conventional gas reburn ($7,171/ton) technologies that were previously shown to be 

inferior options (not on the dominant controls cost curve) and thus were eliminated from further impacts 

analysis. 

The incremental cost analysis indicates that from a cost effectiveness viewpoint, the SNCR with ASOFA 

alternative for MRYS Unit 2 incurs a significant annual (levelized) incremental cost compared to the 

ASOFA NOX control technique. The slope from zero (baseline) to ASOFA (Point A) was $709/ton; the 

incremental cost per ton (slope) from ASOFA (Point A) to SNCR with ASOFA (Point E ) was $2,263/ton 

for MRYS Unit 2. The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top 

hypothetically-applied low-dust SCR case (Point L2, Scenario A) was $8,792/ton (stand alone projects). 

The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetically-applied 

tail end SCR case (Point T2, Scenario A) was $10,472/ton (stand alone projects). The incremental cost per 

ton (slope) from SNCR with ASOFA (Point E) to the second hypothetically-applied low-dust SCR case 

(Point L1, Scenario B) was $13,812/ton (stand alone projects). The incremental cost per ton (slope) from 

SNCR with ASOFA (Point E) to the second hypothetically-applied tail end SCR case (Point T1, Scenario 

B) was $15,550/ton (stand alone projects). For shared projects, the incremental cost per ton (slope) from 

SNCR with ASOFA (Point E) to the top hypothetically-applied SCR cases were $8,331/ton (low-dust Point 

L2, Scenario A) and $10,007/ton (tail end Point T2, Scenario A). For shared projects, the incremental cost 

per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetically-applied SCR cases were 

$13,361/ton (low-dust, Point L1, Scenario B) and $15,096/ton (tail end Point T1, Scenario B). 

In the U.S. EPA’s NSR Manual, the EPA does not specify acceptable or unacceptable ranges for average 

(unit control costs) and incremental cost effectiveness values. EPA’s NSR Manual however, does 

specifically address the standard to be used when rejecting a candidate technology on the basis of adverse 

economic impact: 

“Consequently, where unusual factors exist that result in cost/economic impacts 

beyond the range normally incurred by other sources in that category, the technology 

can be eliminated provided the applicant has adequately identified the circumstances, 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-38 Burns & McDonnell 

including the cost or other analyses, that show what is significantly different about the 

proposed source.”34 

This supplemental report for the MRYS NOx BACT Analysis has clearly established the circumstances, 

including the economic impacts, which would make the hypothetical application of TESCR or LDSCR to 

MRYS Unit 2 significantly more expensive than SCR costs normally incurred by other coal-fired steam 

electric generating units. The following information further supports EPA’s own statements regarding the 

costs “normally incurred by other sources”. The EPA’s technical support document issued with the final 

Regional Haze Regulations and BART Guidelines estimated an average control cost for SCR applied to 

MRYS Unit 2 of $537 per ton35. The unadjusted unit capital cost versus capacity factor assumed by the 

EPA for SCR retrofits applied to cyclone boilers in the cost-effectiveness analysis used for establishing 

presumptive BART36 was $100/kW. The EPA’s cost-effectiveness analysis used for establishing 

presumptive BART stated that “applying SCR for coal-fired cyclone units is typically less than $1500 a ton, 

and that the average cost-effectiveness is $900 per ton” 37. The site-specific control costs estimated for 

hypothetical application of tail-end and low-dust SCR alternatives to MRYS Unit 2 are significantly higher 

than the EPA’s cost-effectiveness analysis for conventional SCR technologies included in the technical 

support document issued with the final Regional Haze Regulations and BART Guidelines discussed above.

Also, the use of incremental cost effectiveness is warranted per the final 2005 RHR/BART Guidelines, 

which state “the greater the number of possible control options that exist, the more weight should be given 

to the incremental costs vs. average costs”. Also in the final 2005 RHR/BART Guidelines, “the average 

cost for each [of two options, A and B]... may be deemed to be reasonable. However, the incremental 

cost...of the additional emissions reductions to be achieved by control B may be very great. In such an 

instance, it may be inappropriate to chose control B, based on its higher incremental costs, even though its 

average cost may be considered reasonable”.38 

 

34 Ibid Reference number 2, Section IV.D.2.c. 

35 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215. 

36 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 209. 

37 See Reference number 11, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136. 

38 Ibid Reference number 11, July 2005, FR Vol. 70 No. 128, page 39168. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions ________________________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-39 

TABLE 4-9SA – Estimated Emissions and Economic Impacts Summary for NOX Control Alternatives - MRY Station Unit 2 - St

Summary of Estimated Annual Emissions and Economics for NOx Control Alternatives Evaluated for Milton R. Young Station Unit 2 – Stand Alon

ECON

EMISSIONS(2)

Emission 

Rate 

Hourly 

Emission 

Annual 

Emission 

Emission 

Reduction

Alt. 

Label(1) NOx Control Alternative lb/mmBtu lbs/hr tons/yr tons/yr 

NOx 

Removal 

Efficiency(2) 

%

Installed 

Capital 

Cost(3) 

$1,000 

Annu

O & 

Cost

$1,00

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(7) 0.049 239 936 14,857 93.8(8) 340,733 31,5T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(7) 0.049 239 813 14,980 93.8(8) 340,733 55,34L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(7) 0.049 239 931 14,862 93.8(8) 270,785 29,04L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(7) 0.049 239 813 14,980 93.8(8) 270,785 52,42

E SNCR w/ ASOFA 0.330 1,612 6,421 9,372 58.0 17,128 8,10

D Gas Reburn w/ ASOFA 0.350 1,710 6,882 8,910 55.4 35,490 48,6

C Lignite Reburn w/ ASOFA 0.360 1,759 6,964 8,829 54.2 81,167 9,92B FLGR w/ ASOFA 0.432 2,110 8,490 7,303 45.0 21,817 21,95

A Advanced SOFA (ASOFA) 0.489 2,391 9,621 6,172 37.7 10,008 2,80

 Baseline 0.786 3,839 15,793 0 - 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Estimated NOX control level reductions relative to average annual unit emission baseline of 0.786 lb/mmBtu at 4,885 mmBtu/hr MCR heat input. Emissions are calculated from unit emission 

and annual hrs/yr operation compared to pre-control baseline based on annual operation at a gross unit electrical output of 440 MWg and assumes a 93.9% average annual availability. Valueoperating period during 2001-2005 with the highest rolling summation of NOx pounds. 

(3) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 477 MWg unit capacity rating. All cost figures in 2006 dollars. C

pressure natural gas supply pipeline installed capital cost of $14,988,000 for CGR and $7,494,000 for FLGR, and annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR. included in lignite reburn option are $36,013,000 for installed capital cost. 

(4) - Annual operating and maintenance cost for a particular technology or combination is compared to unit baseline operation at a gross unit electrical output of 440 MWg and assumes a 95.2% av

nominal unit gross electrical output capacity of 462 MWg. All cost figures in 2006 dollars. Costs for increased PM collection capacity included in lignite reburn option are $3,155,000/yr for 

(5) - Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Lev

x 1.24873 annualized O&M cost factor. 

(6) - Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost (1000$) divided by Annual Emission Reduction (tons). All cost figures in 2006 dollars. 

(7) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that these technologies are technically feasible to install on Unit 2 at Milton R. Young Stat

LTAC shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical infeasibility for installation and operation and maintenance of th

SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals in response to 

parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that specified number of hours of unit operation. 

(8) - The stated overall control percentage includes the anticipated long-term emission reduction of 90% design removal from a baseline of 0.49 lb/mmBtu resulting from an advanced separated ove

cyclone combustion. Without a separated overfire air system operation or any other technique employed, the assumed emission rate would be 0.079 lb/mmBtu, for an overall reduction of 90 

(9) - LTAC for reburn options include high-pressure natural gas supply pipeline annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR; LTAC for increased PM collection capa

$3,140,000 for annualized capital cost plus $3,940,000/yr for annualized O&M cost, for a total of $7,080,000/yr. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions ________________________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-40 

TABLE 4-9SF – Estimated Emissions and Economic Impacts Summary for NOX Control Alternatives - MRY Station Unit 2 – S

Summary of Estimated Annual Emissions and Economics for NOx Control Alternatives Evaluated for Milton R. Young Station Unit 2 – Shared Facil

ECON

EMISSIONS(2)

Emission 

Rate 

Hourly 

Emission 

Annual 

Emission 

Emission 

Reduction

Alt. 

Label(1) NOx Control Alternative lb/mmBtu lbs/hr tons/yr tons/yr 

NOx 

Removal 

Efficiency(2) 

%

Installed 

Capital 

Cost(3) 

$1,000 

Annu

O & 

Cost

$1,00

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(7) 0.049 239 936 14,857 93.8(8) 320,279 30,89T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(7) 0.049 239 813 14,980 93.8(8) 320,279 54,7L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(7) 0.049 239 931 14,862 93.8(8) 250,487 28,4L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(7) 0.049 239 813 14,980 93.8(8) 250,487 51,8

E SNCR w/ ASOFA 0.330 1,612 6,421 9,372 58.0 17,128 8,10

D Gas Reburn w/ ASOFA 0.350 1,710 6,882 8,910 55.4 35,490 48,6

C Lignite Reburn w/ ASOFA 0.360 1,759 6,964 8,829 54.2 81,167 9,92B FLGR w/ ASOFA 0.432 2,110 8,490 7,303 45.0 21,817 21,95

A Advanced SOFA (ASOFA) 0.489 2,391 9,621 6,172 37.7 10,008 2,80

 Baseline 0.786 3,839 15,793 0 - 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Estimated NOX control level reductions relative to average annual unit emission baseline of 0.786 lb/mmBtu at 4,885 mmBtu/hr MCR heat input. Emissions are calculated from unit emission 

and annual hrs/yr operation compared to pre-control baseline based on annual operation at a gross unit electrical output of 440 MWg and assumes a 93.9% average annual availability. Values foperating period during 2001-2005 with the highest rolling summation of NOx pounds. 

(3) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 477 MWg unit capacity rating. All cost figures in 2006 dollars. C

pressure natural gas supply pipeline installed capital cost of $14,988,000 for CGR and $7,494,000 for FLGR, and annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR. Coincluded in lignite reburn option are $36,013,000 for installed capital cost. 

(4) - Annual operating and maintenance cost for a particular technology or combination is compared to unit baseline operation at a gross unit electrical output of 440 MWg and assumes a 95.2% av

nominal unit gross electrical output capacity of 462 MWg. All cost figures in 2006 dollars. Costs for increased PM collection capacity included in lignite reburn option are $3,155,000/yr for an

(5) - Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Lev

x 1.24873 annualized O&M cost factor. 

(6) - Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost (1000$) divided by Annual Emission Reduction (tons). All cost figures in 2006 dollars. 

(7) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that these technologies are technically feasible to install on Unit 2 at Milton R. Young Sta

LTAC shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical infeasibility for installation and operation and maintenance of the S

SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals in response to com

parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that asspecified number of hours of unit operation. 

(8) - The stated overall control percentage includes the anticipated long-term emission reduction of 90% design removal from a baseline of 0.49 lb/mmBtu resulting from an advanced separated ove

cyclone combustion. Without a separated overfire air system operation or any other technique employed, the assumed emission rate would be 0.079 lb/mmBtu, for an overall reduction of 90 pe

(9) - LTAC for reburn options include high-pressure natural gas supply pipeline annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR; LTAC for increased PM collection capa

$3,140,000 for annualized capital cost plus $3,940,000/yr for annualized O&M cost, for a total of $7,080,000/yr. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-41 Burns & McDonnell 

The other elements of the fourth step of a BACT analysis following economic impacts are to evaluate the 

following impacts of feasible emission controls: 

(1) The energy impacts. 

(2) The environmental impacts. 

4.2.2 ENERGY IMPACTS OF HYPOTHETICALLY-APPLIED SCR NOX

CONTROL ALTERNATIVES FOR MRY STATION UNIT 2 

Operation of the NOX control technologies on the dominant controls cost curve for potential application at 

the Milton R. Young Station impose direct impacts on the consumption of energy required for the 

production of electric power at the facility. The details of estimated energy usage and costs for the 

previously-evaluated NOX control alternatives were described and summarized in Section 3.4.2 and 

Appendix C3 of the October 2006 NOx BACT Analysis Study report39. 

The hypothetical application of Tail End and Low-Dust SCR w/ ASOFA alternatives involve higher 

energy consumption compared with the existing operation of MRYS Unit 2. New induced draft booster 

fan electrical power demand is needed due to the estimated additional flue gas pressure drop resulting 

from hypothetical application of SCR reactor, ductwork, and gas-to-gas heat exchangers. The additional 

auxiliary electric power demands for the hypothetical application of TESCR and LDSCR equipment were 

calculated to be 14.9 MW and 12.4 MW, respectively, using estimated annual average electrical loads of 

the booster fan, urea-to-ammonia conversion fired heater combustion/dilution air fan, direct-fired flue gas 

reheat burner combustion air fan, and service and sootblowing air compressor equipment and related 

auxiliary equipment. 

Preliminary conceptual design details were developed for these alternatives. An estimated additional 10 

inches w.c. of flue gas pressure drop was assumed for each hypothetical application of low-dust SCR 

system, and an estimated additional 16 inches w.c. of flue gas pressure drop was assumed for the 

hypothetical application of tail end SCR system. Equipment and ductwork arrangements and expected 

severe fouling of the catalyst for the hypothetical application of SCR system ductwork, reactor, and gasgas reheater changes may cause significantly more restrictive flow paths. Thus the electrical power usage 

estimated here may be too low. 

 

39 Ibid Reference number 3, October 2006, pages 3-31 through 3-35, and Appendix pages C3-7 through C3-10. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-42 Burns & McDonnell 

The expected loss of electrical power generation from these reductions in net output was included as a 

cost, assuming $35 per megawatt-hour for replacement electrical power. Energy impacts of installing 

hypothetical applications of low-dust and tail end SCR alternatives for NOX control were included in the 

O&M cost section (4.2.1.2.1) of this supplemental analysis as Tables C.4-2 through C.4-4. 

Aqueous urea solution was assumed to be the preferred, readily available and transportable source of the 

amine reagent needed to supply ammonia to the SCR reactor catalyst for the hypothetically-applied lowdust and tail-end SCR alternatives. A urea-to-ammonia conversion system dedicated for each SCR 

reactor was also assumed. This conversion process will use a natural gas-fired burner that mixes the 

combustion products at high temperature with the injected aqueous urea solution to thermally decompose 

the urea, producing gaseous ammonia to supply to the reactors’ ammonia injection grids. Gaseous 

ammonia is the required amine reagent that the catalyst in the SCR reactors uses to convert nitrogen 

oxides to elemental nitrogen and water vapor. Ammonia (from urea conversion) is supplied and 

consumed continuously on demand while the SCR NOx reduction process is in operation. Natural gas is 

fired continuously during the urea-to-ammonia conversion system operation. 

Final reactor inlet flue gas reheat systems are required for the hypothetical applications of tail end and 

low-dust SCR with ASOFA alternatives. A natural gas-fired duct burner that injects high temperature 

combustion products directly into the flue gas discharged from each SCR gas/gas heat exchanger was 

assumed for raising the reactor inlet temperature to 600oF before ammonia injection and NOx reduction 

can occur in each SCR reactor. Natural gas is fired continuously for flue gas reheating during SCR 

system operation. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-43 Burns & McDonnell 

TABLE 4-10 – Energy Impacts for NOX Control Alternatives - MRY Station Unit 2

Alt. 

Label(1) 

NOx Control 

Alternative(2)

Estimated 

Annual 

Natural Gas 

Usage for 

Urea-toAmmonia 

Conversion,(3) 

(mmBtu/yr) 

Estimated 

Annual 

Natural 

Gas Usage 

for SCR 

Inlet 

Reheat,(4) 

(mmBtu/yr)

Estimated 

Annual 

Natural 

Gas Usage 

for Reburn 

Fuel,(5) 

(mmBtu/yr) 

Estimated 

Additional 

Annual 

Coal 

Burned for 

Urea 

Solution 

Dilution 

Water,(6) 

(mmBtu/yr) 

Estimated 

Total Annual 

Natural Gas 

Usage and ,

Additional 

Annual Coal 

Burned (7)

(mmBtu/yr) 

T2 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario A(5) 

49,463 754,563 0 0 804,026 

T1 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario B(5)

42,975 655,591 0 0 698,566 

L2 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario A(5)

49,203 710,710 0 0 759,913 

L1 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario B(5) 

42,975 620,747 0 0 663,722 

E SNCR w/ ASOFA 0 0 0 73,986 73,986 

D Gas Reburn w/ ASOFA 0 0 6,301,740 0 6,301,740 

C Lignite Reburn w/ 

ASOFA 0 0 0 0 0 

B FLGR w/ ASOFA 0 0 2,610,560 0 2,610,560 

A Advanced SOFA 

(ASOFA) 0 0 0 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. Alternatives are labeled the same 

as in Table 4-9. 

(2) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is 

technically feasible to install these technologies on Unit 2 at Milton R. Young Station. The annual NOx removal and 

LTAC shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for 

technical infeasibility for installation of the SCR equipment on this boiler are solvable. SCR technology is considered 

technically infeasible by Minnkota for application at MRYS per the October 2006 NOX BACT Analysis Study report 

and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for 

the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for 

details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of 

unit operation. 

(3) – Estimated annual natural gas usage for urea-to-ammonia conversion based on adjustments to preliminary budgetary 

equipment vendor proposals and process calculations. TESCR and LDSCR rate = 3.15 mmBtu/hr for each reactor x 2. 

(4) – Estimated annual natural gas usage for flue gas final reheat based on adjustments to preliminary vendor process 

calculations. TESCR rate = 48.11 mmBtu/hr for each reactor x 2; LDSCR rate = 45.55 mmBtu/hr for each reactor x 2. 

(5) – Natural gas burned for reburn alternatives is assumed to replace coal, no boiler heat rate penalty assumed. Lignite 

reburn is assumed to burn the same total amount of coal in the boiler as without coal reburn. 

(6) - Additional coal burned is due to the urea dilution water injected directly into the boiler’s upper furnace, decreasing 

heat available for steam production and electricity generation, at a net loss of 900 Btu/lb of water for evaporation. See 

Appendix C3 in the 2006 NOX BACT Analysis Study report for additional details. 

(7) - Annual O&M costs include these values multiplied by the number of hours per year of operation and assume $7.98 

per mmBtu for natural gas and $0.71 per mmBtu for coal. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-44 Burns & McDonnell 

4.2.3 ENVIRONMENTAL IMPACTS OF HYPOTHETICALLY-APPLIED SCR NOX

CONTROL ALTERNATIVES FOR MRY STATION UNIT 2 

Operation of the NOX control technologies on the dominant controls cost curve for potential application at 

the Milton R. Young Station impose direct and indirect impacts on the environment. The most 

pronounced direct environmental impact expected from operation of any of the NOX control options 

considered is the reduction of ozone and improvement in atmospheric visibility (i.e. reduced visibility 

impairment) downwind of the facility. Environmental impacts of previously-evaluated NOX control 

alternatives were described and summarized in Section 3.4.3 of the October 2006 NOx BACT Analysis 

Study report.40

There would be a favorable environmental impact from potential reduction of annual unit operating time 

by approximately two percent due to cyclone slag issues associated with air-staged cyclones/ASOFA 

system operation and by between five percent and 17 percent due to catalyst management and SCR 

equipment maintenance-related issues for the various low-dust and tail end SCR alternatives. The impact 

of fewer annual hours of operation will be to decrease the annual amount (tons) of nitrogen oxides 

emitted, by between approximately 0.2 percent and one percent overall compared to baseline operation. 

However, generation of replacement electrical power at other powerplants will negate most of these 

emission reductions. 

Operation of the hypothetical application of SCR systems is not expected to significantly impact 

emissions of carbon monoxide (CO) or volatile organic compounds (VOCs). Emissions from the urea-toammonia conversion and flue gas reheat natural gas-fired burners are additive and included in the flue gas 

entering the SCR reactor in each hypothetical case. 

Operation of any SCR system will normally cause a small amount of unreacted ammonia to be emitted. 

The amount of ammonia slip produced by an SCR depends on the reagent utilization and the location of 

the injection points. Higher SCR NOX reduction performance involves greater amounts of reagent usage 

and ammonia slip. This is typically controlled to less than 2 ppmvd, especially when the possible 

formation of sulfates such as ammonium sulfate [(NH4)2SO4] and ammonium bisulfate [NH4HSO4] will 

be more problematic at higher slip levels. Sulfur trioxide (SO3) formed during combustion in the boiler 

can combine with ammonia during passage through the catalyst to form the sulfates downstream. 

 

40 Ibid Reference number 3, October 2006, pages 3-35 through 3-37. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-45 Burns & McDonnell 

Unreacted ammonia (“slip”) from SCR operation will not be collected downstream of the hypotheticallyapplied tail end SCR reactors. The wet flue gas desulfurization absorbers downstream of the 

hypothetically-applied low-dust SCR reactors may reduce ammonia slip. Any remaining ammonia slip that 

is not collected or condensed in the air pollution control system will be emitted from the stack as an aerosol 

or condensable particulate. This has the potential to increase atmospheric visibility impairment downwind 

of the facility compared with a pristine condition. 

Sulfur dioxide (SO2) formed during combustion in the boiler can combine with oxygen during passage 

through the hypothetical tail end and low-dust SCR catalyst to form additional sulfur trioxide (SO3) 

emissions. SO3 can subsequently combine with water (H2O) to form sulfuric acid (H2SO4), usually in the 

form of a mist. Wet flue gas scrubbing to remove SO2 is not highly effective in removing SO3 created in 

an upstream low-dust SCR, so higher sulfate emissions will result unless a precipitating reaction with 

ammonia or condensation in the downstream gas-gas reheater or ductwork occurs. SO3 and H2SO4 can 

have significant negative far-field impairment impacts on atmospheric visibility if they are above 

threshold concentrations and not controlled. Tail end SCRs can also cause a small amount of SO3 to be 

created as the remaining SO2 not removed by the wet lime flue gas desulfurization systems will pass 

through the catalyst and some will be oxidized. It is not known whether the high concentration of 

alkalinity in the form of sodium aerosol particles at MRYS will effectively eliminate the remaining SO3

downstream of the hypothetically-applied low-dust and tail end SCR systems. 

Catalyst from the hypothetical application of SCR reactors will require regular replacement, requiring 

disposal of the spent catalyst materials or chemical cleaning to remove deposits to allow reuse or 

regeneration. Hauling spent catalyst to a catalyst rejuvenation facility or authorized landfill may be 

required, producing additional liquid and solid wastes and vehicle exhaust emissions. 

Because railroad service is not available to MRYS, shipments of amine reagent (concentrated urea 

solution) for consumption by the hypothetical application of SCR reactors will require additional truck 

traffic between the supply facility and plant, producing more emissions from vehicle exhaust. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-46 Burns & McDonnell 

4.2.4 SUMMARY OF ECONOMIC, ENERGY AND ENVIRONMENTAL IMPACTS 

OF HYPOTHETICALLY-APPLIED SCR NOX CONTROL ALTERNATIVES 

FOR MRY STATION UNIT 2 

The economic, energy, and environmental impacts of each NOX control technology on the dominant 

controls cost curve for potential application at the Milton R. Young Station evaluated for this study are 

summarized in this Section. Table 3-18 summarized the various impacts discussed in Sections 3.4.1 

through 3.4.3 of the October 2006 NOX BACT Analysis Study report 41. The economic analysis examined 

the estimated capital cost of four hypothetically-applied SCR cases and previously-analyzed feasible NOX

control alternatives and any other powerplant upgrade costs necessary to implement the alternatives. In 

addition, the economic analysis examined the operating and maintenance costs associated with each NOX

control technology evaluated. These costs were then combined into the levelized total annual cost for a 

comparative assessment of the total implementation cost of each alternative. Finally, as part of the topdown analysis, a dominant controls cost curve was plotted and the unit control cost for each remaining 

alternative was evaluated. Four hypothetically-applied SCR cases and two previously-analyzed feasible 

alternatives were on the dominant controls cost curve and the latter were identified as the more costeffective alternatives. The four hypothetically-applied SCR cases and two previously-analyzed feasible 

BACT NOX control alternatives were evaluated for incremental cost, energy, and environmental impacts 

applicable to Milton R. Young Station Unit 2. The results are summarized in Tables 4-11SA and 4-11SF. 

The unit control cost for the hypothetically-applied SCR cases: 

• Tail End SCR w/ ASOFA stand alone SCR projects cases - Scenario A was $4,648/ton and 

Scenario B was $ 6,597/ton. 

• Low-Dust SCR w/ ASOFA stand alone SCR projects cases - Scenario A was $4,029/ton and 

Scenario B was $5,946/ton. 

• Tail End SCR w/ ASOFA shared facilities SCR projects cases - Scenario A was $4,477/ton and 

Scenario B was $ 6,427/ton. 

• Low-Dust SCR w/ ASOFA shared facilities SCR projects cases - Scenario A was $3,859/ton and 

Scenario B was $5,777/ton. 

These UCCs are approximately 370 to 525 percent of the UCC for SNCR w/ ASOFA ($1,240/ton), and 

approximately 645 to 920 percent of ASOFA’s UCC ($709/ton). 

 

41 Ibid Reference number 3, October 2006, pages 3-20 through 3-38. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-47 Burns & McDonnell 

The incremental cost analysis indicates that from a cost effectiveness viewpoint, the SNCR with ASOFA 

alternative for MRYS Unit 2 incurs a significant annual (levelized) incremental cost compared to the 

ASOFA NOX control technique. The slope from zero (baseline) to ASOFA (Point A) was $709/ton; the 

incremental cost per ton (slope) from ASOFA (Point A) to SNCR with ASOFA (Point E ) was $2,263/ton 

for MRYS Unit 2. The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the various 

hypothetically-applied SCR cases: 

• Tail End SCR w/ ASOFA stand alone SCR projects cases - Scenario A was $10,472/ton and 

Scenario B was $15,550/ton. 

• Low-Dust SCR w/ ASOFA stand alone SCR projects cases - Scenario A was $8,792/ton and 

Scenario B was $13,812/ton. 

• Tail End SCR w/ ASOFA shared facilities SCR projects cases - Scenario A was $10,007/ton and 

Scenario B was $15,096/ton. 

• Low-Dust SCR w/ ASOFA shared facilities SCR projects cases - Scenario A was $8,331/ton and 

Scenario B was $13,361/ton. 

The incremental unit control cost per ton (slope) from SNCR with ASOFA to the hypothetically-applied 

SCR with ASOFA cases are approximately 360 to 680 percent of the incremental UCC per ton (slope) 

between ASOFA and SNCR with ASOFA ($2,263/ton). The incremental UCCs from SNCR with 

ASOFA to the hypothetically-applied SCR with ASOFA cases is between 11 and 22 times the 

incremental UCC for ASOFA from the pre-control baseline ($709/ton). 

In the U.S. EPA’s NSR Manual, the EPA does not specify acceptable or unacceptable ranges for average 

(unit control costs) and incremental cost effectiveness values. EPA’s NSR Manual however, does 

specifically address the standard to be used when rejecting a candidate technology on the basis of adverse 

economic impact: 

“Consequently, where unusual factors exist that result in cost/economic impacts 

beyond the range normally incurred by other sources in that category, the technology 

can be eliminated provided the applicant has adequately identified the circumstances, 

including the cost or other analyses, that show what is significantly different about 

the proposed source.”42 

This supplemental report for the MRYS NOx BACT Analysis has clearly established the circumstances, 

including the economic impacts, which would make the hypothetical application of TESCR or LDSCR to 

 

42 Ibid Reference number 2, Section IV.D.2.c. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-48 Burns & McDonnell 

MRYS Unit 2 significantly more expensive than SCR costs normally incurred by other coal-fired steam 

electric generating units. The following information further supports EPA’s own statements regarding the 

costs “normally incurred by other sources”. 

The EPA’s technical support document issued with the final Regional Haze Regulations and BART 

Guidelines was considered relevant for control cost-effectiveness comparison. The EPA’s costeffectiveness analysis used for establishing presumptive BART stated that “applying SCR for coal-fired 

cyclone units is typically less than $1500 a ton, and that the average cost-effectiveness is $900 per ton” 43. 

EPA’s Technical Support Document estimated an average control cost for SCR applied to MRYS Unit 2 

of $537 per ton44. The unadjusted unit capital cost factor assumed by the EPA for SCR retrofits applied 

to cyclone boilers in the cost-effectiveness analysis used for establishing presumptive BART45 was 

$100/kW. The estimated “stand alone” and “shared facilities” installed capital costs for the 

hypothetically-applied low-dust SCR w/ ASOFA cases at MRYS Unit 2 are $525 to $568/kW, which are 

more than 500 percent of the EPA’s number. The estimated “stand alone” and “shared facilities” installed 

capital costs for the hypothetically-applied tail end SCR w/ ASOFA cases are $671 to 714/kW, which are 

approximately 700 percent of the EPA’s number. Also stated in the final RHR/BART Guidelines, “the 

average cost for each [of two options, A and B]... may be deemed to be reasonable. However, the 

incremental cost...of the additional emissions reductions to be achieved by control B may be very great. 

In such an instance, it may be inappropriate to chose control B, based on its higher incremental costs, 

even though its average cost may be considered reasonable”.46

4.2.5 CONCLUSIONS 

The site-specific control costs estimated for application of hypothetically-applied tail-end and low-dust 

SCR alternatives to MRYS Unit 2 are significantly higher than the EPA’s cost-effectiveness analysis for 

conventional SCR technologies included in the technical support document issued with the final Regional 

Haze Regulations and BART Guidelines discussed above. 

The expected severity of catalyst blinding and pluggage from particulate matter and flue gases emitted 

from cyclone-fired boilers burning North Dakota lignite precludes the technical feasibility for successful 

application of such SCR technologies on the electric generating units (EGUs) at the Milton R. Young 

 

43 See Reference number 9, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136. 

44 Ibid Reference number 3, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215. 

45 Ibid Reference number 3, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 209. 

46 Ibid Reference number 9, July 2005, FR Vol. 70 No. 128, page 39168. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-49 Burns & McDonnell 

Station. Not withstanding the technical discussion of SCR technology infeasibility and technical details 

previously provided in Appendix A1 and Appendix B47 of the initial NOX BACT Analysis Study report 

and subsequent submittals in response to comments by the NDDH, EPA, DOJ, and other parties, this 

supplemental analysis concludes that the estimated capital and O&M costs for four variations of 

hypothetically-applied tail-end and low-dust SCR technology alternatives are significantly beyond the 

cost analysis values included in EPA’s technical support document issued with the final Regional Haze 

Regulations and BART Guidelines48,49. Average control cost effectiveness for each hypotheticallyapplied SCR control technology case is a minimum of approximately three times the unit control costs of 

the previously-analyzed highest-performing feasible control alternative recommended as BACT for 

MRYS Unit 2 (SNCR with ASOFA). Incremental control cost effectiveness for each hypotheticallyapplied SCR control technology case is a minimum of approximately three times the incremental control 

costs of the previously-analyzed highest-performing feasible control alternative recommended as BACT 

for MRYS Unit 2 (SNCR with ASOFA). 

There is an expected decrease in net capacity and availability to generate electrical power due to the 

hypothetically-applied SCR alternatives. A 5 to 17 percent decrease in the number of hours of annual 

operation, and approximately 3% drop in annual plant capacity (net electrical output or MWn) during 

operation of the MRYS Unit 2 system are expected if the hypothetically-applied low-dust or tail end SCR 

alternatives were installed. There are also substantial expected negative energy impacts for each 

hypothetically-applied SCR control technology case. Additional auxiliary electrical power demands of 

approximately 12 to 15 MW will result. This estimate of electrical power usage may be too low. This 

higher electrical power consumption and lower electrical power generation by MRYS Unit 2 will require 

additional replacement electrical power to be generated elsewhere. 

Natural gas is fired continuously during the urea-to-ammonia conversion system operation for each of the 

hypothetically-applied Tail End and Low-Dust SCR with ASOFA alternatives. 

Final reactor inlet flue gas reheat systems are required for the hypothetically-applied Tail End and LowDust SCR with ASOFA alternatives. Natural gas is fired continuously for flue gas reheating during SCR 

 

47 Ibid Reference number 2, October 2006. 

48 See Reference number 9, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136. 

49 Ibid Reference number 3, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions 

_____________________________________________________________________________________________ 

Square Butte Electric Cooperative 4-50 Burns & McDonnell 

system operation for raising the reactor inlet temperature to 600oF before ammonia injection and NOx 

reduction can occur in each SCR reactor. 

The site-specific control costs estimated for application of hypothetically-applied tail-end and low-dust 

SCR alternatives to MRYS Unit 2 are significantly higher than the EPA’s cost-effectiveness analysis for 

conventional SCR technologies included in the technical support document issued with the final Regional 

Haze Regulations and BART Guidelines50. Low-dust and tail end SCR technologies should be excluded 

from consideration for NOX control at MRYS due to unacceptably high average and incremental cost per 

ton of pollutant removal based on the supplemental analysis provided herein. Therefore the conclusions 

regarding NOx BACT as expressed in the original October 2006 BACT Analysis for MRYS Unit 2 are 

confirmed. 

The economic, energy, and environmental impacts of each NOX control technology on the dominant 

controls cost curve for potential application to Unit 2 at the Milton R. Young Station evaluated for this 

study are summarized in Tables 4-11SA and 4-11SF. 

 

50 See Reference number 4, July, 2005. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions ________________________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-51 

TABLE 4-11SA – Summary of Supplemental BACT Analysis Impact Results for Dominant NOX Control Alternatives - MRY Sta

ECONOMIC IMPACTS 

EMISSIONS(2)

Alt. 

Label(1) NOx Control Alternative

Emission 

Rate 

lb/mmBtu 

Hourly 

Emission 

lbs/hr 

Annual 

Emission 

tons/yr 

Emission 

Reduction(2) 

tons/yr 

Installed 

Capital 

Cost(3) 

$1,000 

Annual 

O & M 

Cost(4) 

$1,000

Levelized 

Total 

Annualized 

Cost(5) 

$1,000 

Average 

Control 

Cost(6) 

$/ton 

Incr

C

C

$

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(10) 0.049 239 936 14,857 340,733 31,512 69,056 4,648 1T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(10) 0.049 239 813 14,980 340,733 55,345 98,818 6,597 1L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(10) 0.049 239 931 14,862 270,785 29,048 59,881 4,029 8L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(10) 0.049 239 913 14,980 270,785 52,424 89,072 5,946 1

E SNCR w/ ASOFA 0.330 1,612 6,421 9,372 17,128 8,108 11,618 1,240 2

A Advanced SOFA (ASOFA) 0.489 2,391 9,621 6,172 10,008 2,805 4,376 709 

 Baseline 0.786 3,839 15,793 0 0 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Estimated NOX control level reductions relative to average annual emission baseline of 0.786 lb/mmBtu at 4,885 mmBtu/hr heat input. Emissions are calculated from unit emission rates, cont

baseline based on annual operation at a gross unit electrical output of 440 MWg and assumes a 93.9% average annual availability. 

(3) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 477 MWg unit capacity rating. All cost figures in 2006 dollars. (4) - Annual operating and maintenance cost for a particular technology or combination is compared to unit baseline operation at a gross unit electrical output of 440 MWg and assumes a 95.2% av

from 2001-2005. All cost figures in 2006 dollars. 

(5) - Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Lev

(6) - Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost (1000$/yr) divided by Annual Emission Reduction (tons/yr). All cost figures in 2006 dollars. 

(7) - Incremental Control Cost Effectiveness ($/ton) is the difference in LTAC between the next most stringent alternative divided by the emissions reduction. All cost figures in 2006 dollars. 

(8) - Energy impacts are incremental auxiliary electrical power demand (kW) and annual power usage plus generation lost due to negative unit availability (fewer hours per year of operation) result

(9) - Environmental impacts summarize expected non-air effects and potential toxic air emissions resulting from control alternative compared to the pre-control baseline. Flyash unburned carbon c

increase an insignificant amount with air-staging cyclones. Excess unreacted ammonia (slip) expected from SNCR technology and the hypothetically-applied SCR technology cases. 

(10) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 2 at Milton R. Young Stat

applied SCR system is based on assumptions that known or expected reasons for technical infeasibility for installation and operation and maintenance of the SCR equipment on this boiler are 

application at MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this informa

purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 2 NOx Emissions ________________________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-52 

TABLE 4-11SF – Summary of Supplemental BACT Analysis Impact Results for Dominant NOX Control Alternatives - MRY Sta

ECONOMIC IMPACTS 

EMISSIONS(2)

Alt. 

Label(1) NOx Control Alternative

Emission 

Rate 

lb/mmBtu 

Hourly 

Emission 

lbs/hr 

Annual 

Emission 

tons/yr 

Emission 

Reduction(2) 

tons/yr 

Installed 

Capital 

Cost(3) 

$1,000 

Annual 

O & M 

Cost(4) 

$1,000

Levelized 

Total 

Annualized 

Cost(5) 

$1,000 

Average 

Control 

Cost(6) 

$/ton 

Incr

C

C

$

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(10) 0.049 239 936 14,857 320,279 30,898 66,506 4,477 1T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(10) 0.049 239 813 14,980 320,279 54,731 96,268 6,427 1L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(10) 0.049 239 931 14,862 250,487 28,439 57,351 3,859 8L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(10) 0.049 239 813 14,980 250,487 51,815 86,542 5,777 1

E SNCR w/ ASOFA 0.330 1,612 6,421 9,372 17,128 8,108 11,618 1,240 2

A Advanced SOFA (ASOFA) 0.489 2,391 9,621 6,172 10,008 2,805 4,376 709 

 Baseline 0.786 3,839 15,793 0 0 0 0 

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Estimated NOX control level reductions relative to average annual emission baseline of 0.786 lb/mmBtu at 4,885 mmBtu/hr heat input. Emissions are calculated from unit emission rates, control 

baseline based on annual operation at a gross unit electrical output of 440 MWg and assumes a 93.9% average annual availability. 

(3) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 477 MWg unit capacity rating. All cost figures in 2006 dollars. (4) - Annual operating and maintenance cost for a particular technology or combination is compared to unit baseline operation at a gross unit electrical output of 440 MWg and assumes a 95.2% avera

2001-2005. All cost figures in 2006 dollars. 

(5) - Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Level

(6) - Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost (1000$/yr) divided by Annual Emission Reduction (tons/yr). All cost figures in 2006 dollars. 

(7) - Incremental Control Cost Effectiveness ($/ton) is the difference in LTAC between the next most stringent alternative divided by the emissions reduction. All cost figures in 2006 dollars. 

(8) - Energy impacts are incremental auxiliary electrical power demand (kW) and annual power usage plus generation lost due to negative unit availability (fewer hours per year of operation) resulting 

(9) - Environmental impacts summarize expected non-air effects and potential toxic air emissions resulting from control alternative compared to the pre-control baseline. Flyash unburned carbon con

increase an insignificant amount with air-staging cyclones. Excess unreacted ammonia (slip) expected from SNCR technology and the hypothetically-applied SCR technology cases. 

(10) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 2 at Milton R. Young Station

SCR system is based on assumptions that known or expected reasons for technical infeasibility for installation and operation and maintenance of the SCR equipment on this boiler are solvable. SC

MRYS per the October 2006 NOX BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypoth

Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation. 
Supplemental BACT Analysis 

for MRY Station Unit 2 NOx Emissions 

Square Butte Electric Cooperative 4-53 Burns & McDonnell 

1. North Dakota Department of Health, Environmental Health Section, Division of Air Quality letter 

by Terry L. O’Clair, P.E. to John Graves, Minnkota Power Cooperative, Re: Milton R. Young 

Station BACT Determination, dated July 15, 2009, and Re: Request for Time Extension, dated 

August 7, 2009. 

2. EPA New Source Review Workshop Manual, Prevention of Significant Deterioration and 

Nonattainment Area Permitting, Draft October 1990 (The “NSR Manual”). 

3. “BACT Analysis Study for Milton R. Young Station Unit 1 Minnkota Power Cooperative, Inc.” and 

a separate “BACT Analysis Study for Milton R. Young Station Unit 2 Square Butte Electric 

Cooperative”, October 2006, submitted to EPA Region 8 and EPA Office of Regulatory 

Enforcement, and included with the “BART DETERMINATION STUDY for Milton R. Young 

Station Unit 1 and 2 Minnkota Power Cooperative, Inc.” Final Report, October 2006 submitted by 

Minnkota to North Dakota Department of Health. 

4. Technical Support Document Methodology For Developing BART NOx Presumptive Limits, 

Environmental Protection Agency, Clean Air Markets Division, June 15, 2005, OAR-2002-0076-

0445, with Attachments, including Excel Spreadsheet OAR-2002-0076-0446 (1199 pages). 

5. Comment & Response to EPA Region 8’s October 4, 2007 Comment on NDDH BACT 

Determination at Milton R. Young Station, submitted by Minnkota to NDDH, November 9, 2007. 

6. EPA Report “Multipollutant Emission Control Technology Options for Coal-fired Power Plants”, 

EPA-600/R-05/034, dated March, 2005, posted at their website: 

http://www.epa.gov/airmarkets/articles/multireport2005.pdf. 

7. “Assessment of Control Technology Options for BART-Eligible Sources, Steam Electric Boilers, 

Industrial Boilers, Cement Plants and Paper and Pulp Facilities”, dated March 2005, prepared by 

Northeast States for Coordinated Air Use Management (NESCAUM) in partnership with the MidAtlantic/Northeast Visibility Union, posted at the website: 

http://bronze.nescaum.org/committees/haze/BART_Control_Assessment.pdf. 

8. “Analysis of Combustion Controls for Reducing NOX Emissions From Coal-fired EGU’s in the 

WRAP Region, Draft Report”, prepared for the Western Regional Air Partnership by Eastern 

Research Group, Inc., ERG Contract Number 30204-101, dated April 26, 2005, available at: 

http://www.wrapair.org/forums/ssjf/documents/eictts/NOxEGU/050426Coalfired%20EGUs_in_WRAP_Region-draft.pdf

9. EPA Office of Air Quality Planning and Standards (OAQPS) publication EPA/452/B-02-001, 

Section 4.2, NOx Controls – NOx Post-Combustion, Chapter 1 - Selective Non-Catalytic 

Reduction, dated October 2000, posted at their website: http://www.epa.gov/ttn/catc/dir1/cs4-2 

ch1.pdf

10. EPA Office of Air Quality Planning and Standards (OAQPS) publication EPA/452/B-02-001, 

Section 4.2, NOx Controls – NOx Post-Combustion, Chapter 2 - Selective Catalytic Reduction, 

dated October 2000, posted at their website: http://www.epa.gov/ttn/catc/dir1/cs4-2 ch2.pdf

11. Federal Register /Vol. 70, No. 128/ Wednesday, July 6, 2005 / Rules and Regulations, Part III 

Environmental Protection Agency 40 CFR Part 51, Regional Haze Regulations and Guidelines for 

Best Available Retrofit Technology (BART) Determinations; Final Rule.