NOx BEST AVAILABLE 

CONTROL TECHNOLOGY 

ANALYSIS STUDY 

 - SUPPLEMENTAL REPORT 

for 

Milton R. Young Station Unit 1 

Minnkota Power Cooperative, Inc. 

November 2009 

Revised February 2010

(refer to page TOC-3 for Index of Revisions)

31777 
NOx Best Available 

Control Technology 

Analysis Study 

SUPPLEMENTAL REPORT 

for 

Milton R. Young Station Unit 1 

prepared for 

Minnkota Power Cooperative, Inc. 

 

November 2009 

Revised February 2010

(refer to page TOC-3 for Index of Revisions)

Project No. 31777 

prepared by 

Burns & McDonnell Engineering Company, Inc. 

Kansas City, Missouri 

COPYRIGHT 2010 © BURNS & McDONNELL ENGINEERING COMPANY, INC. 

Supplemental BACT Control and Cost-Effectiveness Table of Contents 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. TOC-1 Burns & McDonnell 

TABLE OF CONTENTS 

4.0 SUPPLEMENTAL NOx BACT ANALYSIS CONTROLS & COSTS – 

MRY STATION UNIT 1................................................................................. 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 1.....................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 SCR NOx CONTROL 

ALTERNATIVES FOR MRY STATION UNIT 1....................................................4-41 

4.2.3 ENVIRONMENTAL IMPACTS OF HYPOTHETICALLY-APPLIED 

SCR NOx CONTROL ALTERNATIVES FOR MRY STATION UNIT 1.......................4-44 

4.2.4 SUMMARY OF ECONOMIC, ENERGY, AND ENVIRONMENTAL IMPACTS OF 

HYPOTHETICAL-APPLIED SCR NOx CONTROL ALTERNATIVES 

FOR MRY STATION UNIT 1..............................................................................4-46 

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

REFERENCES.......................................................................................................4-53 

Revisions February 2010

Strikethrough indicates text that has been deleted.

Underline indicates text that has been inserted or revised.

(refer to page TOC-3 for Index of Revisions)
Supplemental BACT Control and Cost-Effectiveness Table of Contents 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

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Minnkota Power Cooperative, Inc. TOC-2 Burns & McDonnell 

LIST OF TABLES

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

Performance 

Table 4-2 – Expected Annual NOX Control Performance for MRY Station Unit 1 Alternatives 

Table 4-3SA – Unit Capital Cost Factors of NOX Control Alternatives for MRY Station Unit 1 – 

Stand Alone SCR Projects 

Table 4-3SF – Unit Capital Cost Factors of NOX Control Alternatives for MRY Station Unit 1 – 

Shared Facilities SCR Projects 

Table 4-4SA – Estimated Capital Costs for NOX Control Alternatives - MRY Station Unit 1 – 

Stand Alone SCR Projects 

Table 4-4SF – Estimated Capital Costs for NOX Control Alternatives - MRY Station Unit 1 – 

Shared Facilities SCR Projects 

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

MRY Station Unit 1 – Stand Alone SCR Projects

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

MRY Station Unit 1 – Shared Facilities SCR Projects 

Table 4-6SA – Estimated O&M Costs for NOX Control Alternatives – MRY Station Unit 1 – 

Stand Alone SCR Projects

Table 4-6SF – Estimated O&M Costs for NOX Control Alternatives – MRY Station Unit 1 – 

Shared Facilities SCR Projects

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

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

Table C.4-3 – Expected Auxiliary Electrical Power Demand Changes for MRYS Unit 1 NOX Controls 

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

MRYS Unit 1 NOX Controls 

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

Alternatives– MRY Station Unit 1 – Stand Alone SCR Projects 

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

Alternatives– MRY Station Unit 1 – Shared Facilities SCR Projects 

Table 4-8SA – Dominant Controls Cost Curve Points for NOX Control Alternatives – MRY Station Unit 1 

– Stand Alone SCR Projects 

Table 4-8SF – Dominant Controls Cost Curve Points for NOX Control Alternatives – MRY Station Unit 1 

– Shared Facilities SCR Projects 

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

MRY Station Unit 1 – Stand Alone SCR Projects 

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

MRY Station Unit 1 –Shared Facilities SCR Projects 

Table 4-10 – Energy Impacts for NOX Control Alternatives – MRY Station Unit 1 
Supplemental BACT Control and Cost-Effectiveness Table of Contents 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

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Minnkota Power Cooperative, Inc. TOC-3 Burns & McDonnell 

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

Alternatives – MRY Station Unit 1 – Stand Alone SCR Projects 

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

Alternatives – MRY Station Unit 1 – Shared Facilities SCR Projects 

LIST OF FIGURES 

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

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

Figure 4-2SA – MRY Station Unit 1 NOX Control Alternatives BACT Dominant Controls Cost Curve – 

Stand Alone SCR Projects 

Figure 4-2SF – MRY Station Unit 1 NOX Control Alternatives BACT Dominant Controls Cost Curve – 

Shared Facilities SCR Projects 

INDEX TO REVISIONS

The following page numbers in the February 2010 version include revisions:

Page 4-20

Page 4-21

Page 4-26

Page 4-29

Page 4-30

Page 4-31

Page 4-32

Page 4-33

Page 4-34

Page 4-35

Page 4-36

Page 4-37

Page 4-39

Page 4-40

Page 4-43

Page 4-46

Page 4-47

Page 4-51

Page 4-52

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

Analysis for MRY Station Unit 1 NOx Emissions 

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Minnkota Power Cooperative, Inc. 4-1 Burns & McDonnell 

4.0 SUPPLEMENTAL NOx BACT ANALYSIS CONTROLS & COSTS – MRY 

STATION UNIT 1 

This supplement to the NOX BACT analysis for Milton R. Young Station (MRYS) Unit 1 has been 

prepared in response to the 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 1 includes ranking by effectiveness 

and providing 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 initial 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 1. 

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 1. Site-specific needs and challenges identified for applying tail 

end and low-dust SCR technologies to Milton R. Young Station Unit 1 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 applications 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 hypothetical application of tail-end and low-dust SCR 

alternatives to MRYS Unit 1 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-3 Burns & McDonnell 

Minnkota that it is technically feasible to install these technologies on Unit 1 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 previously-analyzed feasible 

control alternatives. 

For the techniques and technologies considered for determining MRYS Unit 1 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 1 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, is being implemented for operation starting prior to December 31, 

2009. 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 2, 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 1 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 1’s highest 12-month NOX mass emissions averaged 0.849 lb/mmBtu at a 

corresponding average unit heat input rate of 2,744 mmBtu/hr and unit gross electrical output of 

244.5 MWg. 

• During this lookback time period, Unit 1 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 

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

level of expected NOX reduction from ASOFA operation is approximately forty percent below the precontrol baseline emissions rate of 0.849 lb/mmBtu. 

 

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

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-5 Burns & McDonnell 

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

Unit 1 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) 0.053 93.8(4) 

T1 Hypothetical Tail-End SCR w/ ASOFA – Scenario B(3) 0.053 93.8(4) 

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(3) 0.053 93.8(4)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(3) 0.053 93.8(4)

E SNCR (using urea) w/ ASOFA 0.355 58.1 

D Gas Reburn with ASOFA 0.374 56.0 

C Lignite Reburn w/ ASOFA 0.385 54.6 

B Fuel Lean Gas Reburn with ASOFA 0.460 45.9 

A Advanced Separated Overfire Air (ASOFA) 0.513 39.5 

- Baseline 0.849 - 

(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 0.849 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 1 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 0.51 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 0.085 lb/mmBtu, for an overall reduction of 90 percent from a 

baseline of 0.849 lb/mmBtu. 

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

achieve a NOX emission level of 0.053 lb/mmBtu, which is approximately 90% reduction from a 0.51 

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 1’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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 hypotheticallyapplied SCR 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 1 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 1 NOx Emissions _________________________________________________________________________________________________________________________________ Minnkota Power Cooperative, Inc. 4-7 Burns & McDonnell 

TABLE 4-2 – Expected Annual NOX Control Performance for MRY Station Unit 1 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) 0.053 145 589 9,345 93.8(7)T1 Hypothetical Tail End SCR w/ ASOFA– Scenario B(6) 0.053 145 536 9,398 93.8(7)L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(6) 0.053 145 586 9,348 93.8(7)L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(6) 0.053 145 533 9,401 93.8(7)

E SNCR (using urea) w/ ASOFA 0.355 975 4,025 5,909 58.1 

D Gas Reburn w/ ASOFA 0.374 1,025 4,275 5,659 56.0 

C Lignite Reburn w/ ASOFA 0.385 1,058 4,343 5,591 54.6 B Fuel Lean Gas Reburn w/ ASOFA 0.460 1,261 5,260 4,674 45.9 

A Advanced Separated Overfire Air (ASOFA) 0.513 1,409 5,874 4,060 39.5 

- Baseline 0.849 2,330 9,934 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 2,744 mmBtu/hr heat input. (3) - Estimated annual emission tons assume an annual unit availability factor specific to each alternative; 97.3% was assumed for the baseline case. 

See Appendix C3 of the October 2006 NOX BACT Analysis Study report. Hypothetical application of tail end SCR case T2 assumes an annual unit availability factor of 92.8% (approx. 8,127 operating hours per year) and case T1 assumes an annual unit availability factor of 84.5% (approx. 7,402 operating hours per year). Hypothetically-applied low-dust SCR case L2 assumes an annual unit availability factor of 92.3% (approx. 8,084 operating hours per year) and case L1 assumes an annual unit availability factor of 84.0% (approx. 7,359 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 0.849 lb/mmBtu emission baseline at 2,744 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 1 

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 approximately 90% design removal from a baseline of 0.51 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 0.085 lb/mmBtu, for an overall reduction of 90 percent from a baseline of 0.849 lb/mmBtu. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 for an installed 

advanced separated overfire air system, or firm price equipment quotes with performance guarantees for 

SNCR alternatives, 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 use installed capital costs 

estimated in calendar year 2009 escalated to project completion forecast in 2018 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 1 

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

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

technologies on Milton R. Young Unit 1. 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 1, 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 

1. 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 257 MWg for MRY Station Unit 116. 

A review of the unit capital cost factor range and single point factors applicable to MRY Station Unit 1 

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 1 SCR (tail end 

or low-dust) system would be accounted for as if the SCR equipment were being provided for Unit 1 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 1 - Stand Alone SCR Projects 

Alt. 

Label(1) NOX Control Alternative 

Range(2)

($/kW) 

Single Point Unit 

Capital Cost 

Factor(3), ($/kW) 

MRYS Unit 1

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(4) (4) 867(4),(5) 

T1 Hypothetical Tail End SCR w/ ASOFA –Scenario B(4) (4) 867(4),(5)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) (4) 703(4),(5)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) (4) 703(4),(5)

E SNCR (using urea) w/ ASOFA 20-35(6) 31.6(5),(6)

D Gas Reburn w/ ASOFA 15-30(7) 70.1(5),(7),(8) 

C Lignite Reburn w/ ASOFA 30-60(7) 181.5(5),(7),(9) 

B Fuel Lean Gas Reburn w/ ASOFA --(6) 41.4(5),(6),(8) 

A Advanced Separated Overfire Air (ASOFA) 5-10(7) 16.6(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 1 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 assume 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 1 in 2018 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 91.7 $/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 1 – Shared Facilities SCR Projects 

Alt. 

Label(1) NOX Control Alternative 

Range(2)

($/kW) 

Single Point Unit 

Capital Cost 

Factor(3), ($/kW) 

MRYS Unit 1

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(4) (4) 706(4),(5) 

T1 Hypothetical Tail End SCR w/ ASOFA –Scenario B(4) (4) 706(4),(5)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) (4) 543(4),(5)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) (4) 543(4),(5)

E SNCR (using urea) w/ ASOFA 20-35(6) 31.6(5),(6)

D Gas Reburn w/ ASOFA 15-30(7) 70.1(5),(7),(8) 

C Lignite Reburn w/ ASOFA 30-60(7) 181.5(5),(7),(9) 

B Fuel Lean Gas Reburn w/ ASOFA --(6) 41.4(5),(6),(8) 

A Advanced Separated Overfire Air (ASOFA) 5-10(7) 16.6(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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 1 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 assume 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 1 in 2018 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 91.7 $/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 properly represent total 

installed costs that could be expected for MRYS Unit 1. Site-specific needs and challenges identified for 

applying tail end and low-dust SCR technologies to Milton R. Young Station Unit 1 significantly influence 

the capital cost estimate for variations of these hypothetically-applied SCR 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 applications of low-dust SCR 

technology 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 application of 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 1 assume one reactor / gas reheat system installed, connecting to the new wet lime flue gas 

desulfurization absorber currently being constructed. Each hypothetically-applied SCR alternative includes 

flue gas reheat equipment that is typical for these applications but not required for conventional highdust/hot side SCR systems. 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 hypothetically-applied

single SCR reactor 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 1 - 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) 222,864(4) 19,430(4) 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) 222,864(4) 19,430(4)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 180,739(4) 15,758(4)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) 180,739(4) 15,758(4) 

E SNCR w/ ASOFA 8,113 707 

D Gas Reburn w/ ASOFA(5) 18,006 1,570 

C Lignite Reburn w/ ASOFA(6) 46,656 4,068 

B Fuel Lean Gas Reburn w/ ASOFA(5) 10,639 928 

A Advanced SOFA (ASOFA) 4,277 373 

 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 257 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 1 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 1 in 

2018 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 

$8,075,000 for CGR and $4,038,000 for FLGR; and annualized capital cost of $704,000/yr for CGR and 

$352,000 for FLGR. See footnote number 8 under Table 4-3SA. 

(6) - Costs for increased PM collection capacity included in lignite reburn option are $23,561,000 for installed 

capital cost, and $2,054,000/yr annualized capital cost. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-15 Burns & McDonnell 

TABLE 4-4SF – Estimated Capital Costs for 

NOX Control Alternatives - MRY Station Unit 1 – 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) 181,484(4) 15,823(4) 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) 181,484(4) 15,823(4)

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 139,639(4) 12,174(4)

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) 139,639(4) 12,174(4) 

E SNCR w/ ASOFA 8,113 707 

D Gas Reburn w/ ASOFA(5) 18,006 1,570 

C Lignite Reburn w/ ASOFA(6) 46,656 4,068 

B Fuel Lean Gas Reburn w/ ASOFA(5) 10,639 928 

A Advanced SOFA (ASOFA) 4,277 373 

 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 257 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 1 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 1 in 2018 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 

$8,075,000 for CGR and $4,038,000 for FLGR; and annualized capital cost of $704,000/yr for CGR and 

$352,000 for FLGR. See footnote number 8 under Table 4-3SF. 

(6) - Costs for increased PM collection capacity included in lignite reburn option are $23,561,000 for installed 

capital cost, and $2,054,000/yr annualized capital cost. 

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

MRYS Unit 1 are shown in Table 4-5SA and Table 4-5SF in 2018, 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 1 included the following equipment and components: 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-16 Burns & McDonnell 

• One SCR reactor 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 1 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 1 

Stand Alone SCR Projects 

Alt. 

Label(1) Hypothetical SCR Alternative(2) 

Estimated 

BMcD Study 

Total Project 

Cost(3), 

2018$ 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 294,586 235,884 214,221 

Urea preparation and storage, 

building, and equipment(6) _ 4,808(6) 4,366(6)

 ASOFA _ _ 4,277 

T2, T1 TOTAL _ _ 222,864(6)

L2, L1 Low-Dust SCR 236,658 189,499 172,096 

Urea preparation and storage, 

building, and equipment _ 4,808(6) 4,366(6)

 ASOFA _ _ 4,277 

L2, L1 TOTAL _ _ 180,739(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 1 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. 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. Does not include installed capital cost for ASOFA, as shown in Table 4-4SA. 

(4) Modified Total Project Costs are converted from 2018$ to 2009$ as described in the text, except as described in footnote 6 

below. Present Value factor (discounted from future value) is 0.80073. 

(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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-18 Burns & McDonnell 

TABLE 4-5SF – Estimated Capital Costs for 

Hypothetically-Applied SCR Alternatives - MRY Station Unit 1 

Shared Facilities SCR Projects

Alt. 

Label(1) Hypothetical SCR Alternative(2) 

Estimated 

BMcD Study 

Total Project 

Cost(3), 

2018$ 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 240,817 192,829 175,120 

Urea preparation and storage, 

building, and equipment(6) _ 2,298(6) 2,087(6)

 ASOFA _ _ 4,277 

T2, T1 TOTAL _ _ 181,484(6)

L2, L1 Low-Dust SCR 183,274 146,753 133,275 

Urea preparation and storage, 

building, and equipment(6) _ 2,298(6) 2,087(6)

 ASOFA _ _ 4,277 

L2, L1 TOTAL _ _ 139,639(6)

(1) All 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 1 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. 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. Does not include installed capital cost for ASOFA, as shown in Table 4-4SF. 

(4) Modified Total Project Costs are converted from 2018$ to 2009$ as described in the text, except as described in footnote 6 

below. Present Value factor (discounted from future value) is 0.80073. 

(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 1 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 

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

 

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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-19 Burns & McDonnell 

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 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 96.6 percent 

(based on a historic (demonstrated) sustainable unit output capacity of 253 MWg) combined with a 12-

month rolling average availability (uptime) of 8,528 operating hours (97.3 percent of 8760 hours per year) 

resulting in an equivalent annual average unit capacity factor of 94.1% was assumed for Unit 1’s precontrol baseline annual operation. A 12-month rolling average heat input rate of 2,744 mmBtu/hr and a 12-

month rolling average NOX emission rate of 0.849 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 1. 

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 

previously-evaluated feasible NOX emission reduction technologies. These are listed in order of control 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-20 Burns & McDonnell 

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 1 - 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) 20,048 25,034 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) 29,361 36,664 

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 18,332 22,891

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) 29,178 36,435

E SNCR w/ ASOFA 5,417 6,764 

D Gas Reburn w/ ASOFA 28,641 35,765 

C Lignite Reburn w/ ASOFA(5) 5,862 7,320 

B FLGR w/ ASOFA 12,863 16,062 

A Advanced SOFA (ASOFA) 1,695 2,117 

 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 (244.5 MWg) and assumes a 97.3% average annual availability, which is highest 

consecutive 12-months of operation from 2001-2005. All cost figures in 2006 dollars. Revised February, 2010.

(3) - Levelized annual O&M cost = Annual O&M cost x 1.24873 annualized O&M cost factor. Rev. Feb. 2010.

(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 1 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 estimates specific to MRYS Unit 1 in 2018 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 assume 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 $2,024,000/yr for annual O&M cost, 

and $2,527,000/yr annualized O&M cost. 

 

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

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-21 Burns & McDonnell 

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

NOX Control Alternatives - MRY Station Unit 1 – 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) 18,806 23,484 

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(4) 28,120 35,114 

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(4) 17,099 21,352

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(4) 26,483 33,070

E SNCR w/ ASOFA 5,417 6,764 

D Gas Reburn w/ ASOFA 28,641 35,765 

C Lignite Reburn w/ ASOFA(5) 5,862 7,320 

B FLGR w/ ASOFA 12,863 16,062 

A Advanced SOFA (ASOFA) 1,695 2,117 

 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 (244.5 MWg) and assumes a 97.3% average annual availability, which is highest 

consecutive 12-months of operation from 2001-2005. All cost figures in 2006 dollars. Revised February, 2010.

(3) - Levelized annual O&M cost = Annual O&M cost x 1.24873 annualized O&M cost factor. Rev. Feb. 2010.

(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 1 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 estimates specific to MRYS Unit 1 in 2018 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 assume 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 $2,024,000/yr for annual O&M cost, 

and $2,527,000/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 1. 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 

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. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-22 Burns & McDonnell 

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 a new induced draft booster fan 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 9.7 MW, using estimated annual 

average electrical loads of the booster fan, direct flue gas reheat burner combustion air fan, urea-toammonia conversion dilution/combustion air fan, 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 8.0 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 fan, 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 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 

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 hypothetically-
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-23 Burns & McDonnell 

applied 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 slipstream 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 hypothetically-applied catalyst replacement schedule of 16,000 hours. Specifically 

for MRYS Unit 1, this scenario is based on the replacement of one catalyst layer every 16,000 operating 

hours (essentially every two years of operation). 

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 1 is three times per year. Therefore, Scenario B for Unit 1 is based on 

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

the four layer SCR reactor is exposed to flue gas during approximately 16 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 catalyst 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 146 cubic meters 

per layer per reactor for the single reactor. A fourth (bottom) layer at 195 cubic meters is expected to be 

required after initial operation of hypothetically-applied full-time tail end or low-dust SCR alternatives, as 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-24 Burns & McDonnell 

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 213 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 938 hours per year for Scenario B 

TESCR case (assuming three layers are replaced every year) over and above the hours per year of outage time 

assumed for ASOFA impacts. Additional outage time of 256 hours per year was estimated to be attributable 

to the hypothetical application of low-dust SCR Scenario A alternative, and 981 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-25 Burns & McDonnell 

TABLE C.4-1 – Expected Availability Reductions for MRYS Unit 1 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) 0.928 8127 633 401 

T1 Hypothetical Tail End SCR 

w/ ASOFA – Scenario B(6) 0.845 7402 1358 1126 

L2 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario A(6) 0.923 8084 676 444 

L1 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario B(6) 0.840 7359 1401 1169 

E SNCR w/ ASOFA 0.942 8255 505 273 

D Gas Reburn w/ ASOFA 0.952 8340 420 188 

C Coal Reburn w/ ASOFA 0.937 8212 548 316 

B FLGR w/ ASOFA 0.952 8340 420 188 

A Advanced SOFA (ASOFA) 0.952 8340 420 188 

 Baseline 0.973 8528 232 0 

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

(2) – 12-month baseline availability is assumed at 97.3 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 1 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 assumes 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 C3-12. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-26 Burns & McDonnell 

TABLE C.4-2 – Expected Capacity Reductions for MRYS Unit 1 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) 0.937 97,976,764 3,429 

T1 Hypothetical Tail End SCR w/ 

ASOFA – Scenario B(5) 0.937 275,168,784 9,631 

L2 Hypothetical Low-Dust SCR w/ 

ASOFA – Scenario A(5) 0.942 108,399,824 3,794 

L1 Hypothetical Low-Dust SCR w/ 

ASOFA – Scenario B(5) 0.942 285,591,844 9,996(6) 

E SNCR w/ ASOFA 0.965 67,660,606 2,368 

D Gas Reburn w/ ASOFA 0.957 46,120,681 1,614 

C Lignite Reburn w/ ASOFA 0.961 77,958,350 2,729 

B FLGR w/ ASOFA 0.962 46,400,200 1,624 

A Advanced SOFA (ASOFA) 0.966 46,586,546 1,631 

 Baseline 0.966 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 96.6 percent (= 244.4/253.0). 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 244.4 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 1 at Milton R. Young Station. The estimated annual unit 

running plant capacity 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 assumes 

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

(6) Unit Generation Reduction for low-dust SCR Scenario B was $11,940,000. It should be shown as $9,996,000 instead. 

This does not affect economics shown in subsequent tables and graphs. Revised February, 2010.

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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-27 Burns & McDonnell 

C3 of the initial NOX BACT Analysis Study report32. 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 1 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) 9,685 0 9,685 73,768,605 2,582 

T1 Hypothetical Tail End SCR w/ 

ASOFA – Scenario B(7) 9,685 0 9,685 67,189,753 2,352 

L2 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario A(7) 8,012 0 8,012 61,018,532 2,136 

L1 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario B(7) 8,012 0 8,012 55,548,184 1,944 

E SNCR w/ ASOFA 73.1 0 73.1 582,411 20 

D Gas Reburn w/ ASOFA 1 133 (132) (1,054,343) (37) 

C Lignite Reburn w/ ASOFA 4,666 261 4,405 11,905,082 1,217 

B FLGR w/ ASOFA 1 73 (72) (578,744) (20) 

A Advanced SOFA (ASOFA) 1 0 1 8,058 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 1,507 kW for feed preparation and conveying equipment demand plus 3,158 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 1 at Milton R. Young Station. The estimated power demands 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 due to the four hypotheticallyapplied 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 1 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) 73,768,605 97,976,764 171,745,369 6,011 

T1 Hypothetical Tail End SCR 

w/ ASOFA –Scenario B(6) 67,189,753 275,168,784 342,358,537 11,983 

L2 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario A(6) 61,018,532 108,399,824 169,418,356 5,930 

L1 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario B(6) 55,548,184 285,591,844 341,140,028 11,940 

E SNCR w/ ASOFA 582,411 67,660,606 68,243,017 2,389 

D Gas Reburn w/ ASOFA (1,054,343) 46,120,681 45,066,338 1,577 

C Lignite Reburn w/ ASOFA 11,905,082 77,958,350 89,863,432 3,946 

B FLGR w/ ASOFA (578,744) 46,400,200 45,821,456 1,604 

A Advanced SOFA (ASOFA) 8,058 46,586,546 46,594,605 1,631 

(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

244.4 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 electricity generation, assumed to be $35.00/MW-hr. 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 1 at Milton R. Young Station. The estimated power demand shown for hypothetically-

 

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

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-29 Burns & McDonnell 

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. 

4.2.1.3 LEVELIZED TOTAL ANNUAL COST ESTIMATES FOR MRY STATION 

NOX CONTROLS 

A comparison of the control versus cost-effectiveness of four hypothetically-applied SCR cases and 

previously-analyzed feasible NOX control alternatives on Milton R. Young Unit 1 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 1. 

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

for NOX Control Alternatives - MRY Station Unit 1 - 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) 589 9,345 44,465 4,758 

T1 Hypothetical Tail End SCR 

w/ ASOFA – Scenario B(6) 536 9,398 56,095 5,969 

L2 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario A(6) 586 9,348 38,649 4,134

L1 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario B(6) 533 9,401 52,193 5,552

E SNCR w/ ASOFA 4,025 5,909 7,472 1,265 

D Gas Reburn w/ ASOFA 4,275 5,659 37,334(7) 6,597 

C Lignite Reburn w/ ASOFA 4,343 5,591 11,388(8) 2,037 

B FLGR w/ ASOFA 5,260 4,674 16,990(7) 3,635 

A Advanced SOFA (ASOFA) 5,874 4,060 2,489 613 

 Baseline 9,934 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; 9,934 (= 

0.973*8760*2,330/2000) 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, 

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. Revised February, 2010.

(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. Revised February, 2010.
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-30 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 1 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. Costs are derived from Burns & 

McDonnell internal database and cost estimates specifically for MRYS Unit 1 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 $704,000/yr for 

CGR and $352,000 for FLGR. See footnote number 8 under Table 4-3SA. 

(8) - LTAC for increased PM collection capacity included in lignite reburn option are approximately $2,054,000 for annualized 

capital cost plus $2,527,000/yr for annualized O&M cost, for a LTAC subtotal of $4,581,000/yr. 

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

for NOX Control Alternatives - MRY Station Unit 1 - 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) 589 9,345 39,307 4,206 

T1 Hypothetical Tail End SCR 

w/ ASOFA – Scenario B(6) 536 9,398 50,937 5,420 

L2 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario A(6) 586 9,348 33,526 3,586

L1 Hypothetical Low-Dust SCR 

w/ ASOFA – Scenario B(6) 533 9,401 45,244 4,813

E SNCR w/ ASOFA 4,025 5,909 7,472 1,265 

D Gas Reburn w/ ASOFA 4,275 5,659 37,334(7) 6,597 

C Lignite Reburn w/ ASOFA 4,343 5,591 11,388(8) 2,037 

B FLGR w/ ASOFA 5,260 4,674 16,990(7) 3,635 

A Advanced SOFA (ASOFA) 5,874 4,060 2,489 613 

 Baseline 9,934 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; 9,934 (= 

0.973*8760*2,330/2000) 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 

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. Revised February, 2010.

(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. Revised February, 2010.

(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 1 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 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-31 Burns & McDonnell 

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

McDonnell internal database and cost estimates specifically for MRYS Unit 1 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 $704,000/yr 

for CGR and $352,000 for FLGR. See footnote number 8 under Table 4-3SF. 

(8) - LTAC for increased PM collection capacity included in lignite reburn option are approximately $2,054,000 for 

annualized capital cost plus $2,527,000/yr for annualized O&M cost, for a LTAC subtotal of $4,581,000/yr. 

Figure 4-1SA – NOX Control Cost Effectiveness - MRY Station Unit 1(1) 

Stand Alone SCR Projects

Milton R. Young Station Unit 1 NOx Control 

Annual Removal vs Levelized Total Annual Cost - Stand Alone Projects

0

10000

20000

30000

40000

50000

60000

0 2000 4000 6000 8000 10000

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/ AOSFA 

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)

A

B

E

C

D

T1

T2

L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-7SA. Revised February, 2010. 

(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 1 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-32 Burns & McDonnell 

Figure 4-1SF – NOX Control Cost Effectiveness - MRY Station Unit 1(1) 

Shared Facilities SCR Projects

Milton R. Young Station Unit 1 NOx Control 

Annual Removal vs Levelized Total Annual Cost - Shared Facilities Projects

0

10000

20000

30000

40000

50000

60000

0 2000 4000 6000 8000 10000

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/ AOSFA 

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)

A

B

E

C

D

L1

T2

L2

T1

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-7SF. Revised February, 2010.

(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 1 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. 

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 1 

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. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-33 Burns & McDonnell 

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 1 - Stand Alone SCR 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) 

44,465 9,345 36,993 3,437 10,765 

T1 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario B(5)

56,095 9,398 48,623 3,489 13,936 

L2 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario A(5)

38,649 9,348 31,777 3,440 9,064

L1 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario B(5) 

52,193 9,401 44,721 3,492 12,806

E SNCR w/ ASOFA 7,472 5,909 4,982 1,849 2,694 

A Advanced SOFA 

(ASOFA) 2,489 4,060 2,489 4,060 613 

(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. Revised February, 2010.

(3) - Annual emission reduction and levelized control cost of these alternatives is relative to current costs and pre-control unit

MCR baseline emission rate. Revised February, 2010.

(4) - Increment based upon comparison between consecutive alternatives (points) from lowest to highest. Revised February, 2010.

(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 1 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. Revised February, 2010.
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-34 Burns & McDonnell 

TABLE 4-8SF – Dominant Controls Cost Curve Points for 

NOX Control Alternatives - MRY Station Unit 1 - Shared Facilities SCR 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) 

39,307 9,345 31,835 3,437 9,264 

T1 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario B(5)

50,937 9,398 43,465 3,489 12,458 

L2 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario A(5)

33,526 9,348 26,054 3,440 7,575

L1 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario B(5) 

45,244 9,401 37,772 3,492 10,816

E SNCR w/ ASOFA 7,472 5,909 4,982 1,849 2,694 

A Advanced SOFA 

(ASOFA) 2,489 4,060 2,489 4,060 613 

(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. Revised February, 2010.

(3) - Annual emission reduction and levelized control cost of these alternatives is relative to current costs and pre-control 

unit MCR baseline emission rate. Revised February, 2010.

(4) - Increment based upon comparison between consecutive alternatives (points) from lowest to highest. Revised February, 

2010.

(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 1 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. Revised 

February, 2010.

Figures 4-2SA and 4-2SF contains a repetition of the levelized total annual cost and NOX control 

information from Figures 4-1SA and 4-1SF for MRY Station Unit 1, 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 1 NOX emissions alternatives. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-35 Burns & McDonnell 

Figure 4-2SA – MRY Station Unit 1 NOX Control Alternatives 

BACT Dominant Controls Cost Curve(1) - Stand Alone SCR Projects

 Milton R. Young Station Unit 1 NOx Control 

Dominant Controls Cost Curve - Stand Alone Projects

0

10,000

20,000

30,000

40,000

50,000

60,000

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000

Annual NOx Removal, tons/yr

Levelized Total Annual Cost for NOx 

Control, 1000$/yr 

E

$10,765/ton

$9,064/ton

Slope = incremental $/ton

$13,936/ton

$2,694/ton

A = Advanced SOFA

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)

(Points B, C, and D removed)

A

$613/ton

T2

T1

$12,806/ton

/t

L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-8SA. Revised February, 2010.

(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 1 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-36 Burns & McDonnell 

Figure 4-2SF – MRY Station Unit 1 NOX Control Alternatives 

BACT Dominant Controls Cost Curve(1) – Shared Facilities SCR Projects

 Milton R. Young Station Unit 1 NOx Control 

Dominant Controls Cost Curve - Shared Facilities Projects

0

10,000

20,000

30,000

40,000

50,000

60,000

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000

Annual NOx Removal, tons/yr

Levelized Total Annual Cost for NOx 

Control, 1000$/yr 

E

$9,264/ton

$7,575/ton

Slope = incremental $/ton

$12,458/ton

$2,694/ton

A = Advanced SOFA

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)

(Points B, C, and D removed)

A

$613/ton

T2

T1

$10,816/ton

L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-8SF. Revised February, 2010.

(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 1 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 Tables 4-7SA and 4-7SF, the average levelized control cost effectiveness 

(called the unit control cost in this report) ranges from approximately $613/ton to $6,597/ton of MRYS Unit 

1’s NOX emissions removed. The unit control cost for the hypothetically-applied Scenario A Tail End SCR 

w/ ASOFA case was $4,758/ton and for the hypothetically-applied Scenario B Tail End SCR w/ ASOFA 

case was $5,969/ton (stand alone projects). The unit control cost for the hypothetically-applied Scenario A 

Low-Dust SCR w/ ASOFA case was $3,944 4,134/ton and for the hypothetically-applied Scenario B LowDust SCR w/ ASOFA case was $5,380 5,552/ton (stand alone projects). The unit control cost for the 

hypothetically-applied Scenario A Tail End SCR w/ ASOFA case was $4,206/ton and for the 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-37 Burns & McDonnell 

hypothetically-applied Scenario B Tail End SCR w/ ASOFA case was $5,420/ton (shared facilities 

projects). The unit control cost for the hypothetically-applied Scenario A Low-Dust SCR w/ ASOFA case 

was $3,396 3,586/ton and for the hypothetically-applied Scenario B Low-Dust SCR w/ ASOFA case was 

$4,835 4,813/ton (shared facilities projects). Unit control costs for SNCR w/ ASOFA was $1,265/ton, more 

than twice that of ASOFA ($613/ton). It should be noted, however, that the very high estimated average 

control costs involve fuel lean gas reburn ($3,635/ton) and conventional gas reburn ($6,597/ton) 

technologies that were 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 1 incurs a significant annual (levelized) incremental cost compared to the 

ASOFA NOX control technique. The slope from zero (baseline) to ASOFA (Point A) was $613/ton; the 

incremental cost per ton (slope) from ASOFA (Point A) to SNCR with ASOFA (Point E ) was $2,694/ton 

for MRYS Unit 1. 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 $8,547 9,064/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 $10,765/ton (stand alone projects). 

The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypotheticallyapplied low-dust SCR case (Point L1, Scenario B) was $12,343 12,806/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 $13,936/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 $7,058 7,575/ton (low-dust Point L2, Scenario A) and $9,264/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 $10,876 10,816/ton (low-dust, Point L1, Scenario B) and 

$12,458/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 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-38 Burns & McDonnell 

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.”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 1 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 1 of $549 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 1 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 1 NOx Emissions _________________________________________________________________________________________________________________________________________________Minnkota Power Cooperative, Inc. 4-39 

TABLE 4-9SA – Estimated Emissions and Economic Impacts Summary for NOX Control Alternatives - MRY Station Unit 1 - St

Summary of Estimated Annual Emissions and Economics for NOx Control Alternatives Evaluated for Milton R. Young Station Unit 1 – 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) 0.053 145 589 9,345 93.8(8) 222,864 20,04T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(7) 0.053 145 536 9,398 93.8(8) 222,864 29,36L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(7) 0.053 145 586 9,348 93.8(8) 180,739 18,33L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(7) 0.053 145 533 9,401 93.8(8) 180,739 29,17

E SNCR w/ ASOFA 0.355 975 4,025 5,909 58.1 8,113 5,41

D Gas Reburn w/ ASOFA 0.374 1,025 4,275 5,659 56.0 18,006 28,64

C Lignite Reburn w/ ASOFA 0.385 1,058 4,343 5,591 54.6 46,656 5,86B FLGR w/ ASOFA 0.460 1,261 5,260 4,674 45.9 10,639 12,86

A Advanced SOFA (ASOFA) 0.513 1,409 5,874 4,060 39.5 4,277 1,69

 Baseline 0.849 2,330 9,934 0 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 unit emission baseline of 0.849 lb/mmBtu at 2,744 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 244.45 MWg and assumes a 97.3% average annual availability. Va

month operating 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 257 MWg unit capacity rating. All cost figures in 2006 dollars. C

pressure natural gas supply pipeline installed capital cost of $8,075,000 for CGR and $4,038,000 for FLGR. Costs for increased PM collection capacity included in lignite reburn option are $

(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 244.45 MWg and assumes a 96.6% 

to nominal unit gross electrical output capacity of 253 MWg. All cost figures in 2006 dollars. Costs for increased PM collection capacity included in lignite reburn option are $1,909,000/yr 

(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. Revised February, 2010.

(6) - Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost ($/yr) divided by Annual Emission Reduction (tons). All cost figures in 2006 dollars. Revised February, 2010.

(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 1 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 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. Revised February, 2010.

(8) - The stated overall control percentage includes the anticipated long-term emission reduction of 90% design removal from a baseline of 0.51 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 0.085 lb/mmBtu, for an overall reduction of 90 

(9) - LTAC for reburn options include high-pressure natural gas supply pipeline annualized capital cost of $704,000/yr for CGR and $352,000 for FLGR; LTAC for increased PM collection capaci

$2,054,000 for annualized capital cost plus $2,384,000/yr for annualized O&M cost, for a total of $4,438,000/yr. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions _________________________________________________________________________________________________________________________________________________Minnkota Power Cooperative, Inc. 4-40 

TABLE 4-9SF – Estimated Emissions and Economic Impacts Summary for NOX Control Alternatives - MRY Station Unit 1 – S

Summary of Estimated Annual Emissions and Economics for NOx Control Alternatives Evaluated for Milton R. Young Station Unit 1 – Shared Fa

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) 0.053 145 589 9,345 93.8(8) 181,484 18,80T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(7) 0.053 145 536 9,398 93.8(8) 181,484 28,12L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(7) 0.053 145 586 9,348 93.8(8) 139,639 17,09L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(7) 0.053 145 533 9,401 93.8(8) 139,639 26,48

E SNCR w/ ASOFA 0.355 975 4,025 5,909 58.1 8,113 5,41

D Gas Reburn w/ ASOFA 0.374 1,025 4,275 5,659 56.0 18,006 28,64

C Lignite Reburn w/ ASOFA 0.385 1,058 4,343 5,591 54.6 46,656 5,86B FLGR w/ ASOFA 0.460 1,261 5,260 4,674 45.9 10,639 12,86

A Advanced SOFA (ASOFA) 0.513 1,409 5,874 4,060 39.5 4,277 1,69

 Baseline 0.849 2,330 9,934 0 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 unit emission baseline of 0.849 lb/mmBtu at 2,744 mmBtu/hr MCR heat input. Emissions are calculated from u

heat input, and annual hrs/yr operation compared to pre-control baseline based on annual operation at a gross unit electrical output of 244.45 MWg and assumes a 97.3% average anemission data for the 12 month operating 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 257 MWg unit capacity rating. All cost figures in 200

include high-pressure natural gas supply pipeline installed capital cost of $8,075,000 for CGR and $4,038,000 for FLGR. Costs for increased PM collection capacity included in liginstalled 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 244.45 MWg and assu

ratio compared to nominal unit gross electrical output capacity of 253 MWg. All cost figures in 2006 dollars. Costs for increased PM collection capacity included in lignite reburn 

cost. Revised February, 2010.

(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 cos

Annual O&M cost x 1.24873 annualized O&M cost factor. Revised February, 2010.

(6) - Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost ($/yr) divided by Annual Emission Reduction (tons). All cost figures in 2006 dollars. Revised Feb

(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 1 at Milton R

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 

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 sub

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

that assumes replacement of SCR catalyst after a specified number of hours of unit operation. Revised February, 2010.

(8) - The stated overall control percentage includes the anticipated long-term emission reduction of 90% design removal from a baseline of 0.51 lb/mmBtu resulting from an advanced s

low-NOX cyclone combustion. Without a separated overfire air system operation or any other technique employed, the assumed emission rate would be 0.085 lb/mmBtu, for an ove

0.849 lb/mmBtu. 

(9) - LTAC for reburn options include high-pressure natural gas supply pipeline annualized capital cost of $704,000/yr for CGR and $352,000 for FLGR; LTAC for increased PM colle

are $2,054,000 for annualized capital cost plus $2,384,000/yr for annualized O&M cost, for a total of $4,438,000/yr. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 1 

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 1. 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 demand for the hypothetical application of TESCR and LDSCR equipment were 

calculated to be 9.7 MW and 8.0 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 12 

inches w.c. of flue gas pressure drop was assumed for each hypothetical application of low-dust SCR 

system, and an estimated additional 19 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 

fouling of the catalyst for the hypothetical application of SCR system ductwork, reactor, and gas-gas 

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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 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 application 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 low-dust 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-toammonia conversion system operation. 

Final reactor inlet flue gas reheat systems are required for the hypothetical application of tail end and lowdust 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-43 Burns & McDonnell 

TABLE 4-10 – Energy Impacts for NOX Control Alternatives - MRY Station Unit 1

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) 

32,580 460,090 0 0 492,670 

T1 Hypothetical Tail End 

SCR w/ ASOFA – 

Scenario B(5)

29,674 419,054 0 0 448,728 

L2 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario A(5)

32,409 413,655 0 0 446,064

L1 Hypothetical Low-Dust 

SCR w/ ASOFA – 

Scenario A(5) 

29,503 376,566 0 0 406,069

E SNCR w/ ASOFA 0 0 0 54,315 54,315 

D Gas Reburn w/ ASOFA 0 0 3,721,806 0 3,721,806 

C Lignite Reburn w/ 

ASOFA 0 0 0 0 0 

B FLGR w/ ASOFA 0 0 1,541,796 0 1,541,796 

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 1at 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. Revised February, 2010.

(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 = 4.27 mmBtu/hr for one reactor. 

(4) – Estimated annual natural gas usage for flue gas final reheat based on adjustments to preliminary vendor process 

calculations. TESCR rate = 60.3 mmBtu/hr for one reactor; LDSCR rate = 31 54.5 mmBtu/hr for one reactor. Rev 2/10.

(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. Revised February, 2010.

(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. Revised February, 2010.
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-44 Burns & McDonnell 

4.2.3 ENVIRONMENTAL IMPACTS OF HYPOTHETICALLY-APPLIED SCR NOX

CONTROL ALTERNATIVES FOR MRY STATION UNIT 1 

Operation of the NOX control technologies on the dominant controls cost curve for potential application at 

the Milton R. Young Station would 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 application of SCR 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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-45 Burns & McDonnell 

Unreacted ammonia (“slip”) from SCR operation will not be collected downstream of the tail end SCR 

reactor. The wet flue gas desulfurization absorber downstream of the low-dust SCR reactor 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 application of 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 will effectively eliminate the remaining SO3

downstream of the 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 an 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. 

4.2.4 SUMMARY OF ECONOMIC, ENERGY AND ENVIRONMENTAL IMPACTS 

OF HYPOTHETICALLY-APPLIED SCR NOX CONTROL ALTERNATIVES 

FOR MRY STATION UNIT 1 

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 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-46 Burns & McDonnell 

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 report41. This supplemental economic 

analysis examined the estimated capital cost of four hypothetically-applied SCR cases and previouslyanalyzed 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 top-down 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 cost effective 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 1. The results are 

summarized in Tables 4-11SA and 4-11SF. 

The unit control cost for the hypothetical application of Scenario A Tail End SCR w/ ASOFA case was 

$4,758/ton and was $5,969/ton for the hypothetical application of Scenario B Tail End SCR w/ ASOFA 

case (stand alone projects). The unit control cost for the hypothetical application of Scenario A Low-Dust 

SCR w/ ASOFA case was $3,944 4,134/ton and was $5,380 5,552/ton for the hypothetical application of 

Scenario B Low-Dust SCR w/ ASOFA case (stand alone projects). The unit control cost for the 

hypothetical application of Scenario A Tail End SCR w/ ASOFA case was $4,206/ton and was $5,420/ton 

for the hypothetical application of Scenario B Tail End SCR w/ ASOFA case (shared facilities projects). 

The unit control cost for the hypothetical application of Scenario A Low-Dust SCR w/ ASOFA case was 

$3,396 3,586/ton and was $4,835 4,813/ton for the hypothetical application of Scenario B Low-Dust SCR 

w/ ASOFA case (shared facilities projects). Unit control cost for SNCR w/ ASOFA was $1,265/ton, 

more than twice that of ASOFA ($613/ton). The UCCs for the hypothetical application of SCR are 

approximately 270 280 to 470 percent of the UCC for SNCR w/ ASOFA ($1,265/ton), and approximately 

550 580 to 970 percent of ASOFA’s UCC ($613/ton). 

The incremental cost analysis indicates that from a cost effectiveness viewpoint, the SNCR with ASOFA 

alternative for MRYS Unit 1 incurs a significant annual (levelized) incremental cost compared to the 

ASOFA NOX control technique. The slope from zero (baseline) to ASOFA (Point A) was $613/ton; the 

 

41 Ibid Reference number 3, October 2006, pages 3-20 through 3-38. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-47 Burns & McDonnell 

incremental cost per ton (slope) from ASOFA (Point A) to SNCR with ASOFA (Point E ) was $2,694/ton 

for MRYS Unit 1. The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top 

hypothetical application of low-dust SCR case (Point L2, Scenario A) was $8,547 9,064/ton (stand alone 

projects). The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetical 

application of tail end SCR case (Point T2, Scenario A) was $10,765/ton (stand alone projects). The 

incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetical 

application of low-dust SCR case (Point L1, Scenario B) was $12,343 12,806/ton (stand alone projects). 

The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetical 

application of tail end SCR case (Point T1, Scenario B) was $13,936/ton (stand alone projects). For 

shared projects, the incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top 

hypothetical application of SCR cases were $7,058 7,575/ton (low-dust Point L2, Scenario A) and 

$9,264/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 hypothetical application of SCR cases were $10,876

10,816/ton (low-dust, Point L1, Scenario B) and $12,458/ton (tail end Point T1, Scenario B). 

The incremental unit control cost per ton (slope) from SNCR with ASOFA to the hypothetical application 

of SCR with ASOFA cases are approximately 260 280 to 520 percent of the incremental UCC per ton 

(slope) between ASOFA and SNCR with ASOFA ($2,694/ton). The incremental UCCs from SNCR with 

ASOFA to the hypothetical application of SCR with ASOFA cases is between 11 12 and 23 times the 

incremental UCC for ASOFA from the pre-control baseline ($613/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 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-48 Burns & McDonnell 

MRYS Unit 1 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 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 costeffectiveness is $900 per ton” 43. EPA’s technical support document estimated an average control cost for 

SCR applied to MRYS Unit 1 of $549 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 hypothetical application of Low-Dust SCR w/ ASOFA cases at MRYS Unit 1 are $543 to 

$703/kW, which is more than 500 percent of the EPA’s number. The estimated “stand alone” and 

“shared facilities” installed capital costs for the hypothetical application of Tail End SCR w/ ASOFA 

cases are $706 to $867/kW, which is more than 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 hypothetical application of tail-end and lowdust SCR alternatives to MRYS Unit 1 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 

Station. Not withstanding the technical discussion of SCR technology infeasibility and technical details 

 

43 See Reference number 11, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136. 

44 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215. 

45 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 209. 

46 Ibid Reference number 11, July 2005, FR Vol. 70 No. 128, page 39168. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-49 Burns & McDonnell 

previously provided in Appendix A1 and Appendix B47 of the initial NOX BACT Analysis 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 

normal range of costs incurred, as compared to 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 hypothetical application of 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 1 (SNCR with ASOFA). Incremental control 

cost effectiveness for each hypothetical application of 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 1 (SNCR with ASOFA). 

 

There is an expected decrease in capacity and availability to generate electrical power due to the 

hypothetical application of low-dust and tail end SCR alternatives. A five 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 1 system are expected if the hypothetical application 

of low-dust or tail end SCR alternatives were installed. There are also substantial expected negative 

energy impacts for each hypothetical application of SCR control technology case. Additional auxiliary 

electrical power demands of approximately 8 to 10 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 1 will require additional replacement electrical power to be generated elsewhere. 

Natural gas is fired continuously during the urea-to-ammonia conversion system operation for the 

hypothetical application of Tail End and Low-Dust SCR with ASOFA alternatives. 

Final reactor inlet flue gas reheat systems are required for the hypothetical application of Tail End and 

Low-Dust SCR with ASOFA alternatives. Natural gas is fired continuously for flue gas reheating during 

SCR system operation for raising the reactor inlet temperature to 600oF minimum operating temperature 

 

47 Ibid Reference number 3, October 2006. 

48 See Reference number 11, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136. 

49 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215. 
Supplemental BACT Control and Cost-Effectiveness 

Analysis for MRY Station Unit 1 NOx Emissions 

_____________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-50 Burns & McDonnell 

(580oF for low-dust, 563oF for tail-end SCRs) before ammonia injection and NOx reduction can occur in 

the SCR reactor. 

The site-specific control costs estimated for application of hypothetical application of tail-end and lowdust SCR alternatives to MRYS Unit 1 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. SCR technologies of all three types identified in the 

October 2006 NOX BACT Analysis Study report 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 1 are confirmed. 

The economic, energy, and environmental impacts of each NOX control technology on the dominant 

controls cost curve for potential application to Unit 1 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 Analysis 

for MRY Station Unit 1 NOx Emissions _________________________________________________________________________________________________________________________________________________Minnkota Power Cooperative, Inc. 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 

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) 0.053 145 589 9,345 222,864 20,048 44,465 4,758 1T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(10) 0.053 145 536 9,398 222,864 29,361 56,095 5,969 1L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(10) 0.053 145 586 9,348 180,739 18,332 38,649 4,134 9L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(10) 0.053 145 533 9,401 180,739 29,178 52,193 5,552 1

E SNCR w/ ASOFA 0.355 975 4,025 5,909 8,113 5,417 7,472 1,265 2

A Advanced SOFA (ASOFA) 0.513 1,409 5,874 4,060 4,277 1,695 2,489 613 

 Baseline 0.849 2,330 9,934 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 0.849 lb/mmBtu at 2,744 mmBtu/hr heat input. Emissions are calculated from unit emission rates, cont

baseline based on annual operation at a gross unit electrical output of 244.5 MWg and assumes a 97.3% average annual availability. 

(3) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 257 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 244.5 MWg and assumes a 97.3% a

from 2001-2005. All cost figures in 2006 dollars. Revised February, 2010.

(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

Revised February, 2010.

(6) - 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. Revised February, 20

(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. Rev

(8) - Energy impacts are incremental auxiliary electrical power demand (kW) and annual power usage plus generation lost due to negative unit reliability (fewer hours per year of operation) resultin

(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 hypothetical application of 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 1 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 inform

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. 
Supplemental BACT Analysis 

for MRY Station Unit 1 NOx Emissions _________________________________________________________________________________________________________________________________________________Minnkota Power Cooperative, Inc. 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 

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) 0.053 145 589 9,345 181,484 18,806 39,307 4,206 9T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(10) 0.053 145 536 9,398 181,484 28,120 50,937 5,420 1L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(10) 0.053 145 586 9,348 139,639 17,099 33,526 3,586 7L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(10) 0.053 145 533 9,401 139,639 26,483 45,244 4,813 1

E SNCR w/ ASOFA 0.355 975 4,025 5,909 8,113 5,417 7,472 1,265 2

A Advanced SOFA (ASOFA) 0.513 1,409 5,874 4,060 4,277 1,695 2,489 613 

 Baseline 0.849 2,330 9,934 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 0.849 lb/mmBtu at 2,744 mmBtu/hr heat input. Emissions are calculated from unit emissio

pre-control baseline based on annual operation at a gross unit electrical output of 244.5 MWg and assumes a 97.3% average annual availability. 

(3) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 257 MWg unit capacity rating. All cost figures in 200(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 244.5 MWg and assum

operation from 2001-2005. All cost figures in 2006 dollars. Revised February, 2010.

(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 cos

O&M cost factor. Revised February, 2010.

(6) - 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. Revised F

(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 

(8) - Energy impacts are incremental auxiliary electrical power demand (kW) and annual power usage plus generation lost due to negative unit reliability (fewer hours per year of opera

baseline. 

(9) - Environmental impacts summarize expected non-air effects and potential toxic air emissions resulting from control alternative compared to the pre-control baseline. Flyash unbur

concentrations may increase an insignificant amount with air-staging cyclones. Excess unreacted ammonia (slip) expected from SNCR technology and the hypothetical application 

(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 1 at Milton R

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 equ

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, D

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 num
Supplemental BACT Analysis 

for MRY Station Unit 1 NOx Emissions 

______________________________________________________________________________________________ 

Minnkota Power Cooperative, Inc. 4-53

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.