# NOx BEST AVAILABLE CONTROL TECHNOLOGY
ANALYSIS STUDY - SUPPLEMENTAL REPORT

for 

# Milton R. Young Station Unit 2 Minnkota Power Cooperative, Inc.
Operating Agent for 

# Square Butte Electric Cooperative

Owner

November 2009

31777

# NOx Best Available Control Technology Analysis Study
SUPPLEMENTAL REPORT
for Milton R. Young Station Unit 2

prepared for



# Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative

November 2009

Project No. 31777

prepared by

Burns & McDonnell Engineering Company, Inc. Kansas City, Missouri

COPYRIGHT 2009 © BURN S & McDONNELL ENGINEERING COMPANY, INC.Supplemental BACT Control and Cost -Effectiveness Table of Contents Analysis for MRY Station Unit 2 NOx Emissions

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_____________________________________________________________________________________________ Square Butte Electric Cooperativ e TOC-1 Burns & McDonnell 

### TABLE OF CONTENTS

4.0 SUPPLEMENTAL NOx BACT ANALYSIS CONTROLS & COSTS – MRY STATION UNIT 2................................................................................. 4-1 4.01 ADDITIONAL NOx CONTROLS......................................................................4-2
4.1 RANK OF NOx CONTROL OPTIONS BY EFFECTIVENESS................................4-3
4.1.1 ESTIMATING CONTROL-EFFECTI VENESS OF NOx EMISSIONS CONTROL
OPTIONS....................................................................................................4-4
4.2 NOx CONTROLS ANALYSIS AND IMPACTS EVALUATION.................................4-8
4.2.1 NOx CONTROL ECONOMIC IMPACTS FOR MRY STATION UNIT 2.....................4-8
4.2.1.1 CAPITAL COST ESTIMATES FOR NOx CONTROL ALTERNATIVES..................4-9
4.2.1.1.1 CAPITAL COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF
SCR NOx CONTROL ALTERNATIVES.......................................................4-12
4.2.1.2 O&M COST ESTIMATES FOR NOx CONTROL ALTERNATIVES.......................4-18
4.2.1.2.1 O&M COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF
SCR NOx CONTROL ALTERNATIVES.......................................................4-21
4.2.1.3 LEVELIZED TOTAL ANNUAL CO ST ESTIMATES FOR MRY STATION NOx
CONTROLS.............................................................................................4-29
4.2.2 ENERGY IMPACTS OF HYPOTHETICALLY-APPLIED NOx CONTROL
ALTERNATIVES FOR MRY STATION UNIT 2..................................................4-42
4.2.3 ENVIRONMENTAL IMPACTS OF HYPOTHETICALLY-APPLIED
SCR NOx CONTROL ALTERNATIVES FO R MRY STATION UNIT 2.....................4-45 4.2.4 SUMMARY OF ECONOMIC, ENERGY , AND ENVIRONMENTAL IMPACTS OF
HYPOTHETICALLY-APPLIED SCR NOx CONTROL ALTERNATIVES FOR MRY
STATION UNIT 2.........................................................................................4-46
4.2.5 CONCLUSIONS .........................................................................................4-48
REFERENCES.....................................................................................................4-53_____________________________________________________________________________________________ Square Butte Electric Cooperativ e TOC-2 Burns & McDonnell 

### LIST OF TABLES

Table 4-1 – Ranked NO X 

### Control Options for MRY Station Unit 2 Boiler with Expected Control Performance Table 4-2 – Expected Annual NO X 

### Control Performance for MRY Station Unit 2 Alternatives Table 4-3SA – Unit Capital Cost Factors of NO X 

### Control Alternatives for MRY Station Unit 2 – Stand Alone SCR Projects Table 4-3SF – Unit Capital Cost Factors of NO X 

### Control Alternatives for MRY Station Unit 2 – Shared Facilities SCR Projects Table 4-4SA – Estimated Capital Costs for NO X 

### Control Alternatives - MRY Station Unit 2 – Stand Alone SCR Projects Table 4-4SF – Estimated Capital Costs for NO X 

### Control Alternatives - MRY Station Unit 2 – Shared Facilities SCR Projects Table 4-5SA – Estimated Capital Costs for Hypothetically-Applied SCR Alternatives - MRY Station Unit 2 – Stand Alone SCR Projects Table 4-5SF – Estimated Capital Costs for Hypothetically-Applied SCR Alternatives - MRY Station Unit 2 – Shared Facilities SCR Projects

Table 4-6SA – Estimated O&M Costs for NO X 

### Control Alternatives – MRY Station Unit 2 – Stand Alone SCR Projects

Table 4-6SF – Estimated O&M Costs for NO X 

### Control Alternatives – MRY Station Unit 2 – Shared Facilities SCR Projects Table C.4-1 – Expected Availability Reductions for MRYS Unit 2 NO X 

### Controls Table C.4-2 – Expected Capacity Reductions for MRYS Unit 2 NO X 

### Controls Table C.4-3 – Expected Auxiliary Electrical Power Demand Changes for MRYS Unit 2 NO X 

### Controls Table C.4-4 – Expected Auxiliary Electrical Powe r Demand and Generation Reduction Cost Changes for MRYS Unit 2 NO X 

### Controls

Table 4-7SA – Estimated Annual Emissions and Levelized Total Annual Cost for NO X 

### Control Alternatives– MRY Station Unit 2 – Stand Alone SCR Projects

Table 4-7SF – Estimated Annual Emissions and Levelized Total Annual Cost for NO X 

### Control Alternatives– MRY Station Unit 2 – Shared Facilities SCR Projects

Table 4-8SA – Dominant Controls Cost Curve Points for NO X 

### Control Alternatives – MRY Station Unit 2 – Stand Alone SCR Projects

Table 4-8SF – Dominant Controls Cost Curve Points for NO X 

### Control Alternatives – MRY Station Unit 2 – Shared Facilities SCR Projects Table 4-9SA – Estimated Emissions and Economic Impacts Summary for NO X 

### Control Alternatives – MRY Station Unit 2 – Stand Alone SCR Projects Table 4-9SF – Estimated Emissions and Economic Impacts Summary for NO X 

### Control Alternatives – MRY Station Unit 2 –Shared Facilities SCR Projects Table 4-10 – Energy Impacts for NO X 

### Control Alternatives – MRY Station Unit 2_____________________________________________________________________________________________ Square Butte Electric Cooperativ e TOC-3 Burns & McDonnell 

### Table 4-11SA – Summary of Supplemental BACT Analysis Impact Results for Dominant NO X 

### Control Alternatives – MRY Station Unit 2 – Stand Alone SCR Projects Table 4-11SF – Summary of Supplemental BACT Analysis Impact Results for Dominant NO X 

### Control Alternatives – MRY Station Unit 2 – Shared Facilities SCR Projects



### LIST OF FIGURES

Figure 4-1SA – NO X 

### Control Cost Effectiveness – MRY Sta tion Unit 2 – Stand Alone SCR Projects Figure 4-1SF – NO X 

### Control Cost Effectiveness – MRY Station Unit 2 – Shared Facilities SCR Projects Figure 4-2SA – MRY Station Unit 2 NO X 

### Control Alternatives BACT Dominant Controls Cost Curve – Stand Alone SCR Projects Figure 4-2SF – MRY Station Unit 2 NO X 

### Control Alternatives BACT Dominant Controls Cost Curve – Shared Facilities SCR Projects

* * * * *Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-1 Burns & McDonnell 

### 4.0 SUPPLEMEN TAL NOx BACT ANALYSIS CONTROLS & COSTS – MRY STATION UNIT 2 This supplement to the NO X 

### BACT analysis for Milton R. Young Station (MRYS) Unit 2 has been prepared in response to a request of the North Dakota Department of Health 1 

### . The NDDH requested completion of a “full” BACT analysis for two specific technologies that had been eliminated at step 2 of the BACT analysis process 2 

### in the October 2006 NO X 

### BACT Analysis Study report 3 

### . These two technologies are low-dust selective catalytic reduction (S CR) and tail-end SCR. The approach taken in this supplemental NO X 

### BACT Analysis Study report for MRYS Unit 2 includes ranking by control effectiveness and an impacts analysis of alternate control technologies for NO X 

### emissions that follows the third and fourth steps of a “top down” BACT anal ysis as described in the EPA’s Draft New Source Review Workshop Manual 4 

### . The initial NO X 

### BACT Analysis Study for Milton R. Young Station identified potentially available NO X 

### control techniques and technologies, summarized in Table 3-3 5 

### of the October 2006 report. Commonly-applied and novel NO X 

### control techniques and technologies, including a technical description of the specific emission re duction processes and capabilities, were summarized in

Section 3.2 6 

### and detailed in Appendix A1 of the October 2006 NO X 

### BACT Analysis Study report. This supplemental analysis report does not include the details of the technical feasibility discussion previously provided in the initial NO X 

### BACT Analysis Study report for MRYS Unit 2.

SCR technology is considered technically infeasibl e 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 emis sion rates shown for such hypothetically-applied SCR systems are based on assumptions that known or e xpected 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 simila r tail-end or low-dust SCR projects on coal-fired powerplants in the United States that could be used, with adjustments, to represent total installed costs that could be expected for MRYS Unit 2. Site-sp ecific needs and challenges identified for applying tail end and low-dust SCR technologies to Milton R. Young Station Unit 2 significantly influence the capital cost estimate for variations of these hypothetical a pplications 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 Supplemen t commences with Section 4.0, which places it at the end of the October 2006 Analysis, which ended at Section 3.5.2.
4 As described in the EPA’s Draft New Source Review Workshop Manual. Ibid Reference number 2, October 1990.
5 Ibid Reference number 3, October 2006, page 3-5.
6 Ibid Reference number 3, October 2006, page 3-6 through page 3-13, and pages A1-1 through A1-55.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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### “EPA Air Pollution Control Cost Manual” is not appli cable for use in estimating control equipment costs for these hypothetical applications of SCR tec hnologies, 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 appli es 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. Th erefore, the equations in the EPA Control Cost Manual cannot be used for estimating either of the hypothetical application of SCR configurations for which NDDH has requested economic analyses. Thus it was necessary to prepare independent sitespecific cost estimates.

The site-specific control costs estimated for app lication of hypothetical tail-end and low-dust SCR alternatives to MRYS Unit 2 are significantly highe r 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 8 

### . Low-dust and tail end SCR t echnologies should be excluded

from consideration for NO X 

### control at MRYS due to unacceptably high average and incremental cost per ton of pollutant removal based on the supplementa l analysis provided herein. The October 2006 NO X 

### BACT Analysis Study report, and additional subsequent arguments in cluded in responses to comments by the EPA, Department of Justice (DOJ), NDDH, and other parties 9 

### , 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 NO X 

### control alternatives at MRYS.



### 4.0.1 ADDITIONAL NOx CONTROLS
The inclusion of hypothetical emissions contro l alternatives employing tail-end and low-dust SCR technologies in this supplemental NO X 

### BACT Analysis Study report does not constitute agreement by

7 See Reference number 10, Section 4.2, Chapter 2, page 2-41, October 2000.
8 See Reference number 4, June, 2005.
9 Responses submitted by Minnkota in 2007-2009.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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### Minnkota or Square Butte that it is technically feasibl e to install these technologies on Unit 2 at Milton R. Young Station. The rationale for rejection of all fo rms of SCR technology in this specific case, based on an interpretation of the EPA’s Draf t New Source Review Workshop Manual 10 

### , has previously been submitted to the North Dakota Department of Health 11 

### and is not repeated here in. Nevertheless, this supplemental NO X 

### 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 NO X 

### emissions control alternatives involving hypothetical application of technologies such as low-dust and tail end SCR systems at MRYS is based on preliminary pl ant 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 c ontrol technology case was plotted with previouslyanalyzed feasible control alternatives.

For the techniques and technologies considered for determining MRYS Unit 2 NO X 

### control costeffectiveness, estimates were produced for predicted NO X 

### reductions that represent long-term expectations of the reduction techniques and technologi es being presented in the technical analysis. Each evaluated alternative was tabulated and graphed.

It should be noted that as of October 2006, when th e initial BACT Analysis Study report was completed, MRYS Unit 2 did not employ combustion-related or post-combustion NO X 

### emission reduction technology. However, the installation of an advanced form of a separated overfire air system (ASOFA), designed specifically for this boiler, was implemented for operation starting prior to December 31, 2007. A summary of the available alternate NO X 

### emission control technologies is discussed below.



### 4.1 RANK OF NO X 

### CONTROL OPTIONS BY EFFECTIVENESS
The first step 12 

### in this supplemental “top-down” BACT eval uation 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 NO X 

### control techniques and

10 Ibid Reference number 3, October 1990.
11 See Reference number 5, November 2007.
12 Step 3 per the NSR Manual, Ibid Reference 2, October 1990.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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### technologies included from the initial NO X 

### BACT Analysis Study report. To do this, we start with the basis for determining the NOx emissions control eff ectiveness, which is the historic baseline emissions expressed in pounds per million Btu of heat input from the five-year lookback period.

Unit 2 boiler’s baseline pre-control emissions at Milton R. Young Station are based upon the same highest rolling 12-month average unit emission rate (lb/mmBtu) and corresponding highest rolling 12- month average gross heat input rate (mmBtu/hr) that were reported in 2001-2005:

• MRYS Unit 2’s highest 12-month NO X 

### mass emissions averaged 0.786 lb/mmBtu at a corresponding average unit heat input rate of 4,885 mmBtu/hr and unit gross electrical output of

440 MW g 

### .

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

base-loaded manner.



### 4.1.1 ESTIMATING CONTRO L-EFFECTIVENESS OF NO X 

### EMISSIONS CONTROL OPTIONS
The estimated emission control performance for NO X 

### control techniques and technologies included from

the initial NO X 

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

7 13 

### . The expected control effectiveness of the hypo thetical application of tail end and low-dust SCR technology alternatives was added to the listing of highest-performing NO X 

### control alternatives remaining in consideration following the initial technical infeasi bility 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 ex pected reduction from operating with modestly airstaged cyclone furnaces and relocated lignite drying syst em vent ports as applied to this Milton R. Young cyclone boiler without incurring potential significant ne gative impacts of this technique. This level of expected NO X 

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

13 Ibid Reference number 3, October 2006, page 3-18.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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### TABLE 4-1 – Ranked NO X 

### Control Options for MRY Station Unit 2 Boiler with Expected Control Performance

Alt. Label (1) NO X Control Alternative Emission Rate (lb/mmBtu) Control Percentage (2) T2 Hypothetical Tail-End S CR w/ ASOFA – Scenario A (3) 0.049 93.8 (4)
T1 Hypothetical Tail-End S CR w/ ASOFA – Scenario B (3) 0.049 93.8 (4)
L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (3) 0.049 93.8 (4)
L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (3) 0.049 93.8 (4)
E SNCR (using urea) w/ ASOFA 0.330 58.0

D Gas Reburn with ASOFA 0.350 55.4
C Lignite Reburn w/ ASOFA 0.360 54.2

B Fuel Lean Gas Reburn with ASOFA 0.432 45.0
A Advanced Separated Overfire Air (ASOFA) 0.489 37.7

- Baseline 0.786 -

(1) - Alternative designation a ssigned from highest to lowest unit NOx emission rate. (2) - Control percentages are relative to an average pre-control emission baseline of 0.786 lb/mmB tu based on annual operation at highest pre-control 12-month rolling NOx summation mass emi ssions divided by the 12-mont h heat input summation. (3) - The inclusion of tail-end and low-dust S CR technologies in this table does not constitute agreement that it is technicall y feasible to install these technologies on Unit 2 at Milton R. Young Station. The emission rate shown for a hypotheticallyapplied SCR system is based on assumptions that known or exp ected reasons for technical inf easibility for installation of the SCR equipment on this boiler are solvable. SCR technolog y 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 othe r parties, so this info rmation for the hypotheti cal 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 antic ipated long-term emission reducti on of 90% design removal from a baseline of 0.49 lb/mmBtu resulting from an advanced separated overfire air system, with air-staged low-NO X cyclone combustion. Without a separated overfire air system operation or any other techni que employed, the assumed emission rate for hypothetically-applied SCR alterna tives would be 0.079 lb/mmBtu, for an overall reduction of 90 percent from a baseline of 0.786 lb/mmBtu.



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

achieve a NO X 

### emission level of 0.049 lb/mmBtu, which is approximately a 90% reduction from a 0.49 lb/mmBtu level representing ASOFA when operating m odestly air-staged cyclone furnaces with suitable

combustion controls.

Hourly mass emission rates for the baseline pre-contro l condition were calculated by multiplying the unit emission rate (lb/mmBtu) by the average hourly gross heat input rate (mmBtu/hr), both calculated from Unit 2’s highest 12-month NO X 

### mass emissions and heat inputs during the 5-year lookback period.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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### Equivalent annual NO X 

### emissions (tons) were calculated by multiplying the 12-month summation for unit operating hours during the same period as the highest NO X 

### 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 calcu lated 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 an nual uptime (availability) factor]. Scheduled and unplanned maintenance outages are expected to occu r 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 foulin g within the hypothetically-applied SCR systems on sodium, potassium, sulfur, and ammonia slip emission levels, conditions may occur during operation of the hypotheticallySCR systems that exceed the ability to adjust operational practices suffici ently 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 corr esponding operating time and outage time due to the four hypothetical applications of SCR technology cases, along with th e ASOFA and baseline numbers from the referenced Appendix C3 of the initial NO X 

### BACT Analysis Study report 14 

### . Based on these calculations, the estimated annual emissions for M.R. Young Station Unit 2 and the emission reduction corresponding to each technology alternative are shown in Table 4-2.

14 Ibid Reference number 3, October 2006, pages C3-1 through page C3-11.Supplemental BACT Control and Cost-EffectivenessAnalysis for MRY Station Unit 2 NOx Emissions_________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-7 Burns & McDonnellTABLE 4-2 – Expected Annual NOXControl Performance for MRYStation Unit 2 AlternativesEMISSIONSEmissionRateHourlyEmission(2)AnnualEmission(3)EmissionReduction(4)Alt.Label(1)NOx Control Alternativelb/mmBtu lbs/hr tons/yr tons/yrNOxRemovalEfficiency(5)%T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(6)0.049 239 936 14,857 93.8(7)T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(6)0.049 239 813 14,980 93.8(7)L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(6)0.049 239 931 14,862 93.8(7)L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(6)0.049 239 813 14,980 93.8(7)E SNCR (using urea) w/ ASOFA 0.330 1,612 6,421 9,372 58.0D Gas Reburn w/ ASOFA 0.350 1,710 6,882 8,910 55.4C Lignite Reburn w/ ASOFA 0.360 1,759 6,964 8,829 54.2B Fuel Lean Gas Reburn w/ ASOFA 0.432 2,110 8,490 7,303 45.0A Advanced Separated Overfire Air (ASOFA) 0.489 2,391 9,621 6,172 37.7- Baseline 0.786 3,839 15,793 0 -(1)- Alternative label has been assigned from highest to lowest unit NOx emission rate.(2)- Hourly NOXemission estimates (lb/hr) werecalculated based upon average annual unit emission rate (lb/mmBtu) x 4,885 mmBtu/hr heat input.(3)- Estimated annual emission tons assume an annual unit availability factor specific to each alternative; 93.9% was assumed forthe baseline case.See Appendix C3 of the October 2006 NOXBACT Analysis Study report. Hypothetically-applied tail end SCR case T2 assumes anannual unit availability factor of89.5% (approx. 7,842 operating hours per year) and case T1 assumes an annual unit availability factor of 77.8% (approx. 6,813 operating hours per year. Hypotheticallyapplied low-dust SCR case L2 assumes an annual unit availability factor of 89.0% (approx. 7,801 operating hours per year) and case L1 assumesan annual unitavailability factor of77.8% (approx. 6,813 operating hours per year).(4)- Estimated annual tons of emission reduction is the differencebetween annual baseline tons and each alternative’s annual emissions (tons).(5)- Estimated NOXcontrol level percentage reductions relative to 0.786 lb/mmBtu emission baseline at 4,885 mmBtu/hr MCR heat input.(6)- The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that itis technically feasible to install these technologies on Unit 2at Milton R. Young Station. The emission rate shown for a hypothetically-applied SCR system is based on assumptions that knownor expected reasons for technicalinfeasibility for installation and operation and maintenance ofthe SCR equipment on this boiler are solvable. SCR technologyis considered technically infeasible byMinnkota for application at MRYS per the October 2006 NOXBACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA,DOJ, and other parties, so this information for the hypotheticalapplication of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 fordetails of Scenario A and Scenario B that assume replacement ofSCR catalyst after a specified number of hours of unit operation.(7)- The stated overall control percentage includes the anticipated long-term emission reduction of90% design removal from a baseline of 0.49 lb/mmBtu resulting from anadvanced separated overfire air system, with air-staged low-NOXcyclone combustion. Withouta separated overfire air systemoperation or any other techniqueemployed, the assumed emission rate for hypothetically-applied SCR alternatives would be 0.079 lb/mmBtu, for an overall reduction of 90 percent from a baseline of0.786 lb/mmBtu.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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### 4.2 NO X 

### CONTROLS ANALYSIS AND IMPACTS EVALUATION
The next step 15 

### of this supplemental “top-down” BACT analysis is to evaluate the impacts of the hypothetical application of SCR alternatives’ NO X 

### emission controls. Energy, economic, and environmental impacts are to be considered in th e control technology evaluation. The purpose of the evaluation is to determine if there are any energy, eco nomic or environmental impacts that would eliminate the top control technologies from consideration.

This evaluation of the effectiveness of the hypotheti cally-applied SCR alternatives, as well as that of the other control technologies previously considered techni cally 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 cons idered to have been added to the previous NO X 

### BACT Analysis Study report submitted in October, 2006. The actual costs incurred and performance achieved for an installed advanced separated overfire air system, or firm price equipment quotes with performance guarantees for SNCR alternatives, that have been determined after the submittal of the 2006

NO X 

### BACT Analysis Study report, have not been used to adjust the control effec tiveness or cost impacts of the previously analyzed control a lternatives. The approach taken in this supplemental analysis uses installed capital costs estimated in calendar year 2009 escalated to project completion forecast in 2017 adjusted to calendar year 2006 basis for the hy pothetically-applied tail end SCR and low-dust SCR technology cases that have been added to the list of alternatives previously evaluated.



### 4.2.1 NO X 

### CONTROL ECONOMIC IMPACTS FOR MRY STATION UNIT 2
An evaluation was performed to determine the various cost impacts of installing previously-analyzed

feasible NO X 

### control alternatives and hypothetical applica tion of low-dust and tail end SCR technologies on Milton R. Young Unit 2. This evaluation includes estimated:

• Capital costs;

• Fixed and variable operating and maintenance costs; and

• Levelized total annual costs to engineer, design, procure, construct, install, st artup, test, and place into commercial operation the particular control technology. The results of this evaluation are summarized in Tables 4-3 through 4-11.

15 Step 4 per the NSR Manual, Ibid Reference 2, October 1990.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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### 4.2.1.1 CAP ITAL COST ESTIMATES FOR NO X 

### CONTROL ALTERNATIVES The range of estimated capital costs to implement some of the various NO X 

### control technologies were derived from unit output capital cost factors ($/kW) p ublished in technical papers discussing those control technologies. For MRY Station Unit 2, for the cases i nvolving the use of advanced separated overfire air and SNCR alternatives, preliminary project cost estim ates using vendor budgetary cost information were developed and used in place of, or to adjust, the publ ished unit output cost factors. A discussion of the reburn alternatives’ estimated capital costs was included in the 2006 NO X 

### BACT Analysis Study report and has not been repeated here. These co st 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 co al-fired powerplants in the United States that could be used, with adjustments, to properly represent total installed costs that could be expected for MRYS Unit 2. For these alternatives, site-specific detailed pr eliminary (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 ou tput in megawatts) assumed for the installed capital

cost estimate basis of the NO X 

### control technologies evaluated was 477 MW g 

### for MRY Station Unit 2 16



### .

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

NO X 

### 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 cost s for the hypothetically-applied Unit 2 SCR (tail end or low-dust) system would be accounted for as if the SCR equipment were being provided for Unit 2 only. This is referred to as the “stand alone” (SA) case, and all tables showing those costs are identified with that
suffix. In the other case, it was assumed that the re trofit of hypothetically-applied SCR systems was being
done for both Unit 1 and Unit 2, and there are some com ponents that could be shared between the two units. This is referred to as the “shared facilities” (SF) case, and all tables showing those costs are identified with

that suffix.

16 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 390.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 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 su ch technologies on each individual unit at MRYS independent of what may be determined or assumed for ot her units at this facility or similar units at other facilities. The “shared facilities” estimated total proj ect 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 w ith the shared facilities. In this “shared facilities” approach, a BACT would be performed more in th e 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 t echnologies as BACT. Therefore, each unit should be treated as a separate “stand alone” case. Although th e authors believe the “stand alone “case is the proper approach to use, information for both cases has been provided.



### TABLE 4-3SA – Unit Capi tal Cost Factors of NO X 

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

Alt. Label (1) NO X Control Alternative Range (2) ($/kW) Single Point Unit Capital Cost Factor (3) , ($/kW)

MRYS Unit 2 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) (4) 714 (4),(5)

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

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

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

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

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

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

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

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

(1) - Alternative designation has been assigned from highest to lowest uni t NOx emission rate. (2) - Unit capital cost factors ($/kW) of these individual technologi es combined by simple addition. Actual installed costs may differ from this due to positive or negativ e synergistic effects. Range based on published values or vendor proposals. (3) - Single point cost factor is best estimat e for determination of total capital cost for a particular technology or combination, assuming maximum unit capacity is ba sed on EPA’s nameplate rating. Singl e point cost figures in 2006 dollars. (4) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install these technologies on Unit 2 at Milton R. Y oung Station. The single point unit capital cost factor shown for a hypothetically-applied SCR system is based on assumptions that known or expected reasons for technical

17 Ibid Reference 2, October 1990, Chapter B. Introduction page B1.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 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 applicat ion at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in response to comments by th e NDDH, EPA, DOJ and other parties, so this information fo r the hypothetical application of SCR alternatives is included for comparative pur poses only. See Section 4.2.1. 2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst afte r a specified number of hours of unit operation. Due to the site-specific nature of factors influenc ing cost, no comparable cost data rang es for these technologies exist in the literature. A cost range for conventional high-dust SCR te chnology published in the 2005 EPA Report “Multipollutant Emission Control Technology Options for Co al-fired Power Plants”, EPA-600/R-05/034 18 was $55 to $150/kW. Single point unit capital cost factors were derived from Burns & McDonnell internal database and cost estimates prepared specifically for MRYS Unit 2 in 2017 dollars co nverted to 2006$ as described in the text. (5) - The single point unit capital cost factor shown for the “advanced” version of SOFA de rived 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 f ound in available technical literature. See Appendix C2 of the October 2006 NO X BACT Analysis Study report for details 19

. (7) - NESCAUM 2005 Technical Paper 20 ; reburn alternatives on page 2-22, overfire ai r on page 2-23; posted at their website. See technical referenc es in Appendix A1 of the October 2006 NO X 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, resp ectively), 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 s ite-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 Report 21 , posted at their website. The single point unit capital cost factor for this alternative for increased PM collection capacity included in lignite reburn option is 75.5 $/kW. See technical references in Appendix A1 of the October 2006 BACT Analysis report for details.



### TABLE 4-3SF – Unit Capi tal Cost Factors of NO X 

### Control Alternatives for MRY Station Un it 2 – Shared Facilities SCR Projects

Alt. Label (1) NO X Control Alternative Range (2) ($/kW) Single Point Unit Capital Cost Factor (3) , ($/kW)

MRYS Unit 2 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) (4) 671 (4),(5)

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

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

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

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

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

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

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

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

18 See Reference number 6, March 2005, page 3-63.
19 See Reference number 3, October 2006, pages C2-3 and C2-7.
20 See Reference number 7, March 2005.
21 See Reference number 8, April 2005, page 3-9.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 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 technol ogies combined by simple addition. Actual installed costs may differ from this due to positive or ne gative synergistic effects. Range based on published values or vendor proposals. (3) - Single point cost factor is best estimat e for determination of total capital cost for a particular technology or combination, assuming maximum unit capacity is ba sed on EPA’s nameplate rating. Single point cost figures in 2006 dollars. (4) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install these technologies on Unit 2 at Milton R. Y oung 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 boile r are solvable. SCR technolog y is considered technically infeasible by Minnkota for applicat ion at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in response to comments by th e NDDH, EPA, DOJ and other parties, so this information fo r the hypothetical application of SCR alternatives is included for comparative pur poses only. See Section 4.2.1. 2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst afte r a specified number of hours of unit operation. Due to the site-specific nature of factors influenc ing cost, no comparable cost data rang es for these technologies exist in the literature. A cost range for conventional high-dust SCR te chnology published in the 2005 EPA Report “Multipollutant Emission Control Technology Options for Co al-fired Power Plants”, EPA-600/R-05/034 22 was $55 to $150/kW. Single point unit capital cost factors were derived from Burns & McDonnell internal database and cost estimates prepared specifically for MRYS Unit 2 in 2017 dollars co nverted to 2006$ as described in the text. (5) - The single point unit capital cost factor shown for the “advanced” version of SOFA de rived 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 f ound in available technical literature. See Appendix C2 of the October 2006 NO X BACT Analysis Study report for details 23

. (7) - NESCAUM 2005 Technical Paper 24 ; reburn alternatives on page 2-22, overfire ai r on page 2-23; posted at their website. See technical referenc es in Appendix A1 of the October 2006 NO X 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, resp ectively), 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 s ite-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 Report 25 , posted at their website. The single point unit capital cost factor for this alternative for increased PM collection capacity included in lignite reburn option is 75.5 $/kW. See technical references in Appendix A1 of the October 2006 BACT Analysis report for details.



### 4.2.1.1.1 CAPITAL COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF SCR NO X 

### CONTROL ALTERNATIVES There is no available information on recently-completed similar tail-end or low-dust SCR projects on coalfired powerplants in the United States that could be used , with adjustments, to represent total installed costs that could be expected for MRYS Unit 2. Site-speci fic needs and challenges identified for applying tail end and low-dust SCR technologies to Milton R. Young Station Unit 2 significantly influence the capital cost estimate for variations of these hypothetical alternativ es. Furthermore, the “EPA Air Pollution Control Cost Manual” is not applicable for use in estimating control equipment cost s for these hypothetical applications of SCR technology cases, as the EPA Control Cost Manual states:

22 See Reference number 6, March 2005, page 3-63.
23 See Reference number 3, October 2006, pages C2-3 and C2-7.
24 See Reference number 7, March 2005.
25 See Reference number 8, April 2005, page 3-9.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 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 sy stems due to flue gas reheating requirements.” 26



### This requirement for flue gas reheating also appli es to the hypothetical application of low-dust SCR to MRYS, due to the cold-side arrangement (downstream of the electrostatic precipitator) instead of a hot-side

ESP assumed in the EPA Control Cost Manual. Therefor e, the equations in the EPA Control Cost Manual cannot be used for estimating either of the hypothe tical SCR configurations for which NDDH has requested economic analyses. Thus it was necessary to pr epare independent site-specific cost estimates.

The installed capital costs for hypothetical applica tion 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 hypot hetically-applied low-dust and tail end SCR designs for MRYS Unit 2 assume two reactor / gas reheat systems in stalled in parallel, each connecting to one of the two existing wet lime flue gas desulfurization absorber s also arranged in parallel configuration. Each alternative includes flue gas reheat equipment that is typical for these applications but not required for conventional high-dust/hot side SCRs. The estimated flue gas volume at a gross boiler heat input and oxygen content corresponding to unit gross nameplat e output capacity determined the size of the two hypothetically-applied SCR reactors for these cases. St ructures, foundations, ductwork, balance of plant equipment and materials were quantified and include d with the hypothetically-applied SCR equipment,

which were factored for installation costs. Escalati on of project costs, including equipment, materials, engineering and labor costs, is included, along with inte rest 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 implemen tation of these hypothetica lly-applied alternatives. Total project costs were considered to be a future valu e 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 NO X 

### BACT Analysis Study report. A ratio of regional construction cost indices for public utility construction costs betw een 2006 and 2009 was used to adjust the 2009 total estimated project costs to a 2006 calendar year basis for each of the hypothetically-applied SCR alternatives.

26 See Reference number 10, Section 4.2, Chapter 2, page 2-41, October 2000.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 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 NO X 

### 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 NO X 

### Control Alternatives - MRY Stati on Unit 2 - Stand Alone SCR Projects

Alt. Label (1) NOx Control Alternative Installed Capital Cost (2) $1,000 Annualized Capital Cost (3) $1,000 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) 340,733 (4) 29,707 (4)
T1 Hypothetical Tail End S CR w/ ASOFA – Scenario B (4) 340,733 (4) 29,707 (4)
L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 270,785 (4) 23,608 (4)
L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) 270,785 (4) 23,608 (4)

E SNCR w/ ASOFA 17,128 1,493

D Gas Reburn w/ ASOFA (5) 35,490 3,094 C Lignite Reburn w/ ASOFA (6) 81,167 7,077

B Fuel Lean Gas Reburn w/ ASOFA (5) 21,817 1,902
A Advanced SOFA (ASOFA) 10,008 873

Baseline 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 477 MWg unit capa city rating. All cost figures in 2006 dollars. See Table 4-5SA for presentation of installed capital costs determined for hypothetical a pplication of SCR alternatives. (3) - Annualized capital cost = Inst alled capital cost x 0.08718 a nnualized 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 inst all these technologies on Unit 2 at Milton R. Young Station. The installed capital cost shown for a hypothetically-applie d 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 es timates prepared specifically for MRYS Unit 2 in 2017 dollars converted to 2006$ as described in the text. SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and ot her parties, so this information for the hypothetical appli cation 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 na tural gas supply pipeline installed capital cost of $14,988,000 for CGR and $7,494,000 fo r FLGR; and annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR. See footnote number 8 under Table 4-3SA. (6) - Costs for increased PM collecti on capacity included in lig nite reburn option are $36,013,000 for installed capital cost, and $3,140,000/yr annualized capital cost.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-15 Burns & McDonnell 

### TABLE 4-4SF – Estimated Capital Costs for NO X 

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

Alt. Label (1) NOx Control Alternative Installed Capital Cost (2) $1,000 Annualized Capital Cost (3) $1,000 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) 320,279 (4) 27,923 (4)
T1 Hypothetical Tail End S CR w/ ASOFA – Scenario B (4) 320,279 (4) 27,923 (4)
L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 250,487 (4) 21,839 (4)
L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 250,487 (4) 21,839 (4)

E SNCR w/ ASOFA 17,128 1,493

D Gas Reburn w/ ASOFA (5) 35,490 3,094 C Lignite Reburn w/ ASOFA (6) 81,167 7,077

B Fuel Lean Gas Reburn w/ ASOFA (5) 21,817 1,902
A Advanced SOFA (ASOFA) 10,008 873

Baseline 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 477 MWg unit capa city rating. All cost figures in 2006 dollars. See Table 4-5SF for presentation of installed capital costs determined for hypothetical a pplication of SCR alternatives. (3) - Annualized capital cost = Inst alled capital cost x 0.08718 a nnualized 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 t echnologies on Unit 2 at Milton R. Young Station. The installed capital cost shown for a hypothetically-applied SCR system is base d 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 estimate s prepared specifically for MRYS Unit 2 in 2017 dollars converted to 2006$ as described in the text. SCR techno logy is considered technica lly infeasible by Minnkota for application at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this inform ation for the hypothetical application of SCR alternatives is included for compara tive purposes only. See Sectio n 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 na tural gas supply pipeline installed capital cost of $14,988,000 for CGR and $7,494,000 fo r FLGR; and annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR. See footnote number 8 under Table 4-3SF. (6) - Costs for increased PM collecti on capacity included in lig nite reburn option are $36,013,000 for installed capital cost, and $3,140,000/yr annualized capital cost.



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

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

The estimated installed capital costs for the hypothetical application of tail end or low-dust SCR system retrofits on MRYS Unit 2 include the following equipment and components:Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-16 Burns & McDonnell 

### • Two SCR reactors utilizing a “3 +1” arrangement of catalyst layers, in which three layers of catalyst are initially installed, and space for in stallation 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 regenerativ e 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 ma intain 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 unl oading and preparation of liquid urea solution

• Circulation pumps and piping for urea solution

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

• Ammonia gas dilution/combustion air fans and burne rs 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 plan t facilities will be required for the reagent system and new induced draft booster fan power consumption. B ased 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 successf ul completion of extensive pilot-scale slipstreamSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-17 Burns & McDonnell 

### testing, and more detailed plant la yout and equipment design than has been performed as part of this supplemental update to the October 2006 NO X 

### BACT Analysis Study report.

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

described in the initial NO X 

### 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 Alternati ves - MRY Station Unit 2 - Stand Alone SCR Projects

Alt. Label (1) Hypothetical SCR Alternative (2) Estimated BMcD Study Total Project Cost (3)
, 2017$ x 1000 Estimated BMcD Study

Modified TP Cost (4)
, 2009$ x 1000 Estimated BMcD Study

Adjusted TP Cost (5)
, 2006$ x 1000 T2, T1 Tail End SCR 436,346 358,129 325,240 Urea preparation and storage, building, and equipment (6) _ 6,040 (6) 5,485 (6)

ASOFA _ _ 10,008
T2, T1 TOTAL _ _ 340,733 (6)

L2, L1 Low-Dust SCR 342,502 281,107 255,292 Urea preparation and storage, building, and equipment _ 6,040 (6) 5,485 (6)

ASOFA _ _ 10,008
L2, L1 TOTAL _ _ 270,785 (6)

(1) All SCR alternatives are assumed to have the same SCR outlet NOx emission rate. (2) The inclusion of tail end and low-dust SCR te chnologies in this table does not constitute agreement that it is technically feas ible to install these technologies on Unit 2 at Milton R. Young Station. (3) The Total Project Cost shown fo r 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 be low. SCR technology is considered techni cally infeasible by Minnkota for appli cation at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent subm ittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only Does not include installed capital cost for ASOF A, as shown in Table 4-4SA. (4) Modified Total Project Costs are converted from 2017$ to 2009$ as described in the text, except as described in footnote 6 below. Present Value factor (discounted from future value) is 0.82075. (5) Adjusted Total Project Costs are converted from 2009$ to 2006$ as described in the text. Handy-Whitman Index of Public Utility Construction Costs ratio is 0.908. (6) Urea preparation and storage, building, and equipment installe d capital costs were estimated separately in 2009$, and then adjusted using the Handy-Whitman cost ra tio of 0.908 to get 2006$. The TOTAL numbers above are the sum of the Adjusted Total Project Cost; urea preparation and st orage, building, and equipment; and total Installed Capital Costs (TICC) for ASOFA alternative = estimated TICC for the hypothetical ly-applied SCR alternatives in Table 4-4SA.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-18 Burns & McDonnell 

### TABLE 4-5SF – Estimated Capital Costs for Hypothetically-Applied SCR Alternati ves - MRY Station Unit 2 - Shared Facilities SCR Projects

Alt. Label (1) Hypothetical SCR Alternative (2) Estimated BMcD Study Total Project Cost (3)
, 2017$ x 1000 Estimated BMcD Study

Modified TP Cost (4)
, 2009$ x 1000 Estimated BMcD Study

Adjusted TP Cost (5),(6)
, 2006$ x 1000 T2, T1 Tail End SCR 411,063 337,379 306,395 Urea preparation and storage, building, and equipment (6) _ 4,268 (6) 3,876 (6)

ASOFA _ _ 10,008

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

L2, L1 Low-Dust SCR 317,429 260,529 236,603 Urea preparation and storage, building, and equipment _ 4,268 (6) 3,876 (6)

ASOFA _ _ 10,008

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

(1) All SCR alternatives are assumed to have the same SCR outlet NOx emission rate. (2) The inclusion of tail end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 2 at Milton R. Young Station. (3) The Total Project Cost shown for each hypothetically-applied SCR system was estimated by Burns & McDonnell based on scope assumptions for installation of the SCR equipment on this boiler as described in the text, except as described in footnot e 6 below. SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NO X BACT Analysis Study report and subs equent submittals in response to comme nts by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. Does not include installed capital cost for ASOFA, as shown in Table 4-4SF. (4) Modified Total Project Costs are converted from 2017$ to 2009$ as described in the text, except as described in footnote 6 below. Present Value factor (discounted from future value) is 0.82075. (5) Adjusted Total Project Costs are converted from 2009$ to 2006$ as described in the text. Handy-Whitman Index of Public Utility Construction Costs ratio is 0.908. (6) Urea preparation and storage, building, and equipment installe d capital costs were estimated separately in 2009$, and then adjusted using the Handy-Whitman cost ra tio of 0.908 to get 2006$. The TOTAL numbers above are the sum of the Adjusted Total Project Cost; urea preparation and st orage, building, and equipment; and total Installed Capital Costs (TICC) for ASOFA alternative = estimated TICC for the hypothetical ly-applied SCR alternatives in Table 4-4SF.



### 4.2.1.2 O&M COST ESTIMATES FOR NO X 

### CONTROL ALTERNATIVES Operational costs to implement the hypothetical appli cation of SCR alternatives and previously-analyzed

feasible NO X 

### control alternatives for Milton R. Young Unit 2 were estimated using preliminary conceptual designs and budgetary ven dor quotes in place of, or to adjust, th e OAQPS cost factors established in the EPA’s Air Pollution Control Cost Manual (OAQPS) for SNCR 27 

### and SCR 28 

### , and using other costs from

27 See Reference number 9, October 2000.
28 See Reference number 10, October 2000.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-19 Burns & McDonnell 

### published technical papers discussing those control t echnologies. Maintenance costs were estimated as percentages of installed capital costs, with additio nal catalyst replacement costs using budgetary vendor quotes based on preliminary conceptual designs and expected design life.

Fixed and variable operating and maintenan ce costs considered and included in each NO X 

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

• Auxiliary electrical power consumption (megaw att-hours) and incremental purchased power unit costs for operating the additional control equipment;

• Natural gas consumption and unit cost for hypothe tical application of SCR alternatives’ flue gas reheating and urea-to-ammonia thermal conversion sy stems and feasible fuel reburn alternatives;

• Reagent consumption and reagent unit cost for h ypothetical application of SCR alternatives and
feasible SNCR alternatives;

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

• Catalyst removal and replacement for hypot hetical 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 main tenance 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 e xpected to result from loss of unit availability, i.e., outages attributable to the control opti on which reduce annual net electrical generation

available for distribution.

For economic evaluation purposes, a 12-month rolling av erage running plant capacity factor of 95.2 percent (based on a historic (demonstrated) sust ainable unit output capacity of 462 MW g 

### ) combined with a 12- month rolling average availability (uptime) of 8,229 op erating hours (93.9 percent of 8760 hours per year) resulting in an equivalent annual average unit capac ity factor of 89.5% was assumed for Unit 2’s precontrol baseline annual operation. A 12-month rolling average heat input rate of 4,885 mmBtu/hr and a 12- month rolling average NO X 

### emission rate of 0.786 lb/mmBtu from pre-control maximum rolling 12 month summation of nitrogen oxides mass emissions were a ssumed for calculating equivalent annual average

control and cost-effectiveness for MRY Station Unit 2.

Tables 4-6SA and 4-6SF show the estimated annual op erating and maintenance costs and levelized annual O&M cost values for the hypothetically-applied SCR a lternative cases and the highest-performing form ofSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-20 Burns & McDonnell 

### previously-evaluated feasible NO X 

### emission reduction technologies. Th ese are listed in order of control effectiveness, with the highest ranked options at th e top. The cost methodology summarized in Appendix C3 of the 2006 NOx BACT Analysis Study report provi des more details for the levelized annual O&M cost

calculations and cost factors for the previously-analyzed feasible NO X 

### control alternatives 29



### .



### TABLE 4-6SA – Estimated O&M Costs for NO X 

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

Alt. Label (1) NOx Control Alternative Annual O&M Cost (2) $1,000 Levelized Annual O&M Cost (2),(3)

$1,000 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) 31,512 39,350 T1 Hypothetical Tail End S CR w/ ASOFA – Scenario B (4) 55,345 69,111 L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 29,048 36,273 L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) 52,424 65,463
E SNCR w/ ASOFA 8,108 10,125
D Gas Reburn w/ ASOFA 48,688 60,798 C Lignite Reburn w/ ASOFA (5) 9,929 12,398
B FLGR w/ ASOFA 21,954 27,415
A Advanced SOFA (ASOFA) 2,805 3,503

Baseline 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Annual operating and maintenance cost for a particul ar technology or combination is compared to unit baseline operation at an average unit output (462 MW g) and assumes a 94.7% average annual availability, which is highest consecutive 12-months of operati on from 2001-2005. All cost figures in 2006 dollars. (3) - Levelized annual O&M cost = Annual O&M co st x 1.24873 annualized O&M cost factor. (4) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install thes e technologies on Unit 2 at Milton R. Young Sta tion. The estimated annual O&M cost shown for a hypothetically-applied SCR syst em is based on assumptions that known or ex pected reasons for te chnical infeasibility for installation and operation and maintenance of the SCR equipm ent on this boiler are solvable. Costs are derived from Burns & McDonnell internal database an d cost estimate specific to MRYS Un it 2 in 2017 dollars. SCR technology is considered technically infeasible by Minnkota for applicat ion at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submitt als 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 assu mes replacement of SCR catalyst after a specified number of hours of unit operation. (5) - Costs for increased PM collection cap acity included in lignite reburn option are $3,358,000/yr for annual O&M cost, and $4,194,000/yr annualized O&M cost.

29 Ibid Reference number 3, October 2006, pages C3-1 through C3-11.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-21 Burns & McDonnell 

### TABLE 4-6SF – Estimated O&M Costs for NO X 

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

Alt. Label (1) NOx Control Alternative Annual O&M Cost (2) $1,000 Levelized Annual O&M Cost (2),(3)

$1,000 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) 30,898 38,583 T1 Hypothetical Tail End S CR w/ ASOFA – Scenario B (4) 54,731 68,345 L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 28,439 35,512 L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) 51,815 64,703
E SNCR w/ ASOFA 8,108 10,125
D Gas Reburn w/ ASOFA 48,688 60,798 C Lignite Reburn w/ ASOFA (5) 9,929 12,398
B FLGR w/ ASOFA 21,954 27,415
A Advanced SOFA (ASOFA) 2,805 3,503

Baseline 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Annual operating and maintenance cost for a particul ar technology or combination is compared to unit baseline operation at an average unit output (462 MW g) and assumes a 94.7% average annual availability, which is highest consecutive 12-months of operati on from 2001-2005. All cost figures in 2006 dollars. (3) - Levelized annual O&M cost = Annual O&M co st x 1.24873 annualized O&M cost factor. (4) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install thes e technologies on Unit 2 at Milton R. Young Sta tion. The estimated annual O&M cost shown for a hypothetically-applied SCR syst em is based on assumptions that known or ex pected reasons for te chnical infeasibility for installation and operation and maintenance of the SCR equipm ent on this boiler are solvable. Costs are derived from Burns & McDonnell internal database an d cost estimate specific to MRYS Un it 2 in 2017 dollars. SCR technology is considered technically infeasible by Minnkota for applicat ion at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submitt als 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 assu mes replacement of SCR catalyst after a specified number of hours of unit operation. (5) - Costs for increased PM collection cap acity included in lignite reburn option are $3,358,000/yr for annual O&M cost, and $4,194,000/yr annualized O&M cost.



### 4.2.1.2.1 O&M COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF SCR NO X 

### 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 opera tion of MRYS Unit 2. The system uses an amine reagent in the form of concentrated aqueous urea solution, which is thermally converted to gaseous ammonia, carbon dioxide, and water vapor. The estimat ed unit cost of this urea was assumed to average $379/ton (delivered to the plant site via truck-tanke r trailers; unit pricing based on 50% concentration asSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-22 Burns & McDonnell 

### established for the 2006 NO X 

### BACT Analysis Study report). Cons umption of urea converted to ammonia reagent was based upon recent equipment vendor budgeta ry proposals and SCR consultant inputs.

For the hypothetically-applied SCR cases, using the ex isting induced draft fans is not expected to significantly change the overall fan horsepower demand on those fans’ electric motors. There will be new plant electrical power demand due to new induced dr aft booster fans required to overcome the estimated additional flue gas pressure drop resulting from reactor, ductwork, and gas-to-gas heat exchanger equipment assumed for the hypothetically-applied SCR systems. The additional auxiliary electric power demand for the hypothetically-applied tail end SCR systems was calculated to be 14.9 MW, using estimated annual average electrical loads of the booster fan, direct flue gas reheat burner combustion air fans, urea-toammonia conversion dilution/combustion air fans, and SCR sootblower and service air compressor equipment based on preliminary equipment vendor budgetary proposals developed from Burns & McDonnell ductwork sizing and designs. Estimated annual average electrical power demands for hypothetically-applied low-dust SCR systems were calcul ated to be 12.4 MW. Replacement of electrical power resulting from these reductions in net unit electrical output was included as a cost, assuming $35 per megawatt-hour.

Hypothetically-applied tail end and low-dust SCR equipment requiring annual maintenance includes booster fans, gas-to-gas heat exchangers, flue gas re heat 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 s cenario was based on scheduled additions and/or replacement of the exposed catalyst after a certain num ber of hours of operation, repeated throughout the 20 year operating span considered in the analysis. The current installed unit cost of replacement catalyst assumed for the hypothetical application of full-time tail end or low-dust SCR alternatives is $7,500 per

cubic meter in 2006 dollars. The basis for devel opment 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 Eur opean 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 withou t results following successful extensive pilot-scaleSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-23 Burns & McDonnell 

### slipstream testing that confirm the deactivation and fouling rates. According to these catalyst suppliers, there is no SCR operating experience in the world found to be directly comparable to the hypotheticallyapplied tail end and low-dust SCR cases on North Dakota li gnite-fired cyclone boilers being evaluated. Thus they were unable to offer a guaranteed catalys t replacement schedule based on their experience.

Based on information obtained in discussions with th e 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 develope d until extensive pilot testing had b een completed. This led Burns & McDonnell to develop two hypothetica lly-applied SCR catalyst replacement scenarios to bracket possible

outcomes.

Scenario A assumed a catalyst replacement schedule of 16,000 hours. Specifically for MRYS Unit 2, this scenario is based on the replacement of one catalyst layer in each reactor every 16,000 operating hours.

Scenario B assumed that the fouling of the catalyst would be severe, and that it would be necessary for Minnkota to perform catalyst maintenance at each sche duled boiler cleaning outage. The current schedule of boiler cleaning outages on Unit 2 is four times per year . Therefore, Scenario B for Unit 2 is based on the replacement of one catalyst layer in each reactor at each boiler cleaning outage. This means that each catalyst layer in the four layer SCR reactor is expo sed to flue gas during approximately 12 months of operation and then is replaced. By assuming that cat alyst 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 frequenc y of catalysts replacement would need to be for a hypothetically-applied tail-end or low dust SCR syst em operating on a cyclone-fired boiler burning North Dakota lignite, but the two scenarios described above ar e the catalyst replacement numbers assumed for this comparative economic analysis.

SCR catalyst replacements are additive to the genera l annual hypothetically-appl ied low-dust and tail end SCR equipment maintenance. Catalyst replacement costs are based on catalyst vendor quotation of volume of catalyst, estimated to be three layers initially (top, middle-upper and middle-lower) at 256 cubic meters per layer per reactor for two reactors in parallel. A four th (bottom) layer at 342 cubic meters is expected toSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-24 Burns & McDonnell 

### be required after initial operation of hypothetically-a pplied full-time tail end or low-dust SCR alternatives, as part of the catalyst replacement program. Catalyst replacement costs for the hypothetical application of

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

Annual unit operating time will be reduced as a result of the expected outages and maintenance of the hypothetically-applied SCR equipment, including catal yst cleaning and management practices. Additional outage time of 206 hours per year was estimated to be attr ibutable to the hypothetical application of tail end SCR Scenario A alternative (assuming 16,000 hour catalys t life), and 1,235 hours per year for the Scenario B TESCR case (assuming four layers are replaced every year) over and above the outage time assumed for ASOFA impacts. Additional outage time of 247 hours per year was estimated to be attributable to the hypothetical application of low-dust SCR Scenario A alte rnative, and 1,235 hours per year for the Scenario B LDSCR case over and above outage time assumed for ASOFA impacts. The expected loss of electrical power generation from these reductions in net output was included as a cost, assuming $35 per megawatt-hour for replacement power.

Table C.4-1 provides the estimated unit availability an d corresponding operating time and outage time due to the four hypothetically-applied S CR technology cases, along with the ASOFA and baseline numbers from the referenced Appendix C3 of the initial NO X 

### BACT Analysis Study report 30



### .

30 Ibid Reference number 3, October 2006, pages C3-1 through C3-11.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-25 Burns & McDonnell 

### TABLE C.4-1 – Expected Availability Reductions for MRYS Unit 2 NO X 

### Controls

Estimated Annual Average Unit Operating Time

Alt. 1 NOx Control Alternative Unit Availability 2 Unit Operating

Time 3
, hrs/yr Unit Outage Time 4
, hrs/yr Unit Operating Time Reduction 5
, hrs/yr

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (6) 0.895 7,842 918 387

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (6) 0.778 6,813 1,947 1,416

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (6) 0.890 7,801 959 428

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (6) 0.778 6,813 1,947 1,416
E SNCR w/ ASOFA 0.909 7,965 795 264
D Gas Reburn w/ ASOFA 0.919 8,048 712 181
C Coal Reburn w/ ASOFA 0.904 7,916 844 313
B FLGR w/ ASOFA 0.919 8,048 712 181
A Advanced SOFA (ASOFA) 0.919 8,048 712 181
Baseline 0.939 8,229 531 0
(1) – Alternative number has been pr eviously assigned from least removal to highest removal percentage. (2) – 12-month baseline availa bility is assumed at 93.9 percent. These values reflect estimated amounts of negative reliability impact expected from the implementation of the individual NOx control technology. (3) – Annual operating time is annual average availability multiplied by 8760 hrs/yr of possible uptime. (4) – Annual outage time is 8760 hrs/yr possible opera ting time minus estimated a nnual operating time. (5) – Annual operating time reduction result ing from the implementation of the indi vidual NOx control technique is the difference between the baseline and e xpected annual outage times. (6) – The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install thes e technologies on Unit 2 at Milton R. Young Statio n. 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 th e SCR equipment on this boiler are solvable. SCR technology is considered technicall y infeasible by Minnkota for applic ation at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent s ubmittals in response to comments by the NDDH, EPA, DOJ and other parties,, so this information for the hypothetical application of SCR alte rnatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assume replacement of SCR catalyst after a specified number of hours of unit operation.



### Table C.4-2 includes estimated equivalent averag e annual unit running plant capacity ratios and unit generation reductions due to th e four hypothetically-applied SCR cases, along with the ASOFA and

baseline numbers from the referenc ed Appendix C3 of the initial NO X 

### BACT Analysis Study report 31



### . These numbers assume the reduction in annual plant out put is a combination of a reduction of annual operating time and capacity reductions associ ated with the control alternatives.

31 Ibid Reference number 3, October 2006, pages C3-1 through C3-11.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-26 Burns & McDonnell 

### TABLE C.4-2 – Expected Capacity Reductions for MRYS Unit 2 NO X 

### Controls

Estimated Annual Average Unit Electrical Power Generation Reduction from Operating Time Reduction

Alt. Label (1) NOx Control Alternative Unit Running Plant Capacity Ratio (2) Unit Generation Reduction (3) kW-hrs/yr Unit Generation Reduction Cost (4)
, 1000$/yr

T2 Hypothetical Tail End SCR w/

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

T1 Hypothetical Tail End SCR w/

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

L2 Hypothetical Low-Dust SCR w/

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

L1 Hypothetical Low-Dust SCR w/

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

E SNCR w/ ASOFA 0.951 110,176,095 3,856
D Gas Reburn w/ ASOFA 0.943 81,416,590 2,850 C Lignite Reburn w/ ASOFA 0.948 130,375,506 4,563
B FLGR w/ ASOFA 0.949 81,910,024 2,867
A Advanced SOFA (ASOFA) 0.952 75,859,855 2,655

Baseline 0.952 0 0
(1) - Alternative designation has been previously assigned from least removal to high est removal percentage. (2) - 12-month baseline running plant capacity ratio is assumed at 95.2 percent (= 440/462). These values reflect estimated amounts of negative annual output capaci ty impact expected from the implemen tation of the individual NOx control technique. Used only for calculation of annual power usage in Table C.4-3. (3) - Annual electricity generation reduction is annual unit operating time reduction multiplied by the 12-month average gross output of 440 MW. (4) - Annual electricity gene ration reduction cost is the annual electricity generation reduction (kW-hrs/yr) resulting from the implementation of the individual NOx cont rol technique multiplied by the incremental value of electricity generation, assumed to be $35.00/MW-hr. A ll cost figures in 2006 dollars. (5) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install thes e technologies on Unit 2 at Milton R. Young St ation. The estimated annual unit running plant capacity ratios shown for hypothetically-a pplied SCR systems are based on assump tions 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 techni cally infeasible by Minnkota for appli cation at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation.



### Table C.4-3 includes estimated unit gross and net el ectrical power demands (kilowatts) and annual usage (kW-hrs per year) used to calculate unit generation re ductions and replacement electrical power costs due to the four hypothetically-applied SCR cases, along with the ASOFA numbers from the referenced AppendixSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-27 Burns & McDonnell 

### C3 of the initial NO X 

### BACT Analysis Study report 32 

### . These numbers assume that the reductions of annual operating time and capacity associated with th e control alternatives are also applied.



### TABLE C.4-3 – Expected Auxiliary Electrical Power Demand Changes for MRYS Unit 2 NO X 

### Controls

Estimated Annual Average APC NOx Equipment

Auxiliary Electrical Power Demand and Usage

Alt. Label (1) NOx Control Alternative Gross Demand (2) kW Credit (3) kW Total Net Demand (4) kW Power Usage (5) kW-hrs/yr Power Usage Cost (6)
, 1000$/yr

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (7) 14,925 0 14,925 108,122,807 3,784

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (7) 14,925 0 14,925 93,941,913 3,288

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (7) 12,389 0 12,389 89,740,378 3,141

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (7) 12,389 0 12,389 78,381,807 2,743 E SNCR w/ ASOFA 133 0 133 1,008,774 35
D Gas Reburn w/ ASOFA 1 (228) (227) (1,724,428) (60) C Lignite Reburn w/ ASOFA 8,342 (448) 7,894 59,217,554 2,073
B FLGR w/ ASOFA 1 (125) (124) (949,051) (33)
A Advanced SOFA (ASOFA) 1 0 1 7,664 0.3

(1) - Alternative designation has been previously assigned from least removal to high est removal percentage. (2) - The APC NOx equipment gross auxiliary electrical power dema nd of alternatives is the sum of the demand for individual technologies combined by simple addition. Actual power demands may differ from this due to positive or negative synergistic effects. Coal reburn includes 2,484 kW for feed preparation and conveying equipment demand plus 5,857 kW for the COHPAC system addition for PM control. (3) - The APC NOx equipment auxiliary electrical power demand credit of coal reburn alternatives is the estimated result of lower cyclone coal preparation and feeder power demand due to lower boiler cyclone coal equipment loading. Actual power demands may differ from this due to accuracy of esti mates 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 electr ical power demand electricity usage in kW-hrs/yr for these alternatives is the net power demand mu ltiplied 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 S CR technologies in this table does not cons titute agreement that it is technically feasible to install these technologies on Unit 2 at Milt on R. Young Station. The estimated power demand shown for hypothetically-applied SCR sy stems are based on Burns & McDonnell estim ates developed from preliminary equipment and ductwork sizing and designs with vendor budgetary proposals. SCR technology is consider ed technically infeasible by Minnkota for application at MRYS per the October 2006 NO X BACT Analysis Study repor t and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this info rmation 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 replacemen t of SCR catalyst after a specifie d number of hours of unit operation.

32 Ibid Reference number 3, October 2006, pages C3-1 through C3-11.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 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 ge neration reductions and replacement electrical power costs due to the four hypothetically-applied SCR cases, along with the ASOFA numbers from the referenced Appendix C3 of the initial NO X 

### BACT Analysis Study report 33 

### . 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 El ectrical Power Demand and Generation Reduction Cost Changes for MRY Unit 2 NO X 

### Controls

Estimated Annual Change in Unit Generation Due to APC NOx Equipment Auxiliary Power Electri city Demand and Generation Reduction

Alt. Label (1) NOx Control Alternative APC Electrical

Power Usage (2) kW-hrs/yr Unit Generation Reduction (3) kW-hrs/yr Total Unit Electrical Power Generation

Change (4) kW-hrs/yr Total Unit Electrical Power Generation Change Cost (5) 1000$/yr

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (6) 108,122,807 170,167,448 278,290,255 9,740

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (6) 93,941,913 622,740,448 716,682,361 25,084

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (6) 89,740,378 188,270,368 278,010,746 9,730

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (6) 78,381,807 622,740,448 701,122,255 24,539 E SNCR w/ ASOFA 1,008,774 110,176,095 111,184,869 3,891
D Gas Reburn w/ ASOFA (1,724,428) 81,416,590 79,692,162 2,789 C Lignite Reburn w/ ASOFA 59,217,554 130,375,506 189,593,059 6,636
B FLGR w/ ASOFA (949,051) 81,910,024 80,960,972 2,834
A Advanced SOFA (ASOFA) 7,664 75,859,855 75,867,520 2,655
(1) - Alternative designation has been previously assigned from least removal to high est removal percentage. (2) - The annual change in APC NOx equipment auxiliary electr ical power demand electricity usage in kW-hrs/yr for these alternatives is the net power demand mu ltiplied by the estimated annual operating time and running plant capacity ratio which reflects the adjustment for any expected availability and capacity impacts from the implementation of the control technique. (3) - Annual electricity generation reduction is annual operating time reduction multiplied by the 12-month average gross output of 440 MW. (4) - The total unit electrical power generation change is the sum of the annual change in APC NOx equipment auxiliary electrical power demand elec tricity usage plus the annua l electricity generation re duction resulting from the implementation of the individua l 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 replacemen t electricity generation, assumed to be $35.00/ MW-hr. All cost figures in 2006 dollars.

33 Ibid Reference number 2, October 2006, pages C3-1 through C3-11.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-29 Burns & McDonnell

(6) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install these technologies on Unit 2 at Milt on R. Young Station. The estimated power demand shown for hypothetically-applied SCR sy stems are based on Burns & McDonnell estim ates developed from preliminary equipment and ductwork sizing and designs with vendor budgetary proposals. SCR technology is consider ed technically infeasible by Minnkota for application at MRYS per the October 2006 NO X BACT Analysis Study repor t and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this info rmation 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 replacemen t of SCR catalyst after a specifie d number of hours of unit operation.



### 4.2.1.3 L EVELIZED TOTAL ANNUAL COST ESTIMATES FOR MRY STATION NO X 

### CONTROLS A comparison of the control versus cost-effectiv eness of two hypothetical SCR cases and previouslyanalyzed feasible NO X 

### control alternatives on Milton R. Young Un it 2 was made. This is summarized as shown in Tables 4-7SA and 4-7SF, Figures 4-1SA and 4-1SF, and Figures 4-2SA and 4-2SF for MRY

Station Unit 2.



### TABLE 4-7SA – Estimated Annual Emissions and Levelized Total Annual Cost for NO X 

### Control Alternatives - MRY Stati on Unit 2 - Stand Alone SCR Projects

Alt. Label (1) NOx Control Alternative Annual NOx Emissions (2)

Tons/yr Annual NOx Emissions Reduction (3)

Tons/yr Levelized Total Annual Cost (4) $1,000 Average Control Cost (5) $/ton

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (6) 936 14,857 69,057 4,648

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (6) 813 14,980 98,818 6,597

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (6) 931 14,862 59,881 4,029

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (6) 813 14,980 89,072 5,946 E SNCR w/ ASOFA 6,421 9,372 11,618 1,240
D Gas Reburn w/ ASOFA 6,882 8,910 63,892 (7) 7,171 C Lignite Reburn w/ ASOFA 6,964 8,829 19,475 (8) 2,206
B FLGR w/ ASOFA 8,490 7,303 29,317 (7) 4,014
A Advanced SOFA (ASOFA) 9,621 6,172 4,376 709
Baseline 15,793 0 0

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Estimated annual emission tons assume an annual unit uptime availability factor specific to each alternative; 15,793 (= 0.939*8760*3,839/2000) was assumed for the baseline case. (3) - Estimated annual tons of emission reduc tion is the difference between annual ba seline 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 ar e calculated from unit emissi on rates, control percentage,Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-30 Burns & McDonnell hourly heat input, and annual hrs/yr operation compared to pre-control baseline emissions based on annual operation at baseline pre-control NOx emission rate. (5) - Average Control Cost Effectiveness ($/ton) is the Leveli zed Total Annual Cost ($/yr) divided by Annual Emission Reduction (tons/yr). All cost figures in 2006 dollars. (6) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install these t echnologies on Unit 2 at Milton R. Young Sta tion. The estimated annual NOx removal and LTAC shown for a hypothetically -applied SCR system is based on assump tions that known or ex pected reasons for technical infeasibility for installation of the SCR equipment on this bo iler are unsolvable. Costs are derived from Burns & McDonnell internal database and co st estimate specifically for MRYS Unit 2 in 2006 dollars. SCR technology is considered technically infeasible by Minnkota for applicat ion at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent s ubmittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application of SCR alternatives is includ ed for comparative purposes onl y. See Section 4.2.1.2.1 for details of Scenario A and Scenario B th at 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 suppl y pipeline annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR. See footnote number 8 under Table 4-3SA. (8) - LTAC for increased PM collection capacity included in ligni te reburn option are approximate ly $3,140,000 for annualized capital cost plus $4,194,000/yr for annualized O&M cost, for a LTAC subtotal of $7,333,000/yr.



### TABLE 4-7SF – Estimated Annual Emissi ons and Levelized Total Annual Cost for NO X 

### Control Alternatives - MRY Station Unit 2 - Shared Facilities SCR Projects

Alt. Label (1) NOx Control Alternative Annual NOx Emissions (2)

Tons/yr Annual NOx Emissions Reduction (3)

Tons/yr Levelized Total Annual Cost (4) $1,000 Average Control Cost (5) $/ton

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (6) 936 14,857 66,506 4,477

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (6) 813 14,980 96,268 6,427

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (6) 931 14,862 57,351 3,859

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (6) 813 14,980 86,542 5,777 E SNCR w/ ASOFA 6,421 9,372 11,618 1,240
D Gas Reburn w/ ASOFA 6,882 8,910 63,892 (7) 7,171 C Lignite Reburn w/ ASOFA 6,964 8,829 19,475 (8) 2,206
B FLGR w/ ASOFA 8,490 7,303 29,317 (7) 4,014
A Advanced SOFA (ASOFA) 9,621 6,172 4,376 709
Baseline 15,793 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Estimated annual emission tons assume an annual unit uptime availability factor specific to each alternative; 15,793 (= 0.939*8760*3,839/2000) was assumed for the baseline case. (3) - Estimated annual tons of emission reduc tion is the difference between annual ba seline tons and each alternative’s annual emissions (tons). (4) - Levelized Total Annual Cost = Annualiz ed 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, controlSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-31 Burns & McDonnell percentage, hourly heat input, and annual hrs/yr operation compared to pre-cont rol baseline emissions based on annual operation at baseline pre-c ontrol NOx emission rate. (5) - Average Control Cost Effectiveness ($/ton) is the Leveli zed Total Annual Cost ($/yr) divided by Annual Emission Reduction (tons/yr). All cost figures in 2006 dollars. (6) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install these t echnologies on Unit 2 at Milton R. Young Sta tion. The estimated annual NOx removal and LTAC shown for a hypothetically -applied SCR system is based on assump tions that known or ex pected reasons for technical infeasibility for installation of the SCR equipment on this bo iler are unsolvable. Costs are derived from Burns & McDonnell internal database and co st estimate specifically for MRYS Unit 2 in 2006 dollars. SCR technology is considered technically infeasible by Minnkota for applicat ion at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent s ubmittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application of SCR alternatives is includ ed for comparative purposes onl y. See Section 4.2.1.2.1 for details of Scenario A and Scenario B th at assumes replacement of SCR catalyst after a specified number of hours of unit operation. (7) - LTAC for gas reburn options include hi gh-pressure natural gas supply pipeline annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR. See footnote number 8 under Table 4-3SF. (8) - LTAC for increased PM collection capacity included in lignite reburn option are a pproximately $3,140,000 for annualized capital cost plus $4,194,000/yr for annuali zed O&M cost, for a LTAC s ubtotal of $7,333,000/yr.



### Figure 4-1SA – NO X 

### Control Cost Effectiveness - MRY Station Unit 2 (1) 

### Stand Alone SCR Projects

Milton R. Young Station Unit 2 NOx Control Annual Removal vs Levelized Total Annual Cost - Stand Alone Projects

0 20000 40000 60000 80000 100000 120000

0 2000 4000 6000 8000 10000 12000 14000 16000 Annual NOx Removal, tons/yrLevelized Total Annual Cost for NOx Control,1000$/yr A = Advanced Separated Overfire Air (ASOFA) B = Fuel Lean Gas Reburn w/ ASOFA C = Lignite Reburn w/ ASOFA D = Gas Reburn w/ ASOFA E = SNCR w/ ASOFA T1 = Hypothetical Tail-End SCR w/ ASOFA (Scenario B) T2 = Hypothetical Tail-End SCR w/ ASOFA (Scenario A) L1 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario B) L2 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario A)

B

A C D

E T1

T2 L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-7SA.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-32 Burns & McDonnell (2) - The inclusion of tail-end and low-dus t SCR technologies in this figure does not constitute agreement that it is technically feasible to inst all these technologies on Unit 2 at Milton R. Young Station. The estimated annual NOx removal and LTAC shown for a hypothetically-applied SCR sy stem 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 tec hnically infeasible by Minnkota for a pplication at MRYS per the October 2006 NO X 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 spec ified number of hours of unit operation.



### Figure 4-1SF – NO X 

### Control Cost Effectiveness - MRY Station Unit 2 (1) 

### Shared Facilities SCR Projects

Milton R. Young Station Unit 2 NOx Control Annual Removal vs Levelized Total Annual Cost - Shared Facilities Projects

0 20000 40000 60000 80000 100000 120000

0 2000 4000 6000 8000 10000 12000 14000 16000 Annual NOx Removal, tons/yrLevelized Total Annual Cost for NOx Control,1000$/yr A = Advanced Separated Overfire Air (ASOFA) B = Fuel Lean Gas Reburn w/ ASOFA C = Lignite Reburn w/ ASOFA D = Gas Reburn w/ ASOFA E = SNCR w/ ASOFA T1 = Hypothetical Tail-End SCR w/ ASOFA (Scenario B) T2 = Hypothetical Tail-End SCR w/ ASOFA (Scenario A) L1 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario B) L2 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario A)

B

A C D

E T1

T2 L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4-7SF. (2) - The inclusion of tail-end and low-dus t SCR technologies in this figure does not constitute agreement that it is technically feasible to inst all these technologies on Unit 2 at Milton R. Young Station. The estimated annual NOx removal and LTAC shown for a hypothetically-applied SCR sy stem 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 tec hnically infeasible by Minnkota for a pplication at MRYS per the October 2006 NO X 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 spec ified number of hours of unit operation.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-33 Burns & McDonnell 

### The purpose of Figures 4-1SA and 4-1SF is to show the range of control and cost for four hypotheticallyapplied SCR cases and previously-analyzed feasible NO X 

### control alternatives on Milton R. Young Unit 2

alternatives evaluated.

Data points for conventional gas reburn (Point D) and fu el-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 contro l cost-effectiveness analysis.

A dominant set of control alternatives was determined by generating what is called the “envelope of least-cost

alternatives”. The dominant controls cost curve is th e best fit line through the points forming the rightmost boundary of the data zone on a scatter plot of the annual NO X 

### removal tonnage versus LTAC for the various remaining BACT alternatives. Averag e and incremental annual costs and NO X 

### emission reductions for the

dominant least-cost control alternativ es 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 NO X 

### Control Alternatives - MRY Stat ion Unit 2 - Stand Alone Projects

Alt. Label (1) NOx Control Alternative Levelized Total Annual Cost (2),(3) ($1,000/yr) Annual Emission Reduction (3) (tpy) Incremental Levelized

Total Annual Cost (2),(4) ($1,000/yr) Incremental Annual Emission Reduction (4) (tpy) Incremental Control Cost Effectiveness

($/ton) (2),(4)

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (5) 69,057 14,857 57,439 5,485 10,472

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (5) 98,818 14,980 87,200 5,608 15,550

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (5) 59,881 14,862 48,263 5,490 8,792

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (5) 89,072 14,980 77,454 5,608 13,812

E SNCR w/ ASOFA 11,618 9,372 7,242 3,200 2,263

A Advanced SOFA (ASOFA) 4,376 6,172 4,376 6,172 709
(1) - Alternative label has been assigned from highes t to lowest unit NOx emission rate. Dominant controls cost curve points from lowest (ASOFA) to highest (TESCR w/ ASOFA-16,000 hrs) ar e labeled the same as in Ta ble 4-7SA, and on the graphs that accompany this table (Points B, C, and D were eliminated). (2) - All cost figures in 2006 dollars.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-34 Burns & McDonnell (3) - Annual emission reduction and leve lized control cost of these a lternatives is relative to cu rrent costs and pre-control unit MCR baseline emission rate. (4) - Increment based upon comparison between consecutive alternatives (points) fro m lowest to highest. (5) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install thes e technologies on Unit 2 at Milton R. Young Sta tion. 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 technica lly infeasible by Minnkota for application at MRYS per the October 2006 NO X BACT Analysis Study report a nd subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this informat ion for the hypotheti cal application of SCR alternatives is included for comparative purposes only. Se e Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of S CR catalyst after a specified number of hours of unit operation.



### TABLE 4-8SF – Dominant Controls Cost Curve Points for NO X 

### Control Alternatives - MRY Stati on Unit 2 - Shared Facilities Projects

Alt. Label (1) NOx Control Alternative Levelized Total Annual Cost (2),(3) ($1,000/yr) Annual Emission Reduction (3) (tpy) Incremental Levelized

Total Annual Cost (2),(4) ($1,000/yr) Incremental Annual Emission Reduction (4) (tpy) Incremental Control Cost Effectiveness

($/ton) (2),(4)

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (5) 66,506 14,857 54,888 5,485 10,007

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (5) 96,268 14,980 84,650 5,608 15,096

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (5) 57,351 14,862 45,733 5,490 8,331

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (5) 86,542 14,980 74,924 5,608 13,361

E SNCR w/ ASOFA 11,618 9,372 7,242 3,200 2,263

A Advanced SOFA (ASOFA) 4,376 6,172 4,376 6,172 709
(1) - Alternative label has been assigned from highes t to lowest unit NOx emission rate. Dominant controls cost curve points from lowest (ASOFA) to highest (TESCR w/ ASOFA-16, 000 hrs) are labeled the same as in Table 4-7SF, and on the graphs that accompany this table (Points B, C, and D were eliminated). (2) - All cost figures in 2006 dollars. (3) - Annual emission reduction and le velized control cost of these alternatives is relative to current costs and pre-control unit MCR baseline emission rate. (4) - Increment based upon comparison between consecutive alternatives (points) fro m lowest to highest. (5) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install these t echnologies on Unit 2 at Milton R. Young Sta tion. 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 boile r are solvable. SCR technolog y is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in response to comments by th e NDDH, EPA, DOJ and other parties, so this information fo r the hypothetical application of SCR alternatives is included for comparative pur poses only. See Section 4.2.1. 2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-35 Burns & McDonnell 

### Figures 4-2SA and 4-2SF contain a repetition of the levelized total annual cost and NO X 

### control information from Figure 4-1SA and 4-2SF for MRY Station Unit 2, with Point B (FLGRTM with ASOFA), Point C (Lignite Reburn with ASOFA) and Point D (conventiona l gas reburn with ASOFA) removed. This is the

dominant controls cost curve for MRY Station Unit 2 NO X 

### emissions alternatives.



### Figure 4-2SA – MRY Station Unit 2 NO X 

### Control Alternatives BACT Dominant Controls Cost Curve (1) 

### - Stand Alone SCR Projects

Milton R. Young Station Unit 2 NOx Control Dominant Controls Cost Curve - Stand Alone Projects

0 20,000 40,000 60,000 80,000 100,000 120,000

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Annual NOx Removal, tons/yrLevelized Total Annual Cost for NOxControl, 1000$/yr

A E T2 $15,550/ton T1

$709/ton $8,792/ton Slope = Incremental $/ton (Points B, C, and D removed)

$2,263/ton A

= Advanced Separated Overfire Air (ASOFA) E = SNCR w/ ASOFA T1 = Hypothetical Tail-End SCR w/ ASOFA (Scenario B) T2 = Hypothetical Tail-End SCR w/ ASOFA (Scenario A) L1 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario B) L2 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario A)

L2 L1

$10,472/ton $13,812/ton

(1) - All cost figures in 2006 dollars. Numbers are lis ted and qualifiers are noted in Table 4-8SA. (2) - The inclusion of tail-end and low-dust SCR technologies in this figure does not cons titute agreement that it is technically feasible to install these t echnologies on Unit 2 at Milton R. Young Sta tion. The estimated annual NOx removal and LTAC shown for a hypothetically -applied SCR system is based on assump tions that known or ex pected reasons for technical infeasibility for installation and operation and maintenance of the SCR equipment on this boiler are solvable. SCR technology is considered techni cally infeasible by Minnkota for appli cation at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and other parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-36 Burns & McDonnell 

### Figure 4-2SF – MRY Station Unit 2 NO X 

### Control Alternatives BACT Dominant Controls Cost Curve (1) 

### – Shared Facilities SCR Projects



### Milton R. Young Station Unit 2 NOx Control Dominant Controls Cost Curve - Shared Facilities Projects

0 20,000 40,000 60,000 80,000 100,000 120,000

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Annual NOx Removal, tons/yrLevelized Total Annual Cost for NOxControl, 1000$/yr

A E T2 $15,096/ton T1

$709/ton $8,331/ton Slope = Incremental $/ton ( Points B, C, and D removed )

$2,263/ton A = Advanced Separated Overfire Air (ASOFA) E = SNCR w / ASOFA T1 = Hypothetical Tail-End SCR w / ASOFA (Scenario B) T2 = Hypothetical Tail-End SCR w / ASOFA (Scenario A) L1 = Hypothetical Low -Dust SCR w / ASOFA (Scenario B) L2 = Hypothetical Low -Dust SCR w / ASOFA (Scenario A)

L2 L1

$10,007/ton $13,361/ton

(1) - All cost figures in 2006 dollars. Numbers are lis ted and qualifiers are noted in Table 4-8SF. (2) - The inclusion of tail-end and low-dust SCR technologies in this figure does not cons titute agreement that it is technically feasible to install these t echnologies on Unit 2 at Milton R. Young Sta tion. 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 S CR equipment on this boiler are solvable. SCR technology is considered technica lly infeasible by Minnkota for applic ation at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent subm ittals 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. Se e Section 4.2.1.2.1 for details of Scenario A and Scenario B that assume s replacement of SCR catalyst after a sp ecified number of hours of unit operation.



### As can be seen from a review of Table 4-7SA and Table 4-7SF, the average control cost effectiveness (called the unit control cost in this report) ranges from approximately $709/ton to $7,171/ton of MRYS Unit

2’s NO X 

### emissions removed. The unit control cost for the hypothetically-applied Scenario A Tail End SCR w/ ASOFA case was $4,648/ton and for the hypothet ically-applied Scenario B Tail End SCR w/ ASOFA case was $6,597/ton (stand alone projects). The unit contro l cost for the hypotheti cally-applied Scenario A Low-Dust SCR w/ ASOFA case was $4,029/ton and for the hypothetically-applied Scenario B Low-Dust SCR w/ ASOFA case was $5,946/ton (stand alone projects) . The unit control cost for the hypotheticallyapplied Scenario A Tail End SCR w/ ASOFA case was $4,477/ton and for the hypothetically-appliedSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-37 Burns & McDonnell 

### Scenario B Tail End SCR w/ ASOFA case was $6,427/ton (shared facilities projects). The unit control cost for the hypothetically-applied Scenario A Low-Dust SCR w/ ASOFA case was $3,859/ton and for the hypothetically-applied Scenario B Low-Dust S CR w/ ASOFA case was $5,777/ton (shared facilities projects). Unit control cost for SNCR w/ ASOFA was $1,240/ton, nearly twice that of ASOFA ($709/ton). It should be noted, however, that very high estimated average control costs involve fuel lean gas reburn ($4,014/ton) and conventional gas reburn ($7,171/ton) technologies that were previously shown to be inferior options (not on the dominant controls cost curve) and thus were eliminated from further impacts analysis.

The incremental cost analysis indicates that from a cost effectiveness viewpoint, the SNCR with ASOFA alternative for MRYS Unit 2 incurs a significant annu al (levelized) incremental cost compared to the

ASOFA NO X 

### control technique. The slope from zero (base line) to ASOFA (Point A) was $709/ton; the incremental cost per ton (slope) from ASOFA (Point A) to SNCR with ASOFA (Point E ) was $2,263/ton for MRYS Unit 2. The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetically-applied low-dust SCR case (Point L2, Scenario A) was $8,792/ton (stand alone projects). The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetically-applied tail end SCR case (Point T2, Scenario A) was $10,472/t on (stand alone projects). The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetically-applied low-dust SCR case (Point L1, Scenario B) was $13,812/ton (stand alone pr ojects). The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetica lly-applied tail end SCR case (Point T1, Scenario B) was $15,550/ton (stand alone projects). For shared projects, the incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetica lly-applied SCR cases were $8,331/ton (low-dust Point L2, Scenario A) and $10,007/ton (tail end Point T2, Scen ario A). For shared proj ects, the incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetically-applied SCR cases were $13,361/ton (low-dust, Point L1, Scenario B) and $15,096/ton (tail end Point T1, Scenario B).

In the U.S. EPA’s NSR Manual, the EPA does not specify acceptable or unacceptable ranges for average (unit control costs) and incremental cost effec tiveness 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 h as adequately identified the circumstances,Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-38 Burns & McDonnell 

### including the cost or other analyses, that show what is significantly different about the proposed source.” 34



### This supplemental report for the MRYS NOx BACT An alysis has clearly established the circumstances, including the economic impacts, which would make th e hypothetical application of TESCR or LDSCR to MRYS Unit 2 significantly more expensive than SCR costs normally incurred by other coal-fired steam electric generating units. The following information fu rther supports EPA’s own st atements regarding the costs “normally incurred by other sources”. The EPA ’s technical support document issued with the final Regional Haze Regulations and BART Guidelines estimated an average control cost for SCR applied to MRYS Unit 2 of $537 per ton 35 

### . 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 BART 36 

### was $100/kW. The EPA’s cost-effectiveness analysis used for establishing presumptive BART stated that “applying SCR for coal-fi red cyclone units is typically less than $1500 a ton, and that the average cost-effectiveness is $900 per ton” 37 

### . The site-specific control costs estimated for hypothetical application of tail-end and low-dust SCR alternatives to MRYS Unit 2 are significantly higher than the EPA’s cost-effectiveness analysis for conve ntional 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 op tions that exist, the more weight should be given to the incremental costs vs. averag e costs”. Also in the final 2005 RHR/BART Guidelines, “the average cost for each [of two options, A and B]... may be deem ed to be reasonable. However, the incremental

cost...of the additional emissions reductions to be achie ved by control B may be very great. In such an instance, it may be inappropriate to chose control B, based on its higher incrementa l 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-EffectivenessAnalysis for MRY Station Unit 2 NOx Emissions________________________________________________________________________________________________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-39Burns & McDonnellTABLE 4-9SA – Estimated Emissionsand Economic Impacts Summary for NOXControl Alternatives - MRY Station Unit 2 - Stand Alone SCR ProjectsSummary of Estimated Annual Emissions and Economics for NOx Control Alternatives Evaluated for Milton R. Young Station Unit 2 –Stand Alone SCR ProjectsECONOMIC IMPACTSEMISSIONS(2)EmissionRateHourlyEmissionAnnualEmissionEmissionReductionAlt.Label(1)NOx Control Alternativelb/mmBtu lbs/hr tons/yr tons/yrNOxRemovalEfficiency(2)%InstalledCapitalCost(3)$1,000AnnualO & MCost(4)$1,000LevelizedTotalAnnualizedCost(5)$1,000AverageControlCost(6)$/tonT2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(7)0.049 239 936 14,857 93.8(8)340,73331,512 69,057(7)4,648T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(7)0.049 239 813 14,980 93.8(8)340,733 55,345 98,818(7)6,597L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(7)0.049 239 931 14,862 93.8(8)270,785 29,048 59,881(7)4,029L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(7)0.049 239 813 14,980 93.8(8)270,78552,424 89,072(7)5,946E SNCR w/ ASOFA 0.330 1,612 6,421 9,372 58.0 17,128 8,108 11,618 1,240D Gas Reburn w/ ASOFA 0.350 1,710 6,882 8,910 55.4 35,490 48,688 63,892(9)7,171C Lignite Reburn w/ ASOFA 0.360 1,759 6,964 8,829 54.2 81,167 9,929 19,475(9)2,206B FLGR w/ ASOFA 0.432 2,110 8,490 7,303 45.0 21,81721,954 29,317(9)4,014A Advanced SOFA (ASOFA) 0.489 2,391 9,621 6,172 37.7 10,008 2,805 4,376 709Baseline 0.786 3,839 15,793 0 - 0 0 0(1)- Alternative label has been assigned from highest to lowest unit NOx emission rate.(2)- Estimated NOXcontrol level reductions relative to average annual unit emission baseline of 0.786 lb/mmBtu at 4,885 mmBtu/hr MCR heat input.Emissions are calculated from unit emission rates, controlpercentage, hourly heat input,and annual hrs/yr operation compared to pre-control baseline based on annual operationat a gross unit electrical output of 440MWg and assumes a 93.9% average annual availability.Values from reported emission data for the 12 monthoperating period during 2001-2005 with the highest rolling summation of NOx pounds.(3)- Installed capital cost is estimated for determination of totalcapital cost for a particular technology or combination, assuming 477 MWg unit capacity rating. All cost figures in 2006dollars. Costs for gas reburn options include highpressure natural gas supply pipeline installed capital cost of $14,988,000 for CGRand $7,494,000 for FLGR, and annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR. Costs for increased PM collection capacityincluded in lignite reburn option are $36,013,000 for installed capital cost.(4)- Annual operating and maintenance cost fora particular technology or combination is compared to unit baseline operation at agross unit electrical output of 440 MWg and assumes a 95.2% average running plant capacity ratio compared tonominal unit gross electricaloutput capacity of 462 MWg. All cost figuresin 2006 dollars. Costs for increased PMcollectioncapacity included in lignite reburn option are $3,155,000/yr for annual O&M cost.(5)- Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Levelized annual O&M cost = Annual O&M costx 1.24873 annualized O&M cost factor.(6)- Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost (1000$) divided by Annual Emission Reduction (tons). All cost figures in 2006 dollars.(7)- The inclusion of tail-end and low-dustSCR technologies in this table does not constitute agreement thatthese technologiesare technically feasible to install onUnit 2 at Milton R. Young Station.The estimated annual NOx removal andLTAC shown for a hypothetically-applied SCR system is based on assumptions thatknown or expected reasonsfor technical infeasibilityfor installation and operation and maintenance of the SCR equipment on this boiler are solvable.SCR technology isconsidered technically infeasible by Minnkota for application at MRYS per the October 2006 NOXBACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and otherparties, so this information for the hypothetical application ofSCR 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 aspecified number of hours of unit operation.(8)- The stated overall control percentage includes the anticipated long-term emission reduction of90% design removal from a baseline of 0.49 lb/mmBtu resulting from an advanced separated overfire air system, with air-staged low-NOXcyclone combustion. Without a separatedoverfire air system operation or any othertechnique employed, the assumed emission rate would be 0.079 lb/mmBtu, for anoverall reduction of 90 percent froma baseline of 0.786 lb/mmBtu.(9)- LTAC for reburn options include high-pressure natural gas supply pipeline annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR; LTAC for increased PM collection capacity included inlignite reburn option are$3,140,000 for annualized capital cost plus $3,940,000/yr for annualized O&Mcost, for a total of $7,080,000/yr.Supplemental BACT Control and Cost-EffectivenessAnalysis for MRY Station Unit 2 NOx Emissions________________________________________________________________________________________________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-40Burns & McDonnellTABLE 4-9SF – Estimated Emissions and Economic Impacts Summary for NOXControl Alternatives - MRY StationUnit 2 – Shared Facilities SCR ProjectsSummary of Estimated Annual Emissions and Economics for NOx Control Alternatives Evaluated for Milton R. Young Station Unit 2 –Shared Facilities SCR ProjectsECONOMIC IMPACTSEMISSIONS(2)EmissionRateHourlyEmissionAnnualEmissionEmissionReductionAlt.Label(1)NOx Control Alternativelb/mmBtu lbs/hr tons/yr tons/yrNOxRemovalEfficiency(2)%InstalledCapitalCost(3)$1,000AnnualO & MCost(4)$1,000LevelizedTotalAnnualizedCost(5)$1,000AverageControlCost(6)$/tonT2 Hypothetical Tail End SCR w/ ASOFA – Scenario A(7)0.049 239 936 14,857 93.8(8)320,27930,898 66,506(7)4,477T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(7)0.049 239 813 14,980 93.8(8)320,279 54,731 96,268(7)6,427L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(7)0.049 239 931 14,862 93.8(8)250,487 28,439 57,351(7)3,859L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(7)0.049 239 813 14,980 93.8(8)250,48751,815 86,542(7)5,777E SNCR w/ ASOFA 0.330 1,612 6,421 9,372 58.0 17,128 8,108 11,618 1,240D Gas Reburn w/ ASOFA 0.350 1,710 6,882 8,910 55.4 35,490 48,688 63,892(9)7,171C Lignite Reburn w/ ASOFA 0.360 1,759 6,964 8,829 54.2 81,167 9,929 19,475(9)2,206B FLGR w/ ASOFA 0.432 2,110 8,490 7,303 45.0 21,81721,954 29,317(9)4,014A Advanced SOFA (ASOFA) 0.489 2,391 9,621 6,172 37.7 10,008 2,805 4,376 709Baseline 0.786 3,839 15,793 0 - 0 0 0(1)- Alternative label has been assigned from highest to lowest unit NOx emission rate.(2)- Estimated NOXcontrol level reductions relative to average annual unit emission baseline of 0.786 lb/mmBtu at 4,885 mmBtu/hr MCR heat input.Emissions are calculated from unit emission rates, controlpercentage, hourly heat input,and annual hrs/yr operation compared to pre-control baseline based on annual operationat a gross unit electrical output of 440MWg and assumes a 93.9% average annual availability.Values from reported emission data for the 12 monthoperating period during 2001-2005 with the highest rolling summation of NOx pounds.(3)- Installed capital cost is estimated for determination of totalcapital cost for a particular technology or combination, assuming 477 MWg unit capacity rating. All cost figures in 2006dollars. Costs for gas reburn options include highpressure natural gas supply pipeline installed capital cost of $14,988,000 for CGRand $7,494,000 for FLGR, and annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR. Costs for increased PM collection capacityincluded in lignite reburn option are $36,013,000 for installed capital cost.(4)- Annual operating and maintenance cost fora particular technology or combination is compared to unit baseline operation at agross unit electrical output of 440 MWg and assumes a 95.2% average running plant capacity ratio compared tonominal unit gross electricaloutput capacity of 462 MWg. All cost figuresin 2006 dollars. Costs for increased PMcollectioncapacity included in lignite reburn option are $3,155,000/yr for annual O&M cost.(5)- Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Levelized annual O&M cost = Annual O&M costx 1.24873 annualized O&M cost factor.(6)- Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost (1000$) divided by Annual Emission Reduction (tons). All cost figures in 2006 dollars.(7)- The inclusion of tail-end and low-dustSCR technologies in this table does not constitute agreement that these technologiesare technically feasible to install on Unit 2 at Milton R. Young Station.The estimated annual NOx removal andLTAC shown for a hypothetically-applied SCR system is based on assumptions thatknown or expected reasonsfor technical infeasibilityfor installation and operation and maintenance of the SCR equipment on this boiler are solvable.SCR technology isconsidered technically infeasible by Minnkota for application at MRYS per the October 2006 NOXBACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ and otherparties, so this information for the hypothetical application ofSCR 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 aspecified number of hours of unit operation.(8)- The stated overall control percentage includes the anticipated long-term emission reduction of90% design removal from a baseline of 0.49 lb/mmBtu resulting from an advanced separated overfire air system, with air-staged low-NOXcyclone combustion. Without a separatedoverfire air system operation or any othertechnique employed, the assumed emission rate would be 0.079 lb/mmBtu, for anoverall reduction of 90 percent froma baseline of 0.786 lb/mmBtu.(9)- LTAC for reburn options include high-pressure natural gas supply pipeline annualized capital cost of $1,307,000/yr for CGR and $653,000 for FLGR; LTAC for increased PM collection capacity included inlignite reburn option are$3,140,000 for annualized capital cost plus $3,940,000/yr for annualized O&Mcost, for a total of $7,080,000/yr.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-41 Burns & McDonnell 

### The other elements of the fourth step of a BACT an alysis 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 NO X 

### CONTROL ALTERNATIVES FOR MRY STATION UNIT 2 Operation of the NO X 

### 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 de tails of estimated energy usage and costs for the previously-evaluated NO X 

### control alternatives were described and summarized in Section 3.4.2 and Appendix C3 of the October 2006 NOx BACT Analysis Study report 39



### .

The hypothetical application of Tail End and Low-Dust SCR w/ ASOFA alternatives involve higher energy consumption compared with the existing operation of MRYS Unit 2. New induced draft booster fan electrical power demand is needed due to the estimated additional flue gas pressure drop resulting from hypothetical application of SCR reactor, ductwork, and gas-to-gas heat exchangers. The additional auxiliary electric power demands for the hypotheti cal application of TESCR and LDSCR equipment were calculated to be 14.9 MW and 12.4 MW, respectively, using estimated annual aver age electrical loads of
the booster fan, urea-to-ammonia conversion fired heater combustion/dilution air fan, direct-fired flue gas
reheat burner combustion air fan, and service and sootblowing air compressor equipment and related auxiliary equipment.

Preliminary conceptual design details were developed for these alternatives. An estimated additional 10 inches w.c. of flue gas pressure drop was assumed fo r each hypothetical application of low-dust SCR system, and an estimated additional 16 inches w.c. of flue gas pressure drop was assumed for the hypothetical application of tail end SCR system. Equipment and ductwork arrangements and expected severe fouling of the catalyst for the hypothetical app lication of SCR system ductwork, reactor, and gasgas reheater changes may cause significantly more restri ctive flow paths. Thus the electrical power usage estimated here may be too low.

39 Ibid Reference number 3, October 2006, pages 3-31 through 3-35, and Appendix pages C3-7 through C3-10.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-42 Burns & McDonnell 

### The expected loss of electrical power generation from these reductions in net output was included as a cost, assuming $35 per megawatt-hour for replacement electrical power. Energy impacts of installing hypothetical applications of low-dust and tail end SCR alternatives for NO X 

### 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 am monia to the SCR reactor catalyst for the hypothetically-applied lowdust and tail-end SCR alternatives. A urea-to-a mmonia conversion system dedicated for each SCR reactor was also assumed. This conversion process w ill use a natural gas-fired burner that mixes the combustion products at high temperature with the in jected 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 cat alyst in the SCR reactors uses to convert nitrogen oxides to elemental nitrogen and water vapor. Ammonia (from urea conversion) is supplied and consumed continuously on demand while the SCR NOx reduction process is in operation. Natural gas is fired continuously during the urea-to -ammonia conversion system operation.

Final reactor inlet flue gas reheat systems are requi red for the hypothetical app lications of tail end and

low-dust SCR with ASOFA alternatives. A natural gas-fired duct burner that injects high temperature combustion products directly into the flue gas di scharged from each SCR gas/ gas heat exchanger was assumed for raising the reactor inlet temperature to 600oF before ammonia in jection and NOx reduction can occur in each SCR reactor. Natural gas is fire d continuously for flue gas reheating during SCR system operation.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-43 Burns & McDonnell



### TABLE 4-10 – Energy Impacts for NO X 

### Control Alternatives - MRY Station Unit 2

Alt. Label (1) NOx Control Alternative (2) Estimated Annual Natural Gas

Usage forUrea-toAmmonia Conversion ,(3) (mmBtu/yr) Estimated Annual Natural Gas Usage

for SCR

Inlet Reheat ,(4) (mmBtu/yr) Estimated Annual Natural Gas Usage for Reburn

Fuel ,(5) (mmBtu/yr) Estimated Additional

Annual

Coal Burned for Urea Solution Dilution Water ,(6) (mmBtu/yr) Estimated Total Annual Natural Gas Usage and , Additional Annual Coal

Burned (7) (mmBtu/yr)

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (5) 49,463 754,563 0 0 804,026

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (5) 42,975 655,591 0 0 698,566

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (5) 49,203 710,710 0 0 759,913

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (5) 42,975 620,747 0 0 663,722

E SNCR w/ ASOFA 0 0 0 73,986 73,986
D Gas Reburn w/ ASOFA 0 0 6,301,740 0 6,301,740

C Lignite Reburn w/ ASOFA 0 0 0 0 0
B FLGR w/ ASOFA 0 0 2,610,560 0 2,610,560

A Advanced SOFA (ASOFA) 0 0 0 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. Alternatives are labeled the same as in Table 4-9. (2) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these t echnologies on Unit 2 at Milton R. Young Station. The annual NOx removal and LTAC shown for a hypothetically -applied SCR system is based on assump tions that known or ex pected reasons for technical infeasibility for installation of the SCR equipment on this boiler are solvable. SCR technology is considered technically infeasible by Mi nnkota for application at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA, DOJ an d other parties, so this information for the hypothetical application of SCR alternatives is includ ed for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation. (3) – Estimated annual natural gas usage for urea-to-ammonia conversion based on adjustments to preliminary budgetary equipment vendor proposals and process calculations. TESCR and LDSCR rate = 3.15 mmBtu/hr for each reactor x 2. (4) – Estimated annual natural gas usage fo r flue gas final reheat based on adju stments to preliminary vendor process calculations. TESCR rate = 48.11 mmBtu/hr for each reactor x 2; LDSCR rate = 45.55 mmBtu/hr for each reactor x 2. (5) – Natural gas burned for reburn alternatives is assumed to re place coal, no boiler heat rate penalty assumed. Lignite reburn is assumed to burn the same total amount of coal in the boiler as without coal reburn. (6) - Additional coal burned is due to the urea dilution water injected directly into the boiler’s upper furnace, decreasing heat available for steam production and el ectricity generation, at a net loss of 900 Btu/lb of water for evaporation. See Appendix C3 in the 2006 NO X BACT Analysis Study report for additional details. (7) - Annual O&M costs include these values multiplied by th e number of hours per year of operation and assume $7.98 per mmBtu for natural gas and $0.71 per mmBtu for coal.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-44 Burns & McDonnell 

### 4.2.3 ENVIRONMENTAL IMPACTS OF HYPOTHETICALLY-APPLIED SCR NO X 

### CONTROL ALTERNATIVES FOR MRY STATION UNIT 2 Operation of the NO X 

### control technologies on the dominant controls cost curve for potential application at the Milton R. Young Station impose direct and indirect impacts on the environment. The most pronounced direct environmental impact expected from operation of any of the NO X 

### 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 NO X 

### control

alternatives were described and summarized in Sec tion 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 a nd 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 decr ease 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 orga nic compounds (VOCs). Emissions from the urea-toammonia conversion and flue gas reheat natural gas-fi red burners are additive and included in the flue gas entering the SCR reactor in each hypothetical case.

Operation of any SCR system will normally cause a small amount of unreacted ammonia to be emitted. The amount of ammonia slip produced by an SCR de pends on the reagent utilization and the location of the injection points. Higher SCR NO X 

### 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 [(NH 4 

### ) 2 

### SO 4 

### ] and ammonium bisulfate [NH 4 

### HSO 4 

### ] will be more problematic at higher slip levels. Sulfur trioxide (SO 3 

### ) formed during combustion in the boiler can combine with ammonia during passage through the catalyst to form the sulfates downstream.

40 Ibid Reference number 3, October 2006, pages 3-35 through 3-37.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-45 Burns & McDonnell 

### Unreacted ammonia (“slip”) from SCR operation will notbe collected downstream of the hypotheticallyapplied tail end SCR reactors. The wet flue g as desulfurization absorbers downstream of the hypothetically-applied low-dust SCR reactors may reduce ammonia slip. Any remaining ammonia slip that is not collected or condensed in the air pollution cont rol 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 (SO 2 

### ) formed during combustion in the boile r can combine with oxygen during passage through the hypothetical tail end a nd low-dust SCR catalyst to form additional sulfur trioxide (SO 3 

### )

emissions. SO 3 

### can subsequently combine with water (H 2 

### O) to form sulfuric acid (H 2 

### SO 4 

### ), usually in the form of a mist. Wet flue gas scrubbing to remove SO 2 

### is not highly effective in removing SO 3 

### 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. SO 3 

### and H 2 

### SO 4 

### can have significant negative far-field impairment imp acts on atmospheric visibility if they are above

threshold concentrations and not controlled. Tail end SCRs can also cause a small amount of SO 3 

### to be created as the remaining SO 2 

### 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 th e high concentration of alkalinity in the form of sodium aerosol particles at MRYS will effectively eliminate the remaining SO 3 

### downstream of the hypothetically-applied low-dust and tail end SCR systems.

Catalyst from the hypothetical application of S CR reactors will require regular replacement, requiring disposal of the spent catalyst materials or chemic al cleaning to remove deposits to allow reuse or regeneration. Hauling spent catalyst to a catalyst rejuvenation facility or authorized landfill may be required, producing additional liquid and so lid 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 appli cation of SCR reactors will require additional truck traffic between the supply facility and plant, pr oducing more emissions from vehicle exhaust.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-46 Burns & McDonnell 

### 4.2.4 SUMMARY OF ECONOMIC, ENER GY AND ENVIRONMENTAL IMPACTS OF HYPOTHETICALLY-APPLIED SCR NO X 

### CONTROL ALTERNATIVES FOR MRY STATION UNIT 2 The economic, energy, and environmental impacts of each NO X 

### control technology on the dominant controls cost curve for potential application at the Milton R. Young Station evaluated for this study are

summarized in this Section. Table 3-18 summarized the various impacts discussed in Sections 3.4.1 through 3.4.3 of the October 2006 NO X 

### BACT Analysis Study report 41 

### . The economic analysis examined the estimated capital cost of four hypothetically-a pplied SCR cases and previously-analyzed feasible NO X 

### control alternatives and any other po werplant upgrade costs necessary to implement the alternatives. In addition, the economic analysis examined the opera ting and maintenance costs associated with each NO X 

### control technology evaluated. These costs were then combined into th e levelized total annual cost for a comparative assessment of the total implementation cost of each alternative. Finally, as part of the topdown analysis, a dominant controls cost curve was pl otted and the unit control cost for each remaining alternative was evaluated. Four hypothetically-appl ied SCR cases and two previously-analyzed feasible

alternatives were on the dominant controls cost cu rve and the latter were identified as the more costeffective alternatives. The four hypothetically-a pplied SCR cases and two previously-analyzed feasible

BACT NO X 

### control alternatives were evaluated for increm ental cost, energy, and environmental impacts applicable to Milton R. Young Station Unit 2. The results are summarized in Tables 4-11SA and 4-11SF.

The unit control cost for the hypothetically-applied SCR cases:

• Tail End SCR w/ ASOFA stand alone SCR proj ects cases - Scenario A was $4,648/ton and Scenario B was $ 6,597/ton.

• Low-Dust SCR w/ ASOFA stand alone SCR projects cases - Scenario A was $4,029/ton and Scenario B was $5,946/ton.

• Tail End SCR w/ ASOFA shared facilities SCR projects cases - Scenario A was $4,477/ton and Scenario B was $ 6,427/ton.

• Low-Dust SCR w/ ASOFA shared facilities SCR projects cases - Scenario A was $3,859/ton and Scenario B was $5,777/ton. These UCCs are approximately 370 to 525 percent of the UCC for SNCR w/ ASOFA ($1,240/ton), and approximately 645 to 920 percent of ASOFA’s UCC ($709/ton).

41 Ibid Reference number 3, October 2006, pages 3-20 through 3-38.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-47 Burns & McDonnell 

### The incremental cost analysis indicates that from a cost effectiveness viewpoint, the SNCR with ASOFA alternative for MRYS Unit 2 incurs a significant annu al (levelized) incremental cost compared to the

ASOFA NO X 

### control technique. The slope from zero (base line) to ASOFA (Point A) was $709/ton; the incremental cost per ton (slope) from ASOFA (Point A) to SNCR with ASOFA (Point E ) was $2,263/ton for MRYS Unit 2. The incremental cost per ton (sl ope) from SNCR with ASOFA (Point E) to the various hypothetically-applied SCR cases:

• Tail End SCR w/ ASOFA stand alone SCR pr ojects cases - Scenario A was $10,472/ton and Scenario B was $15,550/ton.

• Low-Dust SCR w/ ASOFA stand alone SCR projects cases - Scenario A was $8,792/ton and Scenario B was $13,812/ton.

• Tail End SCR w/ ASOFA shared facilities SCR projects cases - Scenario A was $10,007/ton and Scenario B was $15,096/ton.

• Low-Dust SCR w/ ASOFA shared facilities SCR projects cases - Scenario A was $8,331/ton and Scenario B was $13,361/ton.

The incremental unit control cost per ton (slope) from SNCR with ASOFA to the hypothetically-applied SCR with ASOFA cases are approximately 360 to 680 percent of the incremental UCC per ton (slope) between ASOFA and SNCR with ASOFA ($2,263/to n). The incremental UCCs from SNCR with ASOFA to the hypothetically-applied SCR with ASOFA cases is between 11 and 22 times the incremental UCC for ASOFA from the pr e-control baseline ($709/ton).

In the U.S. EPA’s NSR Manual, the EPA does not specify acceptable or unacceptable ranges for average (unit control costs) and incremental cost effec tiveness 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 h as 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 An alysis has clearly established the circumstances, including the economic impacts, which would make th e hypothetical application of TESCR or LDSCR to

42 Ibid Reference number 2, Section IV.D.2.c.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

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Square Butte Electric Cooper ative 4-48 Burns & McDonnell 

### MRYS Unit 2 significantly more expensive than SCR costs normally incurred by other coal-fired steam electric generating units. The following information fu rther supports EPA’s own st atements regarding the costs “normally incurred by other sources”.

The EPA’s technical support document issued with the final Regional Haze Regulations and BART

Guidelines was considered relevant for control cost-effectiveness comparison. The EPA’s costeffectiveness analysis used for establishing presump tive BART stated that “applying SCR for coal-fired cyclone units is typically less than $1500 a ton, an d that the average cost-effectiveness is $900 per ton” 43



### . EPA’s Technical Support Document estimated an average control cost for SCR applied to MRYS Unit 2 of $537 per ton 44 

### . 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 BART 45 

### was $100/kW. The estimated “stand alone” and “shar ed facilities” installed capital costs for the hypothetically-applied low-dust SCR w/ ASOFA cases at MRYS Unit 2 are $525 to $568/kW, which are more than 500 percent of the EPA’s number. The es timated “stand alone” and “shared facilities” installed capital costs for the hypothetically-applied tail end SCR w/ ASOFA cases are $671 to 714/kW, which are approximately 700 percent of the EPA’s number. Also stated in the final RHR/BART Guidelines, “the average cost for each [of two options, A and B]... ma y be deemed to be reasonable. However, the

incremental cost...of the additional em issions reductions to be achieved by control B may be very great. In such an instance, it may be inappropriate to c hose 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 appli cation of hypothetically-app lied tail-end and low-dust SCR alternatives to MRYS Unit 2 are significantly hi gher 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 plu ggage from particulate matter and flue gases emitted from cyclone-fired boilers burning North Dakota lignite precludes the technical feasibility for successful application of such SCR technologies on the electric generating units (EGUs) at the Milton R. Young

43 See Reference number 9, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136.
44 Ibid Reference number 3, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215.
45 Ibid Reference number 3, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 209.
46 Ibid Reference number 9, July 2005, FR Vol. 70 No. 128, page 39168.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-49 Burns & McDonnell 

### Station. Not withstanding the technical discussion of SCR technology infeasibility and technical details previously provided in Appendix A1 and Appendix B 47 

### of the initial NO X 

### BACT Analysis Study report and subsequent submittals in r esponse 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 t echnology alternatives are significantly beyond the cost analysis values included in EPA’s technical support document issued with the final Regional Haze Regulations and BART Guidelines 48,49 

### . Average control cost effectiveness for each hypotheticallyapplied SCR control technology case is a minimum of approximately three times the unit control costs of the previously-analyzed highest-performing feasi ble control alternative recommended as BACT for MRYS Unit 2 (SNCR with ASOFA). Incremental control cost effectiveness for each hypotheticallyapplied SCR control technology case is a minimum of approximately three times the incremental control costs of the previously-analyzed highest-performing feasible control alternative recommended as BACT for MRYS Unit 2 (SNCR with ASOFA).

There is an expected decr ease in net capacity and availability to generate electrical power due to the hypothetically-applied SCR alternatives. A 5 to 17 percent decrease in the number of hours of annual operation, and approximately 3% drop in annual plant capacity (net electrical output or MW n 

### ) during operation of the MRYS Unit 2 system are expected if the hypothetically-applied low-dust or tail end SCR

alternatives were installed. There are also subs tantial expected negative energy impacts for each hypothetically-applied SCR control technology case. Additional auxiliary electrical power demands of approximately 12 to 15 MW will result. This estimat e of electrical power usage may be too low. This higher electrical power consumption and lower electri cal power generation by MRYS Unit 2 will require additional replacement electrical power to be generated elsewhere.

Natural gas is fired continuously during the urea-to -ammonia conversion system operation for each of the hypothetically-applied Tail End and Low-Dust SCR with ASOFA alternatives.

Final reactor inlet flue gas reheat systems are re quired for the hypothetically-applied Tail End and LowDust SCR with ASOFA alternatives. Natural gas is fired continuously for flue gas reheating during SCR

47 Ibid Reference number 2, October 2006.
48 See Reference number 9, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136.
49 Ibid Reference number 3, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 2 NOx Emissions

_____________________________________________________________________________________________

Square Butte Electric Cooper ative 4-50 Burns & McDonnell 

### system operation for raising the reactor inlet temperature to 600oF before ammonia injection and NOx

reduction can occur in each SCR reactor.

The site-specific control costs estimated for appli cation of hypothetically-app lied tail-end and low-dust SCR alternatives to MRYS Unit 2 are significantly hi gher 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 50 

### . Low-dust and tail end SCR t echnologies should be excluded

from consideration for NO X 

### control at MRYS due to unacceptably high average and incremental cost per ton of pollutant removal based on the supplemental an alysis provided herein. Therefore the conclusions regarding NOx BACT as expressed in the original October 2006 BACT Analysis for MRYS Unit 2 are

confirmed.

The economic, energy, and environmental impacts of each NO X 

### control technology on the dominant controls cost curve for potential application to Unit 2 at the Milton R. Young Station evaluated for this study are summarized in Tables 4-11SA and 4-11SF.

50 See Reference number 4, July, 2005.Supplemental BACT Control and Cost-EffectivenessAnalysis for MRY Station Unit 2 NOx Emissions___________________________________________________________________________________________________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-51Burns & McDonnellTABLE 4-11SA – Summary of Supplemental BACTAnalysis Impact Results for Dominant NOXControl Alternatives - MRY Station Unit 2 - StandAlone SCR ProjectsECONOMIC IMPACTSENERGY IMPACTSENVIRONMENTALIMPACTSEMISSIONS(2)Alt.Label(1)NOx Control AlternativeEmissionRatelb/mmBtuHourlyEmissionlbs/hrAnnualEmissiontons/yrEmissionReduction(2)tons/yrInstalledCapitalCost(3)$1,000AnnualO & MCost(4)$1,000LevelizedTotalAnnualizedCost(5)$1,000AverageControlCost(6)$/tonIncrementalControlCost(7)$/tonIncrementalAux. PowerDemand(8),kWIncrementalAnnual Aux.Power Usage+ GenerationReduction(8),kW-hrs/yrNon-AirIncrease(9)Toxic AirIncrease(9)T2Hypothetical Tail End SCR w/ASOFA – Scenario A(10)0.049 239 936 14,857 340,73331,512 69,056 4,648 10,472 14,925 278,290,255FlyashUBC,catalystdisposalCO, NH3,SO3T1Hypothetical Tail End SCR w/ASOFA – Scenario B(10)0.049 239 813 14,980 340,733 55,345 98,818 6,597 15,550 14,925 716,682,361FlyashUBC,catalystdisposalCO, NH3,SO3L2Hypothetical Low-Dust SCRw/ ASOFA – Scenario A(10)0.049 239 931 14,862 270,785 29,048 59,881 4,029 8,792 12,389 278,010,746FlyashUBC,catalystdisposalCO, NH3,SO3L1Hypothetical Low-Dust SCRw/ ASOFA – Scenario B(10)0.049 239 913 14,980 270,78552,424 89,072 5,946 13,812 12,389 701,122,255FlyashUBC,catalystdisposalCO, NH3,SO3E SNCR w/ ASOFA0.330 1,612 6,421 9,372 17,128 8,108 11,618 1,240 2,263 133 111,184,869 Flyash UBC CO, NH3A Advanced SOFA (ASOFA)0.489 2,391 9,621 6,172 10,008 2,805 4,376 709 709 1 75,867,520 Flyash UBC COBaseline0.786 3,839 15,793 0 0 0 0(1)- Alternative label has been assigned from highest to lowest unit NOx emission rate.(2)- Estimated NOXcontrol level reductions relative to average annual emission baseline of 0.786 lb/mmBtuat 4,885 mmBtu/hr heat input. Emissions are calculated from unit emission rates, control percentage,hourly heat input, and annual hrs/yr operation compared to pre-controlbaseline based on annual operation at a gross unit electrical output of 440 MWg and assumes a 93.9% average annual availability.(3)- Installed capital cost is estimated for determination of totalcapital cost for a particular technology or combination, assuming 477 MWg unit capacity rating. Allcost figures in 2006 dollars.(4)- Annual operating and maintenance cost fora particular technology or combination is compared to unit baseline operation at agross unit electrical output of 440 MWg and assumes a 95.2% average annual availability, which isthe highest consecutive 12-months of operationfrom 2001-2005. All cost figures in 2006 dollars.(5)- Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Levelized annual O&M cost= Annual O&M costx 1.24873 annualized O&M cost factor.(6)- Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost (1000$/yr) divided by Annual Emission Reduction(tons/yr). All cost figures in 2006 dollars.(7)- Incremental Control Cost Effectiveness ($/ton) is the difference in LTAC between the next moststringent alternative dividedby the emissions reduction. All cost figures in 2006 dollars.(8)- Energy impacts are incremental auxiliary electrical power demand (kW) and annual power usage plus generation lost due to negative unit availability (fewer hours per year of operation) resulting from each control alternative (kW-hrs/yr) compared to thepre-control baseline.(9)- Environmental impacts summarize expected non-air effects and potential toxic air emissions resulting from control alternativecompared to the pre-control baseline. Flyash unburned carboncontent may increase with air-staging cyclones; carbon monoxideconcentrations mayincrease an insignificant amount with air-staging cyclones. Excess unreacted ammonia (slip) expected from SNCR technology andthe hypothetically-appliedSCR technology cases.(10)- The inclusion of tail-end and low-dust SCRtechnologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual NOx removal andLTAC shown for a hypotheticallyapplied SCR system is based on assumptions thatknown or expected reasons for technical infeasibilityfor installation and operation and maintenance of the SCR equipment on this boiler are solvable. SCR technology is consideredtechnically infeasible by Minnkota forapplication at MRYS per the October 2006 NOXBACT Analysis Study report and subsequent submittals in responseto comments by the NDDH, EPA, DOJand other parties, so thisinformation for the hypothetical application ofSCR alternatives is included for comparativepurposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after aspecified number of hours of unit operation.Supplemental BACT Control and Cost-EffectivenessAnalysis for MRY Station Unit 2 NOx Emissions___________________________________________________________________________________________________________________________________________________________________________________________________________________________Square Butte Electric Cooperative 4-52Burns & McDonnellTABLE 4-11SF – Summary of Supplemental BACT Analysis Impact Results for Dominant NOXControl Alternatives - MRY StationUnit 2 – Shared Facilities SCR ProjectsECONOMIC IMPACTSENERGY IMPACTSENVIRONMENTALIMPACTSEMISSIONS(2)Alt.Label(1)NOx Control AlternativeEmissionRatelb/mmBtuHourlyEmissionlbs/hrAnnualEmissiontons/yrEmissionReduction(2)tons/yrInstalledCapitalCost(3)$1,000AnnualO & MCost(4)$1,000LevelizedTotalAnnualizedCost(5)$1,000AverageControlCost(6)$/tonIncrementalControlCost(7)$/tonIncrementalAux. PowerDemand(8),kWIncrementalAnnual Aux.Power Usage+ GenerationReduction(8),kW-hrs/yrNon-AirIncrease(9)Toxic AirIncrease(9)T2Hypothetical Tail End SCR w/ASOFA – Scenario A(10)0.049 239 936 14,857 320,27930,898 66,506 4,477 10,007 14,925 278,290,255FlyashUBC,catalystdisposalCO, NH3,SO3T1Hypothetical Tail End SCR w/ASOFA – Scenario B(10)0.049 239 813 14,980 320,279 54,731 96,268 6,427 15,096 14,925 716,682,361FlyashUBC,catalystdisposalCO, NH3,SO3L2Hypothetical Low-Dust SCRw/ ASOFA – Scenario A(10)0.049 239 931 14,862 250,487 28,439 57,351 3,859 8,331 12,389 278,010,746FlyashUBC,catalystdisposalCO, NH3,SO3L1Hypothetical Low-Dust SCRw/ ASOFA – Scenario B(10)0.049 239 813 14,980 250,48751,815 86,542 5,777 13,361 12,389 701,122,255FlyashUBC,catalystdisposalCO, NH3,SO3E SNCR w/ ASOFA0.330 1,612 6,421 9,372 17,128 8,108 11,618 1,240 2,263 133 111,184,869 Flyash UBC CO, NH3A Advanced SOFA (ASOFA)0.489 2,391 9,621 6,172 10,008 2,805 4,376 709 709 1 75,867,520 Flyash UBC COBaseline0.786 3,839 15,793 0 0 0 0(1)- Alternative label has been assigned from highest to lowest unit NOx emission rate.(2)- Estimated NOXcontrol level reductions relative to average annual emission baseline of 0.786 lb/mmBtuat 4,885 mmBtu/hr heat input. Emissions are calculated from unit emission rates, control percentage,hourly heat input, and annual hrs/yr operation compared to pre-controlbaseline based on annual operation at a gross unit electrical output of 440 MWg and assumes a 93.9% average annual availability.(3)- Installed capital cost is estimated for determination of totalcapital cost for a particular technology or combination, assuming 477 MWg unit capacity rating. Allcost figures in 2006 dollars.(4)- Annual operating and maintenance cost fora particular technology or combination is compared to unit baseline operation at agross unit electrical output of 440 MWg and assumes a 95.2% average annual availability, which isthe highest consecutive 12-months of operation from2001-2005. All cost figures in 2006 dollars.(5)- Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Levelized annual O&M cost= Annual O&M costx 1.24873 annualized O&M cost factor.(6)- Average Control Cost Effectiveness ($/ton) is the Levelized Total Annual Cost (1000$/yr) divided by Annual Emission Reduction(tons/yr). All cost figures in 2006 dollars.(7)- Incremental Control Cost Effectiveness ($/ton) is the difference in LTAC between the next most stringent alternative dividedby the emissions reduction. All cost figures in 2006 dollars.(8)- Energy impacts are incremental auxiliary electrical power demand (kW) and annual power usage plus generation lost due to negative unit availability (fewer hours per year of operation) resulting from each control alternative (kW-hrs/yr) compared to thepre-control baseline.(9)- Environmental impacts summarize expected non-air effects and potential toxic air emissions resulting from control alternativecompared to the pre-control baseline. Flyash unburned carboncontent may increase with air-staging cyclones; carbon monoxideconcentrations mayincrease an insignificant amount with air-staging cyclones. Excess unreacted ammonia (slip) expected from SNCR technology andthe hypothetically-appliedSCR technology cases.(10)- The inclusion of tail-end and low-dust SCRtechnologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 2 at Milton R. Young Station. The estimated annual NOx removal andLTAC shown for a hypothetically-appliedSCR system is based on assumptions that known orexpected reasons fortechnical infeasibilityfor installation and operation and maintenance of the SCR equipment on this boiler are solvable.SCR technology is consideredtechnically infeasible by Minnkota for application atMRYS per the October 2006 NOXBACT Analysis Study report and subsequentsubmittals in response to comments by theNDDH, EPA, DOJ and other parties, so thisinformation for the hypothetical application of SCR alternatives is included for comparative purposes only. SeeSection 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number ofhours of unit operation.Supplemental BACT Analysis for MRY Station Unit 2 NOx Emissions

Square Butte Electric Cooper ative 4-53 Burns & McDonnell 1. 

### North Dakota Department of Health, Environmental Health Section, Division of Air Quality letter by Terry L. O’Clair, P.E. to John Graves, Minnkota Power Cooperative, Re: Milton R. Young Station BACT Determination , dated July 15, 2009, and Re: Request for Time Extension , dated August 7, 2009.

2. 

### EPA New Source Review Workshop Manual, Pr evention 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 “B ART 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, subm itted by Minnkota to NDDH, November 9, 2007.

6. 

### EPA Report “Multipollutant Emission Control Tech nology 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 Manage ment (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 NO X 

### 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 Sta ndards (OAQPS) publication EPA/452/B-02-001, Section 4.2, NOx Controls – NOx Post-Combus tion, 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 Sta ndards (OAQPS) publication EPA/452/B-02-001, Section 4.2, NOx Controls – NOx Post-Combusti on, 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 (B ART) Determinations; Final Rule.