# NOx BEST AVAILABLE
CONTROL TECHNOLOGY
ANALYSIS STUDY
- SUPPLEMENTAL REPORT

for


# Milton R. Young Station Unit 1 Minnkota Power Cooperative, Inc.

November 2009

Revised February 2010 (refer to page TOC-3 for Index of Revisions)



## 31777

# NOx Best Available Control Technology Analysis Study
SUPPLEMENTAL REPORT

for Milton R. Young Station Unit 1

prepared for



# Minnkota Power Cooperative, Inc.

November 2009

Revised February 2010 (refer to page TOC-3 for Index of Revisions)


## Project No. 31777

prepared by

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

COPYRIGHT 2010 © BURNS & McDONNELL ENGINEERING COMPANY, INC.Supplemental BACT Control and Cost -Effectiveness Table of Contents Analysis for MRY Station Unit 1 NOx Emissions

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

### TABLE OF CONTENTS

4.0 SUPPLEMENTAL NOx BACT ANALYSIS CONTROLS & COSTS – MRY STATION UNIT 1................................................................................. 4-1 4.01 ADDITIONAL NOx CONTROLS......................................................................4-2
4.1 RANK OF NOx CONTROL OPTIONS BY EFFECTIVENESS................................4-3
4.1.1 ESTIMATING CONTROL-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 1.....................4-8
4.2.1.1 CAPITAL COST ESTIMATES FOR NOx CONTROL ALTERNATIVES..................4-9
4.2.1.1.1 CAPITAL COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF
SCR NOx CONTROL ALTERNATIVES.........................................................4-12
4.2.1.2 O&M COST ESTIMATES FOR NOx CONTROL ALTERNATIVES........................4-18
4.2.1.2.1 O&M COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF
SCR NOx CONTROL ALTERNATIV ES.........................................................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 SCR NOx CONTROL
ALTERNATIVES FOR MRY STATION UNIT 1....................................................4-41
4.2.3 ENVIRONMENTAL IMPACTS OF HYPOTHETICALLY-APPLIED
SCR NOx CONTROL ALTERNATIVES FOR MRY STATION UNIT 1.......................4-44 4.2.4 SUMMARY OF ECONOMIC, ENERGY , AND ENVIRONMENTAL IMPACTS OF
HYPOTHETICAL-APPLIED SCR NOx CONTROL ALTERNATIVES
FOR MRY STATION UNIT 1..............................................................................4-46
4.2.5 CONCLUSIONS ....................... .....................................................................4-48
REFERENCES.......................................................................................................4-53



## Revisions February 2010
Strikethrough indicates text that has been deleted.

Underline indicates text that has been inserted or revised. (refer to page TOC-3 for Index of Revisions)Supplemental BACT Control and Cost -Effectiveness Table of Contents Analysis for MRY Station Unit 1 NOx Emissions

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

### LIST OF TABLES

Table 4-1 – Ranked NO X 

### Control Options for MRY Station Unit 1 Boiler with Expected Control Performance Table 4-2 – Expected Annual NO X 

### Control Performance for MRY Station Unit 1 Alternatives Table 4-3SA – Unit Capital Cost Factors of NO X 

### Control Alternatives for MRY Station Unit 1 – Stand Alone SCR Projects Table 4-3SF – Unit Capital Cost Factors of NO X 

### Control Alternatives for MRY Station Unit 1 – Shared Facilities SCR Projects Table 4-4SA – Estimated Capital Costs for NO X 

### Control Alternatives - MRY Station Unit 1 – Stand Alone SCR Projects Table 4-4SF – Estimated Capital Costs for NO X 

### Control Alternatives - MRY Station Unit 1 – Shared Facilities SCR Projects Table 4-5SA – Estimated Capital Costs for Hypothetically–Applied SCR Alternatives - MRY Station Unit 1 – Stand Alone SCR Projects Table 4-5SF – Estimated Capital Costs for Hypothetically-Applied SCR Alternatives - MRY Station Unit 1 – Shared Facilities SCR Projects

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

### Control Alternatives – MRY Station Unit 1 – Stand Alone SCR Projects

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

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

### Controls Table C.4-2 – Expected Capacity Reductions for MRYS Unit 1 NO X 

### Controls Table C.4-3 – Expected Auxiliary Electrical Power Demand Changes for MRYS Unit 1 NO X 

### Controls Table C.4-4 – Expected Auxiliary Electrical Powe r Demand and Generation Reduction Cost Changes for MRYS Unit 1 NO X 

### Controls

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

### Control Alternatives– MRY Station Unit 1 – Stand Alone SCR Projects

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

### Control Alternatives– MRY Station Unit 1 – Shared Facilities SCR Projects

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

### Control Alternatives – MRY Station Unit 1 – Stand Alone SCR Projects

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

### Control Alternatives – MRY Station Unit 1 – Shared Facilities SCR Projects Table 4-9SA – Estimated Emissions and Economic Impacts Summary for NO X 

### Control Alternatives – MRY Station Unit 1 – Stand Alone SCR Projects Table 4-9SF – Estimated Emissions and Economic Impacts Summary for NO X 

### Control Alternatives – MRY Station Unit 1 –Shared Facilities SCR Projects Table 4-10 – Energy Impacts for NO X 

### Control Alternatives – MRY Station Unit 1Supplemental BACT Control and Cost -Effectiveness Table of Contents Analysis for MRY Station Unit 1 NOx Emissions

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

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

### Control Alternatives – MRY Station Unit 1 – Stand Alone SCR Projects Table 4-11SF – Summary of Supplemental BACT Analysis Impact Results for Dominant NO X 

### Control Alternatives – MRY Station Unit 1 – Shared Facilities SCR Projects



### LIST OF FIGURES

Figure 4-1SA – NO X 

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

### Control Cost Effectiveness – MRY Station Unit 1 – Shared Facilities SCR Projects Figure 4-2SA – MRY Station Unit 1 NO X 

### Control Alternatives BACT Dominant Controls Cost Curve – Stand Alone SCR Projects Figure 4-2SF – MRY Station Unit 1 NO X 

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



### INDEX TO REVISIONS

The following page numbers in the Fe bruary 2010 version include revisions: Page 4-20 Page 4-21 Page 4-26 Page 4-29 Page 4-30 Page 4-31 Page 4-32 Page 4-33 Page 4-34 Page 4-35 Page 4-36 Page 4-37 Page 4-39 Page 4-40 Page 4-43 Page 4-46 Page 4-47 Page 4-51 Page 4-52

* * * * *Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

### 4.0 SUPPLEMEN TAL NOx BACT ANALYSIS CONTROLS & COSTS – MRY STATION UNIT 1 This supplement to the NO X 

### BACT analysis for Milton R. Young Station (MRYS) Unit 1 has been prepared in response to the 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 1 includes ranking by effectiveness and providing 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 initial 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 1.

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 1. Site-sp ecific needs and challenges identified for applying tail end and low-dust SCR technologies to Milton R. Young Station Unit 1 significantly influence the capital cost estimate for variations of these hypothetical 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 1 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 h ypothetical applications of SCR configurations for which NDDH has requested economic analyses. Thus it was necessary to prepare independent sitespecific cost estimates.

The site-specific control costs estimated for hypo thetical application of tail-end and low-dust SCR alternatives to MRYS Unit 1 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 1 NOx Emissions

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

### Minnkota that it is technically feasible to install these technologies on Unit 1 at Milton R. Young Station. The rationale for rejection of all forms of SCR technol ogy in this specific case, based on an interpretation of the EPA’s Draft New Source Review Workshop Manual 10 

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

### and is not repeated herein. 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 t echnologies such as low-dust and tail end SCR systems at MRYS is based on preliminary plant layout design concepts that require pilot-scale slipstream SCR testing and more detailed equipment design for co nfirmation that all technical infeasibility issues previously raised have been, or can be, satisfactor ily resolved. This supplemental analysis includes estimated capital costs and operating and maintenance (O&M) costs for four variations of alternatives involving hypothetical applications of tail-end and low-dust SCR technologies. Cost effectiveness for each hypothetically-applied SCR control technology case was plotted with previously-analyzed feasible

control alternatives.

For the techniques and technologies considered for determining MRYS Unit 1 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 1 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, is being impl emented for operation starting prior to December 31, 2009. 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 2, October 1990.
11 See Reference number 5, November 2007.
12 Step 3 per the NSR Manual, Ibid Reference 2, October 1990.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

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

• MRYS Unit 1’s highest 12-month NO X 

### mass emissions averaged 0.849 lb/mmBtu at a corresponding average unit heat input rate of 2,744 mmBtu/hr and unit gross electrical output of

244.5 MW g 

### .

• During this lookback time period, Unit 1 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 Station cyclone boiler without incurring potential signif icant negative impacts of this technique. This level of expected NO X 

### reduction from ASOFA operation is appr oximately forty percent below the precontrol baseline emissions rate of 0.849 lb/mmBtu.

13 Ibid Reference number 3, October 2006, page 3-18.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

### TABLE 4-1 – Ranked NO X 

### Control Options for MRY Station Unit 1 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) 0.053 93.8 (4)

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

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

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

E SNCR (using urea) w/ ASOFA 0.355 58.1

D Gas Reburn with ASOFA 0.374 56.0
C Lignite Reburn w/ ASOFA 0.385 54.6

B Fuel Lean Gas Reburn with ASOFA 0.460 45.9
A Advanced Separated Overfire Air (ASOFA) 0.513 39.5

- Baseline 0.849 -

(1) - Alternative designation a ssigned from highest to lowest unit NOx emission rate. (2) - Control percentages are relative to an average pre-control emission baseline of 0.849 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 1 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 information for the hypothetical a pplication 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 antici pated long-term emission reducti on of 90% design removal from a baseline of 0.51 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 0.085 lb/mmBtu, for an overall reduction of 90 percent from a baseline of 0.849 lb/mmBtu.



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

achieve a NO X 

### emission level of 0.053 lb/mmBtu, which is approximately 90% reduction from a 0.51 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 1’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 1 NOx Emissions

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Minnkota Power Cooperative, Inc. 4-6 Burns & McDonnell 

### 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 hypotheticallyapplied SCR systems that exceed the ability to adjust operational practic es sufficiently to avoid forced outages to remove the deposits or prevent significan t 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 technolog y cases, along with the 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 1 and the emission reduction corresponding to each technology alte rnative 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 1 NOx Emissions_________________________________________________________________________________________________________________________________Minnkota Power Cooperative,Inc. 4-7 Burns & McDonnellTABLE 4-2 – Expected Annual NOXControl Performance for MRY Station Unit 1 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)0.053 145 589 9,345 93.8(7)T1 Hypothetical Tail End SCR w/ ASOFA– Scenario B(6)0.053 145 536 9,398 93.8(7)L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(6)0.053 145 586 9,348 93.8(7)L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(6)0.053 145 533 9,401 93.8(7)E SNCR (using urea) w/ ASOFA 0.355 975 4,025 5,909 58.1D Gas Reburn w/ ASOFA 0.374 1,025 4,275 5,659 56.0C Lignite Reburn w/ ASOFA 0.385 1,058 4,343 5,591 54.6B Fuel Lean Gas Reburn w/ ASOFA 0.460 1,261 5,260 4,674 45.9AAdvanced Separated Overfire Air (ASOFA)0.513 1,409 5,874 4,060 39.5- Baseline 0.849 2,330 9,934 0 -(1)- Alternative label has been assigned from highest to lowest unit NOx emission rate.(2)- Hourly NOXemission estimates (lb/hr) werecalculated based upon average annual unit emission rate (lb/mmBtu) x 2,744 mmBtu/hr heat input.(3)- Estimated annual emission tons assume an annual unit availability factor specific to each alternative; 97.3% was assumed forthe baseline case.See Appendix C3 of the October 2006 NOXBACT Analysis Study report.Hypothetical application of tail end SCR case T2 assumes anannual unit availability factor of92.8% (approx. 8,127 operating hours per year) and case T1 assumes an annual unit availability factor of 84.5% (approx. 7,402 operating hours per year).Hypothetically-applied low-dust SCR case L2 assumes an annual unit availability factorof 92.3% (approx. 8,084 operating hoursper year) and case L1 assumes anannual unit availability factor of 84.0%(approx. 7,359 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 0.849 lb/mmBtu emission baseline at 2,744 mmBtu/hr MCR heat input.(6)- The inclusion of tail-end and low dust SCR technologies in this table does not constitute agreement that itis technically feasible to install these technologies on Unit 1at 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 NOx BACT Analysis Study report and subsequentsubmittals 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 anticipatedlong-term emission reduction ofapproximately 90% design removal from a baseline of 0.51 lb/mmBturesulting from an advanced separated overfire air system, with air-staged low-NOXcyclone combustion. Withouta separated overfire air system operation or any othertechnique employed, the assumed emission rate for hypothetically-applied SCR alternatives would be 0.085 lb/mmBtu, for an overall reduction of 90 percent from abaseline of 0.849 lb/mmBtu.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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Minnkota Power Cooperative, Inc. 4-8 Burns & McDonnell 

### 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 for an installed advanced separated overfire air system, or firm price equipment quotes with performance guarantees for
SNCR alternatives, have not been used to adjust the control effectiveness or cost impacts of the previously analyzed control alternatives. The approach taken in this supplemental analysis use installed capital costs estimated in calendar year 2009 escalated to project completion forecast in 2018 adjusted to calendar year 2006 basis for the hypothetically-applied tail end S CR 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 1
An evaluation was performed to determine the various cost impacts of installing previously-analyzed

feasible NO X 

### control alternatives and the hypothetical application of low-dust and tail end SCR technologies on Milton R. Young Unit 1. This evaluation includes estimated:

• Capital costs;

• Fixed and variable operating and maintenance costs; and

• Levelized total annual costs to engineer, design, procure, construct, install, 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 1 NOx Emissions

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Minnkota Power Cooperative, Inc. 4-9 Burns & McDonnell 

### 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 1, 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 1. 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 257 MW g 

### for MRY Station Unit 1 16



### .

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

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 1 SCR (tail end or low-dust) system would be accounted for as if the SCR equipment were being provided for Unit 1 only.
This is referred to as the “stand alone” (SA) case, and all tables showing those costs are identified with that
suffix. In the other case, it was assumed that the 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 1 NOx Emissions

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 4-10 Burns & McDonnell 

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

### . The “stand alone” estimated total project capital costs for the hypothetical application of SCR alternatives reflect the economic impacts incurred as a result of implementing 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 projec t 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 1 - Stand Alone SCR Projects

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

MRYS Unit 1 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) (4) 867 (4),(5)
T1 Hypothetical Tail End SCR w/ ASOFA –Scenario B (4) (4) 867 (4),(5)
L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) (4) 703 (4),(5)
L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) (4) 703 (4),(5)

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

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

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

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

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

(1) - Alternative designation has been assigned from highest to lowest uni t 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. Singl e point cost figures in 2006 dollars. (4) - The inclusion of tail-end and low dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 1 at Milton R. 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 1 NOx Emissions

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 4-11 Burns & McDonnell infeasibility for installation of the SCR equipment on this boiler are solvable. SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 NOx BACT Analysis Study report and subsequent submittals in response to comments by 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 assume replacement of SCR catalyst after 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 $150/kW. Single point unit capital cost factors were derived from Burns & McDonnell internal database and cost estimates prepared specifically for MRYS Unit 1 in 2018 dollars co nverted to 2006$ 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 91.7 $/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 1 – Shared Facilities SCR Projects

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

MRYS Unit 1 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) (4) 706 (4),(5)
T1 Hypothetical Tail End SCR w/ ASOFA –Scenario B (4) (4) 706 (4),(5)
L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) (4) 543 (4),(5)
L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) (4) 543 (4),(5)

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

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

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

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

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

18 See Reference number 6, March 2005, page 3-63.
19 See Reference number 3, October 2006, pages C2-3 and C2-7.
20 See Reference number 7, March 2005.
21 See Reference number 8, April 2005, page 3-9.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 4-12 Burns & McDonnell (1) - Alternative designation has been assigned from highest to lowest unit NOx emission rate. (2) - Unit capital cost factors ($/kW) of these individual 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 SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 1 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 application at MRYS per the October 2006 NOx 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 assume replacement of SCR catalyst after 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 $150/kW. Single point unit capital cost factors were derived from Burns & McDonnell internal database and cost estimates prepared specifically for MRYS Unit 1 in 2018 dollars co nverted to 2006$ 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 91.7 $/kW. See technical references in Appendix A1 of the October 2006 BACT Analysis report for details.



### 4.2.1.1.1 CAPITAL COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF SCR 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 properly represent total installed costs that could be expected for MRYS Unit 1. Site-specific needs and challenges identified for applying tail end and low-dust SCR technologies to M ilton R. Young Station Unit 1 significantly influence the capital cost estimate for variations of these hypothe tically-applied SCR alternatives. Furthermore, the “EPA Air Pollution Control Cost Manual” is not appli cable for use in estimating control equipment costs for these hypothetical applications of SCR technol ogy cases, as the EPA Control Cost Manual states:

22 See Reference number 6, March 2005, page 3-63.
23 See Reference number 3, October 2006, pages C2-3 and C2-7.
24 See Reference number 7, March 2005.
25 See Reference number 8, April 2005, page 3-9.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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Minnkota Power Cooperative, Inc. 4-13 Burns & McDonnell 

### “The costs for the tail-end arrangement, however, cannot be estimated from this report because they are significantly higher than the high-dust SCR sy stems due to flue gas reheating requirements.” 26



### This requirement for flue gas reheating also appli es to the hypothetical applications of low-dust SCR technology to MRYS, due to the cold-side arrangeme nt (downstream of the electrostatic precipitator)

instead of a hot-side ESP assumed in the EPA Control Co st Manual. Therefore, the equations in the EPA Control Cost Manual cannot be used for estimating either of the hypothetical application of SCR configurations for which NDDH has requested economic analyses. Thus it was necessary to prepare independent site-specific cost estimates.

The installed capital costs for hypothetical 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 hypothetically-applied low-dust and tail end SCR designs for MRYS Unit 1 assume one reactor / gas reheat system in stalled, connecting to the new wet lime flue gas desulfurization absorber currently being constructed. Each hypothetically-applied SCR alternative includes flue gas reheat equipment that is typical for th ese applications but not re quired for conventional highdust/hot side SCR systems. The estimated flue gas vo lume at a gross boiler heat input and oxygen content corresponding to unit gross nameplate output capacity determined the size of the hypothetically-applied single SCR reactor for these cases. Structures, found ations, ductwork, balance of plant equipment and materials were quantified and includ ed with the hypothetically-applied SCR equipment, which were factored for installation costs. Escalation of project costs, including equipment, materials, engineering and labor costs, is included, along with interest duri ng 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 curre nt preliminary design scope and pricing fully reflects what would be necessary to complete im plementation of these hypothetically-applied alternatives. Total project costs were considered to be a future value fro m 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 1 NOx Emissions

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Minnkota Power Cooperative, Inc. 4-14 Burns & McDonnell 

### The estimated installed and levelized annual capital costs for the hypothetically-applied SCR systems and previously-analyzed highest-performing form of the various feasible 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 1 - Stand Alone SCR Projects

Alt. Label (1) NOx Control Alternative Installed Capital Cost (2) $1,000 Annualized Capital Cost (3) $1,000 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) 222,864 (4) 19,430 (4)
T1 Hypothetical Tail End S CR w/ ASOFA – Scenario B (4) 222,864 (4) 19,430 (4)
L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 180,739 (4) 15,758 (4)
L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) 180,739 (4) 15,758 (4)

E SNCR w/ ASOFA 8,113 707

D Gas Reburn w/ ASOFA (5) 18,006 1,570 C Lignite Reburn w/ ASOFA (6) 46,656 4,068

B Fuel Lean Gas Reburn w/ ASOFA (5) 10,639 928
A Advanced SOFA (ASOFA) 4,277 373

Baseline 0 0

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 257 MWg unit 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 1 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 1 in 2018 dollars converted to 2006$ as described in the text. SCR technology is considered technically infeasible by Minnkota for application at MRYS per the October 2006 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 $8,075,000 for CGR and $4,038,000 fo r FLGR; and annualized capital cost of $704,000/yr for CGR and $352,000 for FLGR. See footnote number 8 under Table 4-3SA. (6) - Costs for increased PM collecti on capacity included in lig nite reburn option are $23,561,000 for installed capital cost, and $2,054,000/yr annualized capital cost.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

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

### Control Alternatives - MRY Station Unit 1 – Shared Facilities SCR Projects

Alt. Label (1) NOx Control Alternative Installed Capital Cost (2) $1,000 Annualized Capital Cost (3) $1,000 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) 181,484 (4) 15,823 (4)
T1 Hypothetical Tail End S CR w/ ASOFA – Scenario B (4) 181,484 (4) 15,823 (4)
L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 139,639 (4) 12,174 (4)
L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) 139,639 (4) 12,174 (4)

E SNCR w/ ASOFA 8,113 707

D Gas Reburn w/ ASOFA (5) 18,006 1,570 C Lignite Reburn w/ ASOFA (6) 46,656 4,068

B Fuel Lean Gas Reburn w/ ASOFA (5) 10,639 928
A Advanced SOFA (ASOFA) 4,277 373

Baseline 0 0

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Installed capital cost is estimated for determination of total capital cost for a particular technology or combination, assuming 257 MWg unit 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 1 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 1 in 2018 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 $8,075,000 for CGR and $4,038,000 fo r FLGR; and annualized capital cost of $704,000/yr for CGR and $352,000 for FLGR. See footnote number 8 under Table 4-3SF. (6) - Costs for increased PM collecti on capacity included in lig nite reburn option are $23,561,000 for installed capital cost, and $2,054,000/yr annualized capital cost.



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

MRYS Unit 1 are shown in Table 4-5SA and Ta ble 4-5SF in 2018, 2009, and 2006 dollars.

The estimated installed capital costs for the hypothetical application of tail end or low-dust SCR system retrofits on MRYS Unit 1 included the following equipment and components:Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### • One SCR reactor utilizing a “3 +1” arrangement of cat alyst layers, in which three layers of catalyst are initially installed, and space for insta llation 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 1 NOx Emissions

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 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 1 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 Alternat ives - MRY Station Unit 1 Stand Alone SCR Projects

Alt. Label (1) Hypothetical SCR Alternative (2) Estimated BMcD Study Total Project Cost (3)
, 2018$ x 1000 Estimated BMcD Study

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

Adjusted TP Cost (5)
, 2006$ x 1000 T2, T1 Tail End SCR 294,586 235,884 214,221
Urea preparation and storage, building, and equipment (6) _ 4,808 (6) 4,366 (6)

ASOFA _ _ 4,277
T2, T1 TOTAL _ _ 222,864 (6)

L2, L1 Low-Dust SCR 236,658 189,499 172,096 Urea preparation and storage, building, and equipment _ 4,808 (6) 4,366 (6)

ASOFA _ _ 4,277
L2, L1 TOTAL _ _ 180,739 (6)

(1) All SCR alternatives are assumed to have the same SCR outlet NOx emission rate. (2) The inclusion of tail end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 1 at Milton R. Young Station. (3) The Total Project Cost shown for each hypothetically-applied SCR system was estimated by Burns & McDonnell based on scope assumptions for installation of the SCR equipment on this boiler as described in the text, except as described in 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. S ee Section 4.2.1.2.1 for details of Scenario A and Scenario B that assume replacement of SCR catalyst after a specified number of hours of unit operation. Does not in clude installed capital cost for AS OFA, as shown in Table 4-4SA. (4) Modified Total Project Costs are converted from 2018$ to 2009$ as described in the text, except as described in footnote 6 below. Present Value factor (discounted from future value) is 0.80073. (5) Adjusted Total Project Costs are converted from 2009$ to 2006$ as described in the text. Handy-Whitman Index of Public Utility Construction Costs ratio is 0.908. (6) Urea preparation and storage, building, and equipment 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 storage, building, and equipment; and To tal Installed Capital Costs (TICC) for ASOFA alternative = estimated TICC for the hypothet ically-applied SCR alternatives in Table 4-4SA.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

### TABLE 4-5SF – Estimated Capital Costs for Hypothetically-Applied SCR Alternat ives - MRY Station Unit 1 Shared Facilities SCR Projects

Alt. Label (1) Hypothetical SCR Alternative (2) Estimated BMcD Study Total Project Cost (3)
, 2018$ x 1000 Estimated BMcD Study

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

Adjusted TP Cost (5)
, 2006$ x 1000 T2, T1 Tail End SCR 240,817 192,829 175,120 Urea preparation and storage, building, and equipment (6) _ 2,298 (6) 2,087 (6)

ASOFA _ _ 4,277
T2, T1 TOTAL _ _ 181,484 (6)

L2, L1 Low-Dust SCR 183,274 146,753 133,275 Urea preparation and storage, building, and equipment (6) _ 2,298 (6) 2,087 (6)

ASOFA _ _ 4,277
L2, L1 TOTAL _ _ 139,639 (6)

(1) All alternatives are assumed to have the same SCR outlet NOx emission rate. (2) The inclusion of tail end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 1 at Milton R. Young Station. (3) The Total Project Cost shown for each hypothetically-applied SCR system was estimated by Burns & McDonnell based on scope assumptions for installation of the SCR equipment on this boiler as described in the text, except as described in footnote 6 below. SCR technology is considered technicall y infeasible by Minnkota for application at MRYS per the October 2006 NO X BACT Analysis Study report and subsequent submittals in respons e to comments by the NDDH, EPA, DOJ, and other parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assume replacement of SCR catalyst after a specified number of hours of unit operation. Does not include installed capital cost for ASOFA, as shown in Table 4-4SF. (4) Modified Total Project Costs are converted from 2018$ to 2009$ as described in the text, except as described in footnote 6 below. Present Value factor (discounted from future value) is 0.80073. (5) Adjusted Total Project Costs are converted from 2009$ to 2006$ as described in the text. Handy-Whitman Index of Public Utility Construction Costs ratio is 0.908. (6) Urea preparation and storage, building, and equipment installe d capital costs were estimated separately in 2009$, and then adjusted using the Handy-Whitman cost ratio of 0.908 to get 2006$. The TOTAL numbers above are the sum of the Adjusted Total Project Cost; urea preparation and storage, build ing, and equipment; and Total Installed Capital Costs (TICC) for ASOFA alternative = estimated TICC for the hypot hetically-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 1 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 published in technical papers discussing those control technologies. Maintenance costs were estimated as

27 See Reference number 9, October 2000.
28 See Reference number 10, October 2000.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

### 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 an d unit cost for 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 96.6 percent
(based on a historic (demonstrated) sust ainable unit output capacity of 253 MW g 

### ) combined with a 12- month rolling average availability (uptime) of 8,528 op erating hours (97.3 percent of 8760 hours per year) resulting in an equivalent annual average unit capac ity factor of 94.1% was assumed for Unit 1’s precontrol baseline annual operation. A 12-month rolling average heat input rate of 2,744 mmBtu/hr and a 12- month rolling average NO X 

### emission rate of 0.849 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 1.

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 of previously-evaluated feasible NO X 

### emission reduction technologies. Th ese are listed in order of controlSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

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

C3 of the 2006 NO X 

### BACT Analysis Study report provides 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 Stati on Unit 1 - Stand Alone SCR Projects

Alt. Label (1) NOx Control Alternative Annual O&M Cost (2) $1,000 Levelized Annual O&M Cost (2),(3) $1,000 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) 20,048 25,034 T1 Hypothetical Tail End S CR w/ ASOFA – Scenario B (4) 29,361 36,664 L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 18,332 22,891 L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) 29,178 36,435
E SNCR w/ ASOFA 5,417 6,764
D Gas Reburn w/ ASOFA 28,641 35,765 C Lignite Reburn w/ ASOFA (5) 5,862 7,320
B FLGR w/ ASOFA 12,863 16,062
A Advanced SOFA (ASOFA) 1,695 2,117

Baseline 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Annual operating and maintenance cost for a particular technology or combin ation is compared to unit baseline operation at an average unit output (244. 5 MWg) and assumes a 97.3% average annual availability, which is highest consecutive 12-months of operation from 2001-2005. All cost figures in 2006 dollars. Revised February, 2010. (3) - Levelized annual O&M cost = Annual O&M cost x 1. 24873 annualized O&M cost factor. Rev. Feb. 2010. (4) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install thes e technologies on Unit 1 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 estimates specific to MRYS Un it 1 in 2018 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 assume 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 $2,024,000/yr for annual O&M cost, and $2,527,000/yr annualized O&M cost.

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

_____________________________________________________________________________________________

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

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

### Control Alternatives - MRY Station Unit 1 – Shared Facilities SCR Projects

Alt. Label (1) NOx Control Alternative Annual O&M Cost (2) $1,000 Levelized Annual O&M Cost (2),(3) $1,000 T2 Hypothetical Tail End S CR w/ ASOFA – Scenario A (4) 18,806 23,484 T1 Hypothetical Tail End S CR w/ ASOFA – Scenario B (4) 28,120 35,114 L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (4) 17,099 21,352 L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (4) 26,483 33,070
E SNCR w/ ASOFA 5,417 6,764
D Gas Reburn w/ ASOFA 28,641 35,765 C Lignite Reburn w/ ASOFA (5) 5,862 7,320
B FLGR w/ ASOFA 12,863 16,062
A Advanced SOFA (ASOFA) 1,695 2,117

Baseline 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Annual operating and maintenance cost for a particular technology or combin ation is compared to unit baseline operation at an average unit output (244. 5 MWg) and assumes a 97.3% average annual availability, which is highest consecutive 12-months of operation from 2001-2005. All cost figures in 2006 dollars. Revised February, 2010. (3) - Levelized annual O&M cost = Annual O&M cost x 1. 24873 annualized O&M cost factor. Rev. Feb. 2010. (4) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install thes e technologies on Unit 1 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 estimates specific to MRYS Un it 1 in 2018 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 assume 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 $2,024,000/yr for annual O&M cost, and $2,527,000/yr annualized O&M cost.



### 4.2.1.2.1 O&M COST ESTIMATES FOR HYPOTHETICAL APPLICATION OF SCR 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 1. The system uses an amine reagent in the form of concentrated aqueous urea solution, which is thermally converted to gaseous ammonia, carbon dioxide, and water vapor. The 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 as

established for the 2006 NO X 

### BACT Analysis Study report). Cons umption of urea converted to ammonia reagent was based upon recent equipment vendor budge tary proposals and SCR consultant inputs.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### For the hypothetically-applied SCR cases, using the existing induced draft fans is not expected to significantly change the overall fan horsepower demand on those fans’ electric motors. There will be new plant electrical power demand due to a new induced draft booster fan required to overcome the estimated additional flue gas pressure drop resulting from reactor, ductwork, and gas-to-gas heat exchanger equipment assumed for the hypothetically-applied SCR systems. The additional auxiliary electric power demand for the hypothetically-applied tail end SCR systems was calculated to be 9.7 MW, using estimated annual average electrical loads of the booster fan, direct flue gas reheat burner combustion air fan, urea-toammonia conversion dilution/combustion air fan, and SCR sootblower and service air compressor equipment based on preliminary equipment vendor budgetary proposals developed from Burns & McDonnell ductwork sizing and designs. Estimated annual average electrical power demands for hypothetically-applied low-dust SCR systems were calcul ated to be 8.0 MW. Replacement of electrical power resulting from these reductions in net unit electrical output was included as a cost, assuming $35 per megawatt-hour.

Hypothetically-applied tail end and low-dust SCR equipment requiring annual maintenance includes booster fan, gas-to-gas heat exchangers, flue gas reh eat duct burners, and compre ssor 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 installed unit cost of replacement catalyst assumed for the hypothetical application of full-time tail end or low-dust SCR alternatives is $7,500 per cubic meter in 2006 dollars. The basis for development of the two scenarios is described below.

During preparation of the cost estimate, Burns & McDonnell consulted with two SCR catalyst vendors experienced with biomass-fired boiler SCRs and 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-scale slipstream testing that confirm the deactivation and fouling rates. According to these catalyst suppliers, there is no SCR operating experience in the world found to be directly comparable to the hypothetically-Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### applied tail end and low-dust SCR cases on North Dakot a lignite-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 slipstream te sting had been completed. This led Burns & McDonnell to develop two hypothetically -applied SCR catalyst replacement scenarios to bracket possible outcomes.

Scenario A assumed a hypothetically-applied catalyst replacement schedule of 16,000 hours. Specifically for MRYS Unit 1, this scenario is based on the repl acement of one catalyst layer every 16,000 operating hours (essentially every two years of operation).

Scenario B assumed that the fouling of the catalyst would be severe, and that it would be necessary for Minnkota to perform catalyst maintenance at each sche duled boiler cleaning outage. The current schedule of boiler cleaning outages on Unit 1 is three times per y ear. Therefore, Scenario B for Unit 1 is based on the replacement of one catalyst layer at each boiler cl eaning outage. This means that each catalyst layer in the four layer SCR reactor is exposed to flue gas dur ing approximately 16 months of operation and then is replaced. By assuming that catalyst management activ ities 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 freque ncy of catalyst 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 146 cubic meters per layer per reactor for the single reactor. A fourth ( bottom) layer at 195 cubic meters is expected to be required after initial operation of hypothetically-applied full-time tail end or low-dust SCR alternatives, asSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### part of the catalyst replacement program. Catalyst re placement 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 213 hours per year was estimated to be attr ibutable to the hypothetical application of tail end SCR Scenario A alternative (assuming 16,000 hour catal yst life), and 938 hours per year for Scenario B TESCR case (assuming three layers are replaced every year) over and above the hours per year of outage time assumed for ASOFA impacts. Additional outage time of 256 hours per year was estimated to be attributable to the hypothetical application of low-dust SCR Scen ario A alternative, and 981 hours per year for the Scenario B LDSCR case over and above outage time assu med for ASOFA impacts. The expected loss of electrical power generation from these reductions in net output was included as a cost, assuming $35 per megawatt-hour for replacement power.

Table C.4-1 provides the estimated unit availability and corresponding operating time and outage time due to the four hypothetically-applied SCR technolog y 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 1 NOx Emissions

_____________________________________________________________________________________________

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

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

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (6) 0.845 7402 1358 1126

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (6) 0.923 8084 676 444

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (6) 0.840 7359 1401 1169

E SNCR w/ ASOFA 0.942 8255 505 273

D Gas Reburn w/ ASOFA 0.952 8340 420 188

C Coal Reburn w/ ASOFA 0.937 8212 548 316

B FLGR w/ ASOFA 0.952 8340 420 188
A Advanced SOFA (ASOFA) 0.952 8340 420 188

Baseline 0.973 8528 232 0

(1) – Alternative number has been pr eviously assigned from least removal to highest removal percentage. (2) – 12-month baseline availabilit y is assumed at 97.3 percent. These va lues 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 1 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 th e NDDH, EPA, DOJ, and other parties, so this information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation.



### Table C.4-2 includes estimated equivalent 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 C3-12.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

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

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (5) 0.937 275,168,784 9,631

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (5) 0.942 108,399,824 3,794

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (5) 0.942 285,591,844 9,996 (6)

E SNCR w/ ASOFA 0.965 67,660,606 2,368
D Gas Reburn w/ ASOFA 0.957 46,120,681 1,614 C Lignite Reburn w/ ASOFA 0.961 77,958,350 2,729
B FLGR w/ ASOFA 0.962 46,400,200 1,624
A Advanced SOFA (ASOFA) 0.966 46,586,546 1,631

Baseline 0.966 0 0

(1) - Alternative designation has been previously assigned from least removal to high est removal percentage. (2) - 12-month baseline running plant capacity ratio is assumed at 96.6 percent (= 244.4/253.0). Thes e values reflect estimated amounts of negative annual ou tput capacity impact expected from th e implementation of the individual NOx control technique. Used only for calcula tion of annual power usage in Table C.4-3. (3) - Annual electricity generation reduction is annual unit operating time reduction multiplied by the 12-month average gross output of 244.4 MW. (4) - Annual electricity generati on reduction cost is the annual electricity generation reducti on (kW-hrs/yr) resulting from the implementation of the individual NOx control technique multiplied by the incremental value of electricity generation, assumed to be $35.00/MW-hr. All cost figures in 2006 dollars. (5) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these t echnologies on Unit 1 at Milton R. Young Station. The es timated annual unit running plant capacity factors shown for hypothetically-appl ied SCR systems are based on assumptions that known or expected reasons for technical infeasibility for installation and operation and ma intenance of the SCR equipment on this boiler are solvable. SCR technology is considered te chnically infeasible by Minnkot a 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 th is information for the hypothetical a pplication of SCR alternativ es 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. (6) Unit Generation Reduction for low-dust SCR Scenario B was $11 ,940,000. It should be s hown as $9,996,000 instead. This does not affect economics s hown in subsequent tables and graphs. Revised February, 2010.



### 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 1 NOx Emissions

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 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 1 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) 9,685 0 9,685 73,768,605 2,582

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (7) 9,685 0 9,685 67,189,753 2,352

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (7) 8,012 0 8,012 61,018,532 2,136

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (7) 8,012 0 8,012 55,548,184 1,944
E SNCR w/ ASOFA 73.1 0 73.1 582,411 20
D Gas Reburn w/ ASOFA 1 133 (132) (1,054,343) (37) C Lignite Reburn w/ ASOFA 4,666 261 4,405 11,905,082 1,217
B FLGR w/ ASOFA 1 73 (72) (578,744) (20)
A Advanced SOFA (ASOFA) 1 0 1 8,058 0.3

(1) - Alternative designation has been previously assigned from least removal to 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 dema nds may differ from this due to positive or negative synergistic effects. Coal reburn includes 1,507 kW for feed preparat ion and conveying equipment demand plus 3,158 kW for the COHPAC system addition for PM control. (3) - The APC NOx equipment auxiliary electrical power demand credit of coal reburn alternatives is the estimated result of lower cyclone coal preparation and feeder power demand due to lower boiler cyclone coal equipment lo ading. Actual power demands may differ from this due to accuracy of estimates fo r 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 multip lied by the estimated annual operating time and running plant capacity ratio which reflects the adjustment for any expected availability and ca pacity impacts from the implementa tion 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 1 at Milton R. Young Station. The estim ated power demands shown for hypothetically-applied SCR syst ems are based on Burns & McD onnell estimates deve loped from preliminary equipment and ductwork sizing and designs with vendor bud getary proposals. SCR technology is c onsidered technicall y 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 information for the hypothetical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation.

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

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 4-28 Burns & McDonnell 

### Table C.4-4 includes estimated net unit electrical annual power usage (kW-hrs per year) and expected reductions in annual operating time to calculate unit ge neration reductions due to the four hypotheticallyapplied SCR cases, along with the ASOFA numbers fro m 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 b ecause of electrical power usage and reductions in annual operating time and capacity associat ed with the control alternatives.



### TABLE C.4-4 – Expected Auxiliary El ectrical Power Demand and Generation Reduction Cost Changes for MRY Unit 1 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) 73,768,605 97,976,764 171,745,369 6,011

T1 Hypothetical Tail End SCR w/ ASOFA –Scenario B (6) 67,189,753 275,168,784 342,358,537 11,983

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (6) 61,018,532 108,399,824 169,418,356 5,930

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (6) 55,548,184 285,591,844 341,140,028 11,940
E SNCR w/ ASOFA 582,411 67,660,606 68,243,017 2,389
D Gas Reburn w/ ASOFA (1,054,343) 46,120,681 45,066,338 1,577 C Lignite Reburn w/ ASOFA 11,905,082 77,958,350 89,863,432 3,946
B FLGR w/ ASOFA (578,744) 46,400,200 45,821,456 1,604
A Advanced SOFA (ASOFA) 8,058 46,586,546 46,594,605 1,631

(1) - Alternative designation has been previously assigned from least removal to 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 multip lied by the estimated annual operating time and running plant capacity ratio which reflects the adjustment for any expected availability and ca pacity impacts from the implementa tion of the control technique. (3) - Annual electricity generation reduction is annual operating ti me reduction multiplied by the 12-month average gross output of 244.4 MW. (4) - The total unit electrical power generation change is the sum of the annual change in APC NOx equipment auxiliary electrical power demand electricity usage plus the annual electricity generation reduction resulting from the implementation of the individual NOx control alternative. (5) - The total unit electrical power generation change cost is th e total generation change (kw-hrs/yr) multiplied by the incremen tal value of electricity generation, assumed to be $35 .00/MW-hr. All cost figures in 2006 dollars. (6) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitu te agreement that it is technically fe asible to install these technologies on Unit 1 at Milton R. Young Station. The estimate d power demand shown for hypothetically-

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

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 4-29 Burns & McDonnell applied SCR systems are based on Burns & McDonnell estim ates developed from preliminar y equipment and ductwork sizing and designs with vendor budgetary proposals. SCR technology is considered technica lly 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, and other parties, so this information for the hypothe tical application of SCR alternatives is included for comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation.



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

### CONTROLS A comparison of the control versus cost-effectiven ess of four hypothetically-applied SCR cases and previously-analyzed feasible NO X 

### control alternatives on Milton R. Young Unit 1 was made. This is
summarized as shown in Tables 4-7SA and 4-7SF, Fi gures 4-1SA and 4-1SF, and Figures 4-2SA and 4-2SF

for MRY Station Unit 1.



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

### Control Alternatives - MRY Stati on Unit 1 - Stand Alone SCR Projects

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

Tons/yr Annual NOx Emissions Reduction (3)

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

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (6) 589 9,345 44,465 4,758

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (6) 536 9,398 56,095 5,969

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (6) 586 9,348 38,649 4,134

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (6) 533 9,401 52,193 5,552
E SNCR w/ ASOFA 4,025 5,909 7,472 1,265
D Gas Reburn w/ ASOFA 4,275 5,659 37,334 (7) 6,597 C Lignite Reburn w/ ASOFA 4,343 5,591 11,388 (8) 2,037
B FLGR w/ ASOFA 5,260 4,674 16,990 (7) 3,635
A Advanced SOFA (ASOFA) 5,874 4,060 2,489 613
Baseline 9,934 0 0

(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Estimated annual emission tons assume an annual unit uptime availa bility factor specific to ea ch alternative; 9,934 (= 0.973*8760*2,330/2000) 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, hourly heat input, and annual hrs/yr operation compared to pre-control baseline emissions based on annual operation at baseline pre-control NOx emission rate. Revised February, 2010. (5) - Average Control Cost Effectiveness ($/ton) is the Leveli zed Total Annual Cost ($/yr) divided by Annual Emission Reduction (tons/yr). All cost figures in 2006 dollars. Revised February, 2010.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 4-30 Burns & McDonnell

(6) - The inclusion of tail-end and low-dust S CR technologies in this table does not cons titute agreement that it is technically feasible to install these t echnologies on Unit 1 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 boiler are solvable. Costs are derived from Burns & McDonnell internal database and cost estimates specifi cally for MRYS Unit 1 in 2006 dollars. 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 co mments by the NDDH, EPA, DOJ, a nd 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. (7) - LTAC for gas reburn options include high- pressure natural gas supply pipeline a nnualized capital cost of $704,000/yr for CGR and $352,000 for FLGR. See footnote number 8 under Table 4-3SA. (8) - LTAC for increased PM collection capacity included in ligni te reburn option are approximate ly $2,054,000 for annualized capital cost plus $2,527,000/yr for annualized O&M cost, for a LTAC subtotal of $4,581,000/yr.



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

### Control Alternatives - MRY Station Unit 1 - Shared Facilities SCR Projects

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

Tons/yr Annual NOx Emissions Reduction (3)

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

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (6) 589 9,345 39,307 4,206

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (6) 536 9,398 50,937 5,420

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (6) 586 9,348 33,526 3,586

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (6) 533 9,401 45,244 4,813
E SNCR w/ ASOFA 4,025 5,909 7,472 1,265
D Gas Reburn w/ ASOFA 4,275 5,659 37,334 (7) 6,597 C Lignite Reburn w/ ASOFA 4,343 5,591 11,388 (8) 2,037
B FLGR w/ ASOFA 5,260 4,674 16,990 (7) 3,635
A Advanced SOFA (ASOFA) 5,874 4,060 2,489 613
Baseline 9,934 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. (2) - Estimated annual emission tons assume an annual unit uptime availa bility factor specific to ea ch alternative; 9,934 (= 0.973*8760*2,330/2000) 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, control percentage, hourly heat input, and annual hrs/yr operation compared to pre-cont rol baseline emissions based on annual operation at baseline pre-control NOx em ission rate. Revised February, 2010. (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. Revised February, 2010. (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 1 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 forSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 4-31 Burns & McDonnell technical infeasibility for installation of the SCR equipment on this boiler are solvable. Costs are derived from Burns & McDonnell internal database and cost estimates specifi cally for MRYS Unit 1 in 2006 dollars. SCR technology is considered technically infeasible by Minnkota for application 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. (7) - LTAC for gas reburn options include high-pressure natura l gas supply pipeline annualized capital cost of $704,000/yr for CGR and $352,000 for FLGR. See footnote number 8 under Table 4-3SF. (8) - LTAC for increased PM collection capacity included in lignite reburn option are a pproximately $2,054,000 for annualized capital cost plus $2,527,000/yr for annuali zed O&M cost, for a LTAC s ubtotal of $4,581,000/yr.



### Figure 4-1SA – NO X 

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

### Stand Alone SCR Projects

Milton R. Young Station Unit 1 NOx Control Annual Removal vs Levelized Total Annual Cost - Stand Alone Projects

0 10000 20000 30000 40000 50000 60000

0 2000 4000 6000 8000 10000 Annual NOx Removal, tons/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/ AOSFA E = SNCR w/ ASOFA T1 = Hypothetical Tail-End SCR w/ ASOFA (Scenario B) T2 = Hypothetical Tail-End SCR w/ ASOFA (Scenario A) L1 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario B) L2 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario A)

A B

E C D T1

T2 L1

L2

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

. (2) - The inclusion of tail-end and low-dust S CR technologies in this figure does not cons titute agreement that it is technically feasible to install these t echnologies on Unit 1 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 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 purposes only. See Section 4.2.1. 2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### Figure 4-1SF – NO X 

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

### Shared Facilities SCR Projects

Milton R. Young Station Unit 1 NOx Control Annual Removal vs Levelized Total Annual Cost - Shared Facilities Projects

0 10000 20000 30000 40000 50000 60000

0 2000 4000 6000 8000 10000 Annual NOx Removal, tons/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/ AOSFA E = SNCR w/ ASOFA T1 = Hypothetical Tail-End SCR w/ ASOFA (Scenario B) T2 = Hypothetical Tail-End SCR w/ ASOFA (Scenario A) L1 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario B) L2 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario A)

A B

E C D L1

T2

L2 T1

(1) - All cost figures in 2006 dollars. Numbers are listed and qualifiers are noted in Table 4- 7SF. Revised February, 2010. (2) - The inclusion of tail-end and low-dust S CR technologies in this figure does not cons titute agreement that it is technically feasible to install these t echnologies on Unit 1 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 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 purposes only. See Section 4.2.1. 2.1 for details of Scenario A and Scenario B that assumes replacement of SCR catalyst after a specified number of hours of unit operation.



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

### control alternatives on Milton R. Young Unit 1

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.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

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

alternatives”. The dominant controls cost curve is 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 Stati on Unit 1 - Stand Alone SCR Projects

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

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

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

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (5) 44,465 9,345 36,993 3,437 10,765

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (5) 56,095 9,398 48,623 3,489 13,936

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (5) 38,649 9,348 31,777 3,440 9,064

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (5) 52,193 9,401 44,721 3,492 12,806

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

A Advanced SOFA (ASOFA) 2,489 4,060 2,489 4,060 613
(1) - Alternative label has been assigned from 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 4-7SA, and on the graphs that accompany this table (Points B, C, and D were eliminated). (2) - All cost figures in 2006 dollars. Revised February, 2010. (3) - Annual emission reduction and leve lized control cost of these a lternatives is relative to cu rrent costs and pre-control unit MCR baseline emission rate . Revised February, 2010. (4) - Increment based upon comparison between consecutive alternativ es (points) from lowest to highest. Revised February, 2010. (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 1 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 informati on 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 assumes replacement of SCR cataly st after a specified number of hours of unit operation. Revised February, 2010.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

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

### Control Alternatives - MRY Station Unit 1 - Shared Facilities SCR Projects

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

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

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

T2 Hypothetical Tail End SCR w/ ASOFA – Scenario A (5) 39,307 9,345 31,835 3,437 9,264

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (5) 50,937 9,398 43,465 3,489 12,458

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (5) 33,526 9,348 26,054 3,440 7,575

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B (5) 45,244 9,401 37,772 3,492 10,816

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

A Advanced SOFA (ASOFA) 2,489 4,060 2,489 4,060 613
(1) - Alternative label has been assigned from 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. Revised February, 2010. (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. Revised February, 2010. (4) - Increment based upon comparison between consecutive alternativ es (points) from lowest to highest. Revised February, 2010. (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 1 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 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 specified numbe r of hours of unit operation. Revised February, 2010.



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

### control information from Figures 4-1SA and 4-1SF for MRY Sta tion Unit 1, with Point B (FLGRTM with ASOFA) , Point C (Lignite Reburn with ASOFA) and Point D (c onventional gas reburn with ASOFA) removed. This

is the dominant controls cost curve for MRY Station Unit 1 NO X 

### emissions alternatives.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### Figure 4-2SA – MRY Station Unit 1 NO X 

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

### - Stand Alone SCR Projects

Milton R. Young Station Unit 1 NOx Control Dominant Controls Cost Curve - Stand Alone Projects

0 10,000 20,000 30,000 40,000 50,000 60,000

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000
Annual NOx Removal, tons/yrLevelized Total Annual Cost for NOxControl, 1000$/yr

E $10,765/ton

$9,064 /ton Slope = incremental $/ton

$13,936/ton

$2,694/ton A = Advanced SOFA E = SNCR w/ ASOFA T1 = Hypothetical Tail-End SCR w/ ASOFA (Scenario B) T2 = Hypothetical Tail-End SCR w/ ASOFA (Scenario A) L1 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario B) L2 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario A) (Points B, C, and D removed)

A $613/ton T2 T1

$12,806 /ton /t L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qu alifiers are noted in Table 4-8SA. Revised February, 2010. (2) - The inclusion of tail-end and low dust SCR technologies in this figure does not constitute agr eement that it is technically feasible to install these t echnologies on Unit 1 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 1 NOx Emissions

_____________________________________________________________________________________________

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

### Figure 4-2SF – MRY Station Unit 1 NO X 

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

### – Shared Facilities SCR Projects

Milton R. Young Station Unit 1 NOx Control Dominant Controls Cost Curve - Shared Facilities Projects

0 10,000 20,000 30,000 40,000 50,000 60,000

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000
Annual NOx Removal, tons/yrLevelized Total Annual Cost for NOxControl, 1000$/yr

E $9,264/ton

$7,575 /ton Slope = incremental $/ton

$12,458/ton

$2,694/ton A = Advanced SOFA E = SNCR w/ ASOFA T1 = Hypothetical Tail-End SCR w/ ASOFA (Scenario B) T2 = Hypothetical Tail-End SCR w/ ASOFA (Scenario A) L1 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario B) L2 = Hypothetical Low-Dust SCR w/ ASOFA (Scenario A) (Points B, C, and D removed)

A $613/ton T2 T1

$10,816 /ton L1

L2

(1) - All cost figures in 2006 dollars. Numbers are listed and qu alifiers are noted in Table 4-8SF. Revised February, 2010. (2) - The inclusion of tail-end and low dust SCR technologies in this figure does not constitute agr eement that it is technically feasible to install these t echnologies on Unit 1 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 assumes replacement of S CR catalyst after a specified num ber of hours of unit operation.



### As can be seen from a review of Tables 4-7SA and 4- 7SF, the average levelized control cost effectiveness (called the unit control cost in this report) ranges from approximately $613/ton to $6,597/ton of MRYS Unit

1’s NO X 

### emissions removed. The unit control cost for the hypothetically-applied Scenario A Tail End SCR w/ ASOFA case was $4,758/ton and for the hypothet ically-applied Scenario B Tail End SCR w/ ASOFA case was $5,969/ton (stand alone projects). The unit contro l cost for the hypotheti cally-applied Scenario A Low-Dust SCR w/ ASOFA case was $3, 944 4,134 /ton and for the hypothetically-applied Scenario B LowDust SCR w/ ASOFA case was $5, 380 5,552 /ton (stand alone projects). The unit control cost for the hypothetically-applied Scenario A Tail End SCR w/ ASOFA case was $4,206/ton and for theSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### hypothetically-applied Scenario B Tail End SCR w/ ASOFA case was $5,420/ton (shared facilities projects). The unit control cost for the hypothetical ly-applied Scenario A Low-Dust SCR w/ ASOFA case was $3,396 3,586 /ton and for the hypothetically-applied Scenario B Low-Dust SCR w/ ASOFA case was $4,835 4, 813 /ton (shared facilities projects). Unit control costs for SNCR w/ ASOFA was $1,265/ton, more than twice that of ASOFA ($613/ton). It should be no ted, however, that the very high estimated average control costs involve fuel lean gas reburn ($3, 635/ton) and conventional gas reburn ($6,597/ton) technologies that were shown to be inferior options (not on the dominant controls cost curve) and thus were eliminated from further impacts analysis.

The incremental cost analysis indicates that from a cost effectiveness viewpoint, the SNCR with ASOFA alternative for MRYS Unit 1 incurs a significant annu al (levelized) incremental cost compared to the

ASOFA NO X 

### control technique. The slope from zero (base line) to ASOFA (Point A) was $613/ton; the incremental cost per ton (slope) from ASOFA (Point A) to SNCR with ASOFA (Point E ) was $2,694/ton for MRYS Unit 1. The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetically-applied low-dust SCR case (Point L2, Scenario A) was $8

, 547 9,064 /ton (stand alone projects). The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetically-applied tail end SCR case (Point T2, Sc enario A) was $10,765/ton (stand alone projects).The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypotheticallyapplied low-dust SCR case (Point L1, Scenario B) was $12

, 343 12,806 /ton (stand alone projects). The incremental cost per ton (slope) from SNCR with AS OFA (Point E) to the second hypothetically-applied tail end SCR case (Point T1, Scenario B) was $13,936/t on (stand alone projects). For shared projects, the incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetically-applied SCR cases were $7,058 7,575 /ton (low-dust Point L2, Scenario A) and $9,264/ton (tail end Point T2, Scenario A). For shared projects, the incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetically-applied SCR cases were $1 0

, 876 10,816 /ton (low-dust, Point L1, Scenario B) and $12,458/ton (tail end Point T1, Scenario B).

In the U.S. EPA’s NSR Manual, the EPA does not specify acceptable or unacceptable ranges for average
(unit control costs) and incremental cost 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 technologySupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### can be eliminated provided the applicant h as adequately identified the circumstances, including the cost or other analyses, that show what is significantly different about the proposed source.” 34



### This supplemental report for the MRYS NOx BACT 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 1 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 1 of $549 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 1 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 1 NOx Emissions________________________________________________________________________________________________________________________________________________________________________________________________________________________Minnkota Power Cooperative, Inc. 4-39Burns & McDonnellTABLE 4-9SA – Estimated Emissionsand Economic Impacts Summary for NOXControl Alternatives - MRY Station Unit 1 - Stand Alone SCR ProjectsSummary of Estimated Annual Emissions and Economics for NOx Control Alternatives Evaluated for Milton R. Young Station Unit 1 –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)0.053 145 589 9,345 93.8(8)222,86420,048 44,465 4,758T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(7)0.053 145 536 9,398 93.8(8)222,864 29,361 56,095 5,969L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(7)0.053 145 586 9,348 93.8(8)180,739 18,33238,6494,134L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(7)0.053 145 533 9,401 93.8(8)180,73929,17852,1935,552E SNCR w/ ASOFA 0.355 975 4,025 5,909 58.1 8,113 5,417 7,472 1,265D Gas Reburn w/ ASOFA 0.374 1,025 4,275 5,659 56.0 18,006 28,641 37,334(9)6,597C Lignite Reburn w/ ASOFA 0.385 1,058 4,343 5,591 54.6 46,656 5,862 11,388(9)2,037B FLGR w/ ASOFA 0.460 1,261 5,260 4,674 45.9 10,639 12,863 16,990(9)3,635A Advanced SOFA (ASOFA) 0.513 1,409 5,874 4,060 39.5 4,277 1,695 2,489 613Baseline 0.849 2,330 9,934 0 0.0 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 0.849 lb/mmBtu at 2,744 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 244.45 MWg and assumes a 97.3% average annual availability. Values from reported emission data for the 12month operating 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 257 MWg unit capacity rating. All cost figures in 2006dollars. Costs for gas reburn options include highpressure natural gas supply pipeline installed capital cost of $8,075,000 for CGR and $4,038,000 for FLGR. Costs for increasedPM collection capacity included inlignite reburn option are $23,561,000for 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 244.45MWg and assumes a 96.6% average running plant capacity ratio comparedto nominal unit gross electrical output capacity of 253 MWg. All cost figures in 2006 dollars. Costs for increased PM collection capacity included in lignite reburn option are $1,909,000/yr for annual O&M cost. Revised February, 2010.(5)- Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Levelized annual O&M cost = Annual O&M costx 1.24873 annualized O&M cost factor. Revised February, 2010.(6)- Average Control Cost Effectiveness ($/ton)is the Levelized Total Annual Cost ($/yr)divided by Annual Emission Reduction (tons). All cost figures in 2006dollars. Revised February, 2010.(7)- 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 1 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 is considered 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. Revised February, 2010.(8)- The stated overall control percentage includes the anticipated long-term emission reduction of90% design removal from a baseline of 0.51 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 0.085 lb/mmBtu, for anoverall reduction of 90 percent froma baseline of 0.849 lb/mmBtu.(9)- LTAC for reburn options include high-pressure natural gas supply pipeline annualized capital cost of $704,000/yr for CGR and$352,000 for FLGR; LTAC for increased PM collection capacity included in lignite reburn option are$2,054,000 for annualized capital cost plus $2,384,000/yr for annualized O&Mcost, for a total of $4,438,000/yr.Supplemental BACT Control and Cost-EffectivenessAnalysis for MRY Station Unit 1 NOx Emissions________________________________________________________________________________________________________________________________________________________________________________________________________________________Minnkota Power Cooperative, Inc. 4-40Burns & McDonnellTABLE 4-9SF – Estimated Emissions and Economic Impacts Summary for NOXControl Alternatives - MRY StationUnit 1 – Shared Facilities SCR ProjectsSummary of Estimated Annual Emissions and Economics for NOx Control Alternatives Evaluated for Milton R. Young Station Unit 1 –Shared Facilities 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)0.053 145 589 9,345 93.8(8)181,48418,806 39,307 4,206T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B(7)0.053 145 536 9,398 93.8(8)181,484 28,120 50,937 5,420L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A(7)0.053 145 586 9,348 93.8(8)139,639 17,09933,5263,586L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario B(7)0.053 145 533 9,401 93.8(8)139,63926,48345,2444,813E SNCR w/ ASOFA 0.355 975 4,025 5,909 58.1 8,113 5,417 7,472 1,265D Gas Reburn w/ ASOFA 0.374 1,025 4,275 5,659 56.0 18,006 28,641 37,334(9)6,597C Lignite Reburn w/ ASOFA 0.385 1,058 4,343 5,591 54.6 46,656 5,862 11,388(9)2,037B FLGR w/ ASOFA 0.460 1,261 5,260 4,674 45.9 10,639 12,863 16,990(9)3,635A Advanced SOFA (ASOFA) 0.513 1,409 5,874 4,060 39.5 4,277 1,695 2,489 613Baseline 0.849 2,330 9,934 0 0.0 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 0.849 lb/mmBtu at 2,744 mmBtu/hr MCR heat input.Emissions are calculated from unit emission rates, control percentage, hourlyheat input, and annual hrs/yr operation compared to pre-control baseline basedon annual operation at agross unit electrical output of 244.45 MWg and assumes a 97.3% average annual availability. Values from reportedemission data for the 12 month operating period during 2001-2005 with the highest rolling summation of NOx pounds.(3)- Installed capital cost is estimated for determination of totalcapital cost for a particular technology or combination, assuming 257 MWg unit capacity rating. All cost figuresin 2006 dollars. Costs for gas reburn optionsinclude high-pressure natural gas supply pipeline installed capital cost of $8,075,000 for CGR and $4,038,000 for FLGR. Costsfor increased PM collection capacity included in lignite reburn option are $23,561,000 forinstalled 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 244.45 MWg and assumes a 96.6% average running plant capacityratio compared to nominal unit gross electrical output capacity of 253 MWg. All costfigures in 2006 dollars. Costs for increased PM collection capacity included in lignite reburn option are $1,909,000/yr for annual O&Mcost. Revised February, 2010.(5)- Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capitalcost factor. Levelized annual O&M cost =Annual O&M cost x 1.24873 annualized O&Mcost factor. Revised February, 2010.(6)- Average Control Cost Effectiveness ($/ton)is the Levelized Total Annual Cost ($/yr)divided by Annual Emission Reduction (tons). All cost figures in 2006dollars. Revised February, 2010.(7)- 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 1 at Milton R. Young Station. The estimated annual NOxremoval andLTAC shown for a hypothetically-applied SCR system is based on assumptions that known or expectedreasons for technical infeasibilityfor installation and operation and maintenance of the SCR equipment onthis 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 commentsby the NDDH, EPA, DOJ, and other parties, so this information forthe hypothetical application ofSCR alternatives is includedfor comparative purposes only. See Section 4.2.1.2.1 for details of Scenario A and Scenario Bthat assumes replacement of SCR catalyst after a specified number of hours of unit operation. Revised February, 2010.(8)- The stated overall control percentage includes the anticipated long-term emission reduction of90% design removal from a baseline of 0.51 lb/mmBtu resulting from an advancedseparated overfire airsystem, with air-stagedlow-NOXcyclone combustion. Without a separatedoverfire air system operation or any other technique employed, the assumed emission rate would be 0.085 lb/mmBtu, for an overall reduction of 90 percent from a baseline of0.849 lb/mmBtu.(9)- LTAC for reburn options include high-pressure natural gas supply pipeline annualized capital cost of $704,000/yr for CGR and$352,000 for FLGR; LTAC for increased PM collection capacity included inlignite reburn optionare $2,054,000 for annualized capital cost plus $2,384,000/yr forannualized O&M cost, for a total of $4,438,000/yr.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

Minnkota Power Cooperative, Inc. 4-41 Burns & McDonnell 

### The other elements of the fourth step of a BACT 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 1 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 1. New induced draft booster fan electrical power demand is needed due to the estimated additional flue gas pressure drop resulting from hypothetical application of SCR reactor, ductwork, and gas-to-gas heat exchangers. The additional auxiliary electric power demand for the hypothetical application of TESCR and LDSCR equipment were calculated to be 9.7 MW and 8.0 MW, respectively, us ing estimated annual average electrical loads of the
booster fan, urea-to-ammonia conversion fired heater combustion/dilution air fan, direct-fired flue gas
reheat burner combustion air fan, and service and sootblowing air compressor equipment and related auxiliary equipment.

Preliminary conceptual design details were developed for these alternatives. An estimated additional 12 inches w.c. of flue gas pressure drop was assumed fo r each hypothetical application of low-dust SCR system, and an estimated additional 19 inches w.c. of flue gas pressure drop was assumed for the hypothetical application of tail end SCR system. Equipment and ductwork arrangements and expected fouling of the catalyst for the hypothetical appli cation of SCR system ductwork, reactor, and gas-gas reheater changes may cause significantly more restric tive flow paths. Thus the electrical power usage estimated here may be too low.

39 Ibid Reference number 3, October 2006, pages 3-31 through 3-35, and Appendix pages C3-7 through C3-10.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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Minnkota Power Cooperative, Inc. 4-42 Burns & McDonnell 

### The expected loss of electrical power generation from these reductions in net output was included as a cost, assuming $35 per megawatt-hour for replacement electrical power. Energy impacts of installing hypothetical application of low-dust and tail end SCR alternatives for 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 ammonia to the S CR reactor catalyst for the low-dust and tail-end SCR alternatives. A urea-to-ammonia conversion system de dicated for each SCR reactor was also assumed. This conversion process will use a natural gas-fired bu rner that mixes the combustion products at high temperature with the injected aqueous urea solution to thermally decompose the urea, producing gaseous ammonia to supply to the reactors’ ammonia injectio n grids. Gaseous ammonia is the required amine reagent that the catalyst in the S CR reactors uses to convert nitrogen oxides to elemental nitrogen and water vapor. Ammonia (from urea conversion) is supplied and cons umed continuously on demand while

the SCR NO X 

### reduction process is in operation. Natural gas is fired continuously during the urea-toammonia conversion system operation.

Final reactor inlet flue gas reheat systems are require d for the hypothetical application of tail end and lowdust SCR with ASOFA alternatives. A natural g as-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 1 NOx Emissions

_____________________________________________________________________________________________

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



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

### Control Alternatives - MRY Station Unit 1

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) 32,580 460,090 0 0 492,670

T1 Hypothetical Tail End SCR w/ ASOFA – Scenario B (5) 29,674 419,054 0 0 448,728

L2 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (5) 32,409 413,655 0 0 446,064

L1 Hypothetical Low-Dust SCR w/ ASOFA – Scenario A (5) 29,503 376,566 0 0 406,069

E SNCR w/ ASOFA 0 0 0 54,315 54,315
D Gas Reburn w/ ASOFA 0 0 3,721,806 0 3,721,806

C Lignite Reburn w/ ASOFA 0 0 0 0 0
B FLGR w/ ASOFA 0 0 1,541,796 0 1,541,796

A Advanced SOFA (ASOFA) 0 0 0 0 0
(1) - Alternative label has been assigned from highest to lowest unit NOx emission rate. Alternatives are labeled the same as in Table 4-9. (2) - The inclusion of tail-end and low-dust SCR technologies in this table does not constitute agreement that it is technically feasible to install these technologies on Unit 1at Milton R. Young Station. The annual NOx removal and LTAC shown for a hypothetically -applied SCR system is based on 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, a nd 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. Revised February, 2010. (3) – Estimated annual natural gas usage for urea-to-ammonia conversion based on adjustments to preliminary budgetary equipment vendor proposals and process calculations. TESCR and LDSCR rate = 4.27 mmBtu/hr for one reactor. (4) – Estimated annual natural gas usage fo r flue gas final reheat based on adju stments to preliminary vendor process calculations. TESCR rate = 60.3 mmBtu/h r for one reactor; LDSCR rate = 31 54.5 mmBtu/hr for one reactor. Rev 2/10

. (5) – Natural gas burned for reburn alternatives is assumed to 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. Revised February, 2010. (6) - Additional coal burned is due to the urea dilution water injected directly into the boiler’s upper furnace, decreasing heat available for steam production and 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. Revised February, 2010.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

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

### CONTROL ALTERNATIVES FOR MRY STATION UNIT 1 Operation of the NO X 

### control technologies on the dominant controls cost curve for potential application at the Milton R. Young Station would impose direct and indirect impacts on the environment. The most pronounced direct environmental impact expected from operation of any of the 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 application of SCR case.

Operation of any SCR system will normally cause a small amount of unreacted ammonia to be emitted. The amount of ammonia slip produced by an SCR 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 1 NOx Emissions

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

### Unreacted ammonia (“slip”) from SCR operation will not be collected downstream of the tail end SCR reactor. The wet flue gas desulfurization absorber downstream of the low-dust SCR reactor may reduce ammonia slip. Any remaining ammonia slip that is no t collected or condensed in the air pollution control system will be emitted from the stack as an aerosol or condensable particulate. This has the potential to increase atmospheric visibility impairment downwind of the facility compared with a pristine condition.

Sulfur dioxide (SO 2 

### ) formed during combustion in the boile r can combine with oxygen during passage through the hypothetical applicati on of tail end and low-dust SCR catal yst 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 downs tream gas-gas reheater or ductwork occurs. SO 3 

### and

H 2 

### SO 4 

### can have significant negative far-field impairment impacts on atmospheric visibility if they are

above threshold concentrations and not controlled. Tail end SCRs can also cause a small amount of 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 par ticles will effectively eliminate the remaining SO 3 

### downstream of the 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 re juvenation facility or an 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.



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

### CONTROL ALTERNATIVES FOR MRY STATION UNIT 1 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 areSupplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

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

### BACT Analysis Study report 41 

### . This supplemental economic analysis examined the estimated capital cost of four hypothetically-applied SCR cases and previouslyanalyzed feasible NO X 

### control alternatives and any other powerplant upgrade costs necessary to implement the alternatives. In addition, the economic analysis examined the operating and maintenance

costs associated with each NO X 

### control technology evaluated. These costs were then combined into the levelized total annual cost for a comparative asse ssment of the total implementation cost of each alternative. Finally, as part of the top-down analys is, a dominant controls cost curve was plotted and the unit control cost for each remaining alternative was evaluated. Four hypothetically-applied SCR cases and two previously-analyzed feasible alternatives were on the dominant controls cost curve and the latter

were identified as the more cost effective altern atives. The four hypothetically-applied SCR cases and two previously-analyzed feasible BACT NO X 

### control alternatives were evaluated for incremental cost, energy, and environmental impacts applicable to Milton R. Young Station Unit 1. The results are

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

The unit control cost for the hypothetical application of Scenario A Tail End SCR w/ ASOFA case was $4,758/ton and was $5,969/ton for the hypothetical application of Scenario B Tail End SCR w/ ASOFA case (stand alone projects). The unit control cost for th e hypothetical application of Scenario A Low-Dust SCR w/ ASOFA case was $3,944 4,134 /ton and was $5,380 5,552 /ton for the hypothetical application of
Scenario B Low-Dust SCR w/ ASOFA case (stand al one projects). The unit control cost for the hypothetical application of Scenario A Tail End S CR w/ ASOFA case was $4,206/ton and was $5,420/ton for the hypothetical application of Scenario B Tail End SCR w/ ASOFA case (shared facilities projects). The unit control cost for the hypothetical applicati on of Scenario A Low-Dust SCR w/ ASOFA case was $3,396 3,586 /ton and was $4,835 4, 813 /ton for the hypothetical application of Scenario B Low-Dust SCR w/ ASOFA case (shared facilities projects). Unit control cost for SNCR w/ ASOFA was $1,265/ton, more than twice that of ASOFA ($613/ton). The UCCs for the hypothetical application of SCR are approximately 270 280 to 470 percent of the UCC for SNCR w/ ASOFA ($1,265/ton), and approximately

5 5 0 58 0 to 970 percent of ASOFA’s UCC ($613/ton).

The incremental cost analysis indicates that from a cost effectiveness viewpoint, the SNCR with ASOFA alternative for MRYS Unit 1 incurs a significant annu al (levelized) incremental cost compared to the

ASOFA NO X 

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

41 Ibid Reference number 3, October 2006, pages 3-20 through 3-38.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

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

### incremental cost per ton (slope) from ASOFA (Point A) to SNCR with ASOFA (Point E ) was $2,694/ton for MRYS Unit 1. The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetical application of low-dust SCR case (Point L2, Scenario A) was $8,547 9,064 /ton (stand alone projects). The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the top hypothetical application of tail end SCR case (Point T2, Scenario A) was $10,765/ton (stand alone projects). The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetical application of low-dust SCR case (Point L1, Scenario B) was $12,343 12,806 /ton (stand alone projects). The incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetical application of tail end SCR case (Point T1, Scenario B) was $13,936/ton (stand alone projects). For shared projects, the incremental cost per ton (sl ope) from SNCR with ASOFA (Point E) to the top hypothetical application of SCR cases were $7,058 7,575 /ton (low-dust Point L2, Scenario A) and $9,264/ton (tail end Point T2, Scenario A). For shared projects, the incremental cost per ton (slope) from SNCR with ASOFA (Point E) to the second hypothetical application of SCR cases were $10,876
10,816 /ton (low-dust, Point L1, Scenario B) and $1 2,458/ton (tail end Point T1, Scenario B).

The incremental unit control cost per ton (slope) fro m SNCR with ASOFA to the hypothetical application of SCR with ASOFA cases are approximately 260 280 to 520 percent of the incremental UCC per ton (slope) between ASOFA and SNCR with ASOFA ($2,69 4/ton). The incremental UCCs from SNCR with ASOFA to the hypothetical application of SCR with ASOFA cases is between 1 1 12 and 23 times the incremental UCC for ASOFA from the pr e-control baseline ($613/ton).

In the U.S. EPA’s NSR Manual, the EPA does not specify acceptable or unacceptable ranges for average
(unit control costs) and incremental cost 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 1 NOx Emissions

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

### MRYS Unit 1 significantly more expensive than SCR costs normally incurred by other coal-fired steam electric generating units. The following information 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 cost-effectiveness analysis used for establishing presumptive BART stated that “applying SCR for coal-fired cyclone units is typically less than $1500 a ton, and that the average costeffectiveness is $900 per ton” 43 

### . EPA’s technical support document es timated an average control cost for SCR applied to MRYS Unit 1 of $549 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 alon e” and “shared facilities” installed capital costs for the hypothetical application of Low-Du st SCR w/ ASOFA cases at MRYS Unit 1 are $543 to $703/kW, which is more than 500 percent of the EPA’s number. The estimated “stand alone” and “shared facilities” installed capital costs for the hypothetical application of Tail End SCR w/ ASOFA cases are $706 to $867/kW, which is more than 700 percent of the EPA’s number. Also stated in the final RHR/BART Guidelines, “the averag e cost for each [of two options, A and B]... may be deemed to be
reasonable. However, the incremental cost...of the additional emissions reducti ons to be achieved by control B may be very great. In such an instance, it may be inappropriate to chose control B, based on its higher incremental costs, even though its av erage cost may be considered reasonable”. 46



### 4.2.5 CONCLUSIONS The site-specific control costs estim ated for application of hypothetical application of tail-end and lowdust SCR alternatives to MRYS Unit 1 are significantly higher than the EPA’s co st-effectiveness analysis for conventional SCR technologies included in the t echnical 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 Station. Not withstanding the technical discussion of SCR technology infeasibility and technical details

43 See Reference number 11, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136.
44 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215.
45 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 209.
46 Ibid Reference number 11, July 2005, FR Vol. 70 No. 128, page 39168.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

### previously provided in Appendix A1 and Appendix B 47 

### of the initial NO X 

### BACT Analysis report and subsequent submittals in response to comme nts by the NDDH, EPA, DOJ, and other parties, th 

### is 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 normal range of costs incurred, as compared to cost analysis values included in EPA’s technical support document issued with the final Regiona l Haze Regulations and BART Guidelines 48,49 

### . Average control cost effectiveness for each hypothetical application of SCR control technology case is a minimum of approximately three times the unit control costs of the previously-analyzed highest-performing feasible

control alternative recommended as BACT for MRYS Unit 1 (SNCR with ASOFA). Incremental control cost effectiveness for each hypothetical application of SCR control technology case is a minimum of approximately three times the incremental control co sts of the previously-analyzed highest-performing
feasible control alternative recommended as BACT for MRYS Unit 1 (SNCR with ASOFA).

There is an expected decrease in capacity and availability to gene rate electrical power due to the hypothetical application of low-dust and tail end SCR alternatives. A fi ve to 17 percent decrease in the number of hours of annual operation, and approximatel y 3% drop in annual plant capacity (net electrical
output or MW n 

### ) during operation of the MRYS Unit 1 system are expected if the hypothetical application

of low-dust or tail end SCR alternatives were insta lled. There are also substantial expected negative energy impacts for each hypothetical application of SCR control technology case. Additional auxiliary electrical power demands of approximately 8 to 10 MW will result. This estimate of electrical power usage may be too low. This higher electrical power consumption and lower electrical power generation by MRYS Unit 1 will require additional replacement electrical power to be generated elsewhere.

Natural gas is fired continuously during the ur ea-to-ammonia conversion system operation for the hypothetical application of Tail End and Low-Dust SCR with ASOFA alternatives.

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

Low-Dust SCR with ASOFA alternativ es. Natural gas is fired continuously for flue gas reheating during SCR system operation for raising the reactor inlet temperature to 600oF minimum operating temperature

47 Ibid Reference number 3, October 2006.
48 See Reference number 11, July 2005, FR Vol. 70 No. 128, pages 39135 and 39136.
49 Ibid Reference number 4, June 2005, Excel Spreadsheet OAR-2002-0076-0446, page 215.Supplemental BACT Control and Cost-Effectiveness Analysis for MRY Station Unit 1 NOx Emissions

_____________________________________________________________________________________________

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

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

the SCR reactor.

The site-specific control costs estim ated for application of hypothetical application of tail-end and lowdust SCR alternatives to MRYS Unit 1 are significantly higher than the EPA’s co st-effectiveness analysis for conventional SCR technologies included in the t echnical support document issued with the final Regional Haze Regulations and BART Guidelines 50 

### . SCR technologies of all three types identified in the

October 2006 NO X 

### BACT Analysis Study report should be excluded from consideration for NO X 

### control at MRYS due to unacceptably high av erage and incremental cost per t on of pollutant removal based on the supplemental analysis provided herein. Therefor e the conclusions regarding NOx BACT as expressed in the original October 2006 BACT Analysis for MRYS Unit 1 are confirmed.

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

### control technology on the dominant controls cost curve for potential application to Unit 1 at the Milton R. Young Station evaluated for this study are summarized in Tables 4-11SA and 4-11SF.

50 See Reference number 4, July, 2005.Supplemental BACT Analysisfor MRY Station Unit 1 NOx Emissions___________________________________________________________________________________________________________________________________________________________________________________________________________________________Minnkota Power Cooperative, Inc. 4-51Burns & McDonnellTABLE 4-11SA – Summary of Supplemental BACTAnalysis Impact Results for Dominant NOXControl Alternatives - MRY Station Unit 1 - StandAlone SCR ProjectsECONOMIC IMPACTSENERGY IMPACTSENVIRONMENTALIMPACTS(9)EMISSIONS(2)Alt.Label(1)NOx Control AlternativeEmissionRatelb/mmBtuHourlyEmissionlbs/hrAnnualEmissiontons/yrEmissionReductiontons/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-AirIncreaseToxic AirIncreaseT2Hypothetical Tail End SCR w/ASOFA – Scenario A(10)0.053 145 589 9,345 222,86420,048 44,465 4,758 10,765 9,685 171,745,369FlyashUBC,catalystdisposalCO, NH3T1Hypothetical Tail End SCR w/ASOFA – Scenario B(10)0.053 145 536 9,398 222,864 29,361 56,095 5,969 13,936 9,685 342,358,537FlyashUBC,catalystdisposalCO, NH3L2Hypothetical Low-Dust SCRw/ ASOFA – Scenario A(10)0.053 145 586 9,348 180,739 18,33238,6494,1349,0648,012 169,418,356FlyashUBC,catalystdisposalCO, NH3L1Hypothetical Low-Dust SCRw/ ASOFA – Scenario B(10)0.053 145 533 9,401 180,73929,17852,1935,55212,8068,012 341,140,028FlyashUBC,catalystdisposalCO, NH3E SNCR w/ ASOFA0.355 975 4,025 5,909 8,113 5,417 7,472 1,265 2,694 73 68,243,017 Flyash UBC CO, NH3A Advanced SOFA (ASOFA)0.513 1,409 5,874 4,060 4,277 1,695 2,489 613 613 1 46,594,605 Flyash UBC COBaseline0.849 2,330 9,934 0 0 0 0(1)- Alternative label has been assigned from highest to lowest unit NOx emission rate.(2)- Estimated NOXcontrol level reductions relative to average annual emission baseline of 0.849 lb/mmBtuat 2,744 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 of244.5 MWg and assumes a 97.3% average annual availability.(3)- Installed capital cost is estimated for determination of totalcapital cost for a particular technology or combination, assuming 257 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 244.5 MWg and assumes a 97.3% average annual availability, which is the highest consecutive 12-months of operationfrom 2001-2005. All cost figures in 2006dollars. Revised February, 2010.(5)- Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Levelized annual O&M cost= Annual O&M costx 1.24873 annualized O&M cost factor.Revised February, 2010.(6)- Average Control Cost Effectiveness ($/ton)is the Levelized Total Annual Cost ($/yr)divided by Annual Emission Reduction (tons/yr). All cost figures in 2006 dollars. Revised February, 2010.(7)- Incremental Control Cost Effectiveness ($/ton) is the difference in LTAC between the next most stringent alternative dividedby the emissions reduction. All cost figures in 2006 dollars. Revised February, 2010.(8)- Energy impacts are incremental auxiliary electrical power demand (kW) and annual power usage plus generation lost due to negative unit reliability (fewer hours per year of operation) resulting from each control alternative (kW-hrs/yr) compared to the pre-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 hypothetical applicationof SCR 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 1 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 MRYSper the October 2006 NOXBACT Analysis Study report and subsequent submittals in response to comments by the NDDH, EPA,DOJ, and 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 assume replacement of SCR catalyst after aspecified number of hours of unit operation.Supplemental BACT Analysisfor MRY Station Unit 1 NOx Emissions___________________________________________________________________________________________________________________________________________________________________________________________________________________________Minnkota Power Cooperative, Inc. 4-52Burns & McDonnellTABLE 4-11SF – Summary of Supplemental BACT Analysis Impact Results for Dominant NOXControl Alternatives - MRY StationUnit 1 – Shared Facilities SCR ProjectsECONOMIC IMPACTSENERGY IMPACTSENVIRONMENTALIMPACTS(9)EMISSIONS(2)Alt.Label(1)NOx Control AlternativeEmissionRatelb/mmBtuHourlyEmissionlbs/hrAnnualEmissiontons/yrEmissionReductiontons/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-AirIncreaseToxic AirIncreaseT2Hypothetical Tail End SCR w/ASOFA – Scenario A(10)0.053 145 589 9,345 181,48418,806 39,307 4,206 9,264 9,685 171,745,369FlyashUBC,catalystdisposalCO, NH3T1Hypothetical Tail End SCR w/ASOFA – Scenario B(10)0.053 145 536 9,398 181,484 28,120 50,937 5,420 12,458 9,685 342,358,537FlyashUBC,catalystdisposalCO, NH3L2Hypothetical Low-Dust SCRw/ ASOFA – Scenario A(10)0.053 145 586 9,348 139,639 17,09933,5263,5867,5758,012 169,418,356FlyashUBC,catalystdisposalCO, NH3L1Hypothetical Low-Dust SCRw/ ASOFA – Scenario B(10)0.053 145 533 9,401 139,63926,48345,2444,81310,8168,012 341,140,028FlyashUBC,catalystdisposalCO, NH3E SNCR w/ ASOFA0.355 975 4,025 5,909 8,113 5,417 7,472 1,265 2,694 73 68,243,017 Flyash UBC CO, NH3A Advanced SOFA (ASOFA)0.513 1,409 5,874 4,060 4,277 1,695 2,489 613 613 1 46,594,605 Flyash UBC COBaseline0.849 2,330 9,934 0 0 0 0(1)- Alternative label has been assigned from highest to lowest unit NOx emission rate.(2)- Estimated NOXcontrol level reductions relative to average annual emission baseline of 0.849 lb/mmBtuat 2,744 mmBtu/hr heat input. Emissions are calculated from unit emission rates, control percentage, hourly heat input, and annualhrs/yr operation compared topre-control baseline based on annual operation at a gross unitelectrical output of 244.5 MWgand assumes a 97.3% average annual availability.(3)- Installed capital cost is estimated for determination of totalcapital cost for a particular technology or combination, assuming 257 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 244.5 MWg and assumes a 97.3% average annual availability, which is the highest consecutive 12-months ofoperation from 2001-2005. All cost figuresin 2006 dollars. Revised February, 2010.(5)- Levelized Total Annual Cost = Annualized Installed Capital Cost + Levelized Annual O&M cost. Annualized capital cost = Installed capital cost x 0.08718 annualized capital cost factor. Levelized annual O&M cost = Annual O&M cost x 1.24873 annualizedO&M cost factor. Revised February, 2010.(6)- Average Control Cost Effectiveness ($/ton)is the Levelized Total Annual Cost ($/yr)divided by Annual Emission Reduction (tons/yr). All cost figures in 2006 dollars. Revised February, 2010.(7)- Incremental Control Cost Effectiveness ($/ton) is the difference in LTAC between the next most stringent alternative dividedby the emissions reduction. All cost figures in 2006 dollars. Revised February, 2010.(8)- Energy impacts are incremental auxiliary electrical power demand (kW) and annual power usage plus generation lost due to negative unit reliability (fewer hours per year of operation) resulting from each control alternative (kW-hrs/yr) compared to the pre-controlbaseline.(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 may increase an insignificant amount with air-staging cyclones. Excess unreacted ammonia (slip) expected from SNCR technology and the hypotheticalapplication of SCR 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 technologieson Unit 1 at Milton R. Young Station.The estimated annual NOx removal andLTAC shown for ahypothetically-applied SCR system is based on assumptions that known or expected reasons for technical infeasibilityfor installation and operation and maintenance of the SCR equipment on this boiler are solvable. SCR technology is consideredtechnicallyinfeasible by Minnkota for application at MRYSper 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 SCRalternatives 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 aspecified number of hours of unit operation.Supplemental BACT Analysis for MRY Station Unit 1 NOx Emissions

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Minnkota Power Cooperative, Inc. 4-53 1. 

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

2. 

### EPA New Source Review Workshop Manual, 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.