Best Available Control Technology 

Determination 

for 

Control of Nitrogen Oxides 

for 

M.R. Young Station 

Units 1 and 2 

April 2010 

Division of Air Quality 

ND Department of Health 

918 E. Divide Avenue 

Bismarck, ND 
2 

Table of Contents 

I. Introduction 

II. Step 3: Rank Remaining Control Technologies by Control Effectiveness 

A. Baseline Emissions 

B. Control Alternatives Effectiveness 

III. Step 4: Evaluate Most Effective Controls and Document Results 

A. Cost/Economic Analysis 

B. Energy Impact Analysis 

C. Environmental Impacts 

D. Consideration of Emissions of Toxic or Hazardous Air Pollutants 

IV. Step 5: Select BACT 

References 

Appendix A Selective Catalytic Reduction (SCR) 

 Technical Feasibility for M.R. Young Station 

Appendix B Minnkota’s Cost Estimate and Supporting Data 

Appendix C Supplemental Information 

Appendix D Excerpts from Confidential Vendor Proposals 

 
3 

I. Introduction 

In June of 2008, the North Dakota Department of Health (Department) provided for public 

comment a preliminary Best Available Control Technology (BACT) determination for the 

control of nitrogen oxides at both units of the M.R. Young Station. That preliminary 

determination indicated that selective catalytic reduction (including high dust SCR, low dust 

SCR and tailend SCR) was not technically feasible for the units at the M.R. Young Station. 

The preliminary determination was that BACT was represented by selective non-catalytic 

reduction (SNCR) plus advanced separated overfire air (ASOFA). 

The Department received comments suggesting that all three types of SCR (HDSCR, LDSCR 

and TESCR) were technically feasible. Based on the comments, the Department reevaluated the 

technical feasibility of SCR (see Appendix A). Based on the information available at the time, 

the Department maintained its position that HDSCR was not technically feasible; however, the 

Department determined that LDSCR and TESCR were technically feasible. On June 15, 2009, 

the Department asked Minnkota Power Coop (Minnkota) to submit a cost estimate and complete 

the BACT analysis for LDSCR and TESCR. Minnkota, in submittals dated November 12, 2009, 

December 11, 2009 and February 11, 2010, provided the cost estimates and supporting 

documentation (see Appendix B). 

This document provides the Department’s evaluation of LDSCR and TESCR as a BACT control 

technology and provides a determination of BACT. 

II. STEP 3: Rank Remaining Control Technologies by Control Effectiveness 

 A. Baseline Emissions 

EPA’s Draft New Source Review Workshop Manual (NSR Manual Section 

IV.D.2.b) states “The baseline emissions rate represents a realistic scenario of 

upper bound uncontrolled emissions for the source.” The NSR Manual goes on to 

state “Estimating realistic upper-bound emissions does not mean one should 

assume the emissions represent the potential emissions.” Also, the NSR Manual 

states “In addition, historic upper bound operating data, typical for the source or 

industry, may be used in defining baseline emissions in evaluating the cost 

effectiveness of a control option for a specific source.” Minnkota has estimated 

their baseline emissions based on the following criteria: 

Table 1 

Predicted Operating Data 

Operating Data Unit 1 Unit 2 

Baseline Emission Rate (lb/106 Btu/hr) 0.849 0.786 

Heat Input (106 Btu/hr) 2744 4885 

Availability 97.3% 93.9% 

Baseline NOx Emissions (tpy) 9,934 15,793 
4 

The Department evaluated the historical operating data from M.R. Young Station 

to determine if Minnkota’s baseline emission rates were reasonable. Based on the 

maximum 2-year period (may be different for each parameter) in the last 5-years 

(2003-2007), the results are: 

Table 2 

Historical Operating Data 

Operating Data Unit 1 Unit 2 

Actual Emission Rate (lb/106 Btu/hr) 0.840 0.835 

Heat Input (106 Btu/hr) 2,728 4,691 

Availabilitya 96.4% 92.2% 

Calculated Maximum Emissions 

(tpy)b

9,676 15,818 

Historical NOx Emissions (tpy)c 9,081 14,858 

 a Based on actual hours of operations. 

 b Based on actual emission rate (lb/106

 Btu/hr), heat input (Btu/hr) and availability. 

 c Based on the average of the highest two years in the last five years. 

Minnkota’s calculated baseline emissions are somewhat higher than the historical 

emissions; however, it appears their calculated baseline emission rates are 

reasonable. Using historical baseline emissions would increase the cost 

effectiveness value for SCR and make it less attractive as a BACT control 

technology as shown in Table 5. 

 

 B. Control Alternatives Effectiveness 

Table 3 

Emissions Reductions

Unit Technologya

Expected 

Efficiency (%) 

Controlled Emission Rate 

Annual Average 

lb/106 Btu Tons/yr 

1 LDSCR + ASOFA (A) 93.8 0.053 586 

1 LDSCR + ASOFA (B) 93.8 0.053 533 

1 TESCR + ASOFA (A) 93.8 0.053 589 

1 TESCR + ASOFA (B) 93.8 0.053 536 

1 SNCR + ASOFA 58.1 0.355 4,025 

1 Gas Reburn + ASOFA 56.0 0.374 4,275 

1 Lignite Reburn + ASOFA 54.6 0.385 4,343 

1 FLGR + ASOFA 45.9 0.460 5,260 

1 ASOFA 39.5 0.513 5,874 

1 Baseline --- 0.849 9,934 

2 LDSCR + ASOFA (A) 93.8 0.049 931 

2 LDSCR + ASOFA (B) 93.8 0.049 913 

2 TESCR + ASOFA (A) 93.8 0.049 936 

2 TESCR + ASOFA (B) 93.8 0.049 813 
5 

Table 3 

Emissions Reductions

Unit Technologya

Expected 

Efficiency (%) 

Controlled Emission Rate 

Annual Average 

lb/106 Btu Tons/yr 

2 SNCR + ASOFA 58.0 0.330 6,421 

2 Gas Reburn + ASOFA 55.4 0.350 6,882 

2 Lignite Reburn + ASOFA 54.2 0.360 6,964 

2 FLGR + ASOFA 45.0 0.432 8,490 

2 ASOFA 37.7 0.489 9,621 

2 Baseline --- 0.786 15,793 

a

 Scenario (A) based on a catalyst replacement schedule of 16,000 hours. Scenario (B) 

based on catalyst replacement during scheduled outages. For Unit 1 this is every 4 

months and for Unit 2 this is every 3 months. 

III. STEP 4: Evaluate Most Effective Controls and Document Results 

 A. Cost/Economic Analysis 

The NSR Manual (Section IV.D.2.a) states “Total cost estimates of options 

developed for BACT analyses should be on the order of plus or minus 30 percent 

accuracy.” Minnkota has developed costs estimates that are site specific. The 

cost estimates are based on information supplied by design engineers and vendors. 

The estimates appear to be within ± 30% for the design presented. 

Minnkota has supplied four different cost estimates for LDSCR and TESCR. 

Two cost estimates are based on each unit operating as a stand-alone facility and 

two estimates are based on Unit 1 and Unit 2 having shared facilities. The other 

cost parameter that varies is the catalyst replacement schedule. Minnkota 

included two schedules, every 16,000 hours or every scheduled shutdown of the 

unit (3-4 months depending on the unit). The 3-4 months (approximately 2,200 – 

2,900 hours) catalyst replacement would represent a catalyst life which the 

Department considers to be unsuccessful application of SCR technology and thus 

SCR would be technically infeasible. However, the lack of a vendor guarantee 

and statements made by the vendors (as discussed in Step 5) provides some 

justification for submitting such an estimate. The Department has included both 

estimates in this analysis. 

Minnkota believes the BACT determination should be based on the estimate 

provided for the stand-alone facilities. Their reasoning is that BACT, by 

definition, is determined on a case-by-case basis (i.e. seperate for each unit). 

Paragraph 65 of the Consent Decree requires a BACT analysis for each unit and 

Minnkota has supplied a separate analysis for each unit. 

Unit 1 and Unit 2 at the M.R. Young Station are both cyclone-fired units burning 

lignite from the Center Mine. The likely outcome is that BACT will be the same 
6 

for both units. Therefore, the design of the systems would logically share 

facilities such as the natural gas pipeline for reheat fuel and urea storage facilities. 

This would be the least expensive system to build and would better represent the 

true cost of the systems. Therefore, the Department has only included in its 

analysis the shared facilities cost estimate. 

Table 4 

Costs 

Minnkota’s Baseline Emissions

Unit Technology 

NOx

Reduction 

(tons/yr) 

Levelized 

Annualized 

Cost ($) 

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness 

($/ton) 

1 LDSCR + ASOFA (A) 9,348 33,526,000 3,586 7,576a

1 LDSCR + ASOFA (B) 9,401 45,244,000 4,813 10,817a

1 TESCR + ASOFA (A) 9,345 39,307,000 4,206 9,265a

1 TESCR + ASOFA (B) 9,398 50,937,000 5,420 12,458a

1 SNCR +ASOFA 5,909 7,472,000 1,265 2,697b

1 Gas Reburn + ASOFAc 5,659 37,334,000 6,597 --- 

1 Lignite Reburn + ASOFAc 5,591 11,383,000 2,037 --- 

1 FLGR + ASOFAc 4,674 16,990,000 3,635 --- 

1 ASOFA 4,060 2,489.000 613 --- 

2 LDSCR + ASOFA (A) 14,862 57,351,000 3,859 8,330a

2 LDSCR + ASOFA (B) 14,980 86,542,000 5,777 13,360a

2 TESCR + ASOFA (A) 14,875 66,506,000 4,476 10,007a

2 TESCR + ASOFA (B) 14,980 96,268,000 6,426 15,095a

2 SNCR +ASOFA 9,372 11,618,000 1,240 2,263b

2 Gas Reburn + ASOFAc 8,910 63,982,000 7,181 --- 

2 Lignite Reburn + ASOFAc 8,829 19,475,000 2,206 --- 

2 FLGR + ASOFAc 7,303 29,317,000 4,014 --- 

2 ASOFA 6,172 4,376,000 709 

 a Incremental cost between given technology and SNCR + ASOFA. 

 b Incremental cost between SNCR + ASOFA and ASOFA. 

 c Inferior options. 

Table 5 

Costs 

Historical Baseline Emissions

Unit Technology 

NOx

Reduction 

(tons/yr) 

Levelized 

Annualized 

Cost ($) 

Cost 

Effectiveness 

($/ton) 

Incremental Cost 

Effectiveness 

($/ton) 

1 LDSCR + ASOFA (A) 8,518 33,526,000 3,936 8,036a

1 LDSCR + ASOFA (B) 8,518 45,244,000 5,312 11,645a

1 TESCR + ASOFA (A) 8,518 39,307,000 4,615 9,820a

1 TESCR + ASOFA (B) 8,518 50,937,000 5,980 13,407a

1 SNCR + ASOFA 5,276 7,472,000 1,416 2,950b

1 Gas Reburn + ASOFAc 5,085 37,334,000 7,342 

1 Lignite Reburn + ASOFAc 4,958 11,383,000 2,295 
7 

Table 5 

Costs 

Historical Baseline Emissions

Unit Technology 

NOx

Reduction 

(tons/yr) 

Levelized 

Annualized 

Cost ($) 

Cost 

Effectiveness 

($/ton) 

Incremental Cost 

Effectiveness 

($/ton) 

1 FLGR + ASOFAc 4,168 16,990,000 4,076 

1 ASOFA 3,587 2,489,000 694 

2 LDSCR + ASOFA (A) 13,937 57,351,000 4,115 8,598a

2 LDSCR + ASOFA (B) 13,937 86,542,000 6,210 14,086a

2 TESCR + ASOFA (A) 13,937 66,506,000 4,772 10,319a

2 TESCR + ASOFA (B) 13,937 96,268,000 6,907 15,915a

2 SNCR + ASOFA 8,618 11,618,000 1,348 2,400b

2 Gas Reburn + ASOFAc 8,231 63,982,000 7,773 

2 Lignite Reburn + ASOFAc 8,053 19,475,000 2,418 

2 FLGR + ASOFAc 6,686 29,317,000 4,385 

2 ASOFA 5,601 43,760,007 781 

 a Incremental cost between given technology and SNCR + ASOFA. 

 b Incremental cost between SNCR + ASOFA and ASOFA. 

 c Inferior options. 

Because of lack of a vendor guarantee without pilot scale testing and statements 

made by the vendors (see Step 5), 16,000 hours between catalyst change out may 

not be possible. The following represents an average for the two catalyst 

changeout scenarios presented by Minnkota. 

Table 6 

Average Costs 

Minnkota’s Baseline Emissions

Unit Technology 

NOx

Reduction 

Levelized 

Annual 

Costb

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness 

($/ton) 

1 LDSCR + ASOFA 9,375 39,385,000 4,201 9,207a

1 TESCR + ASOFA 9,372 45,122,000 4,815 10,872a

1 SNCR + ASOFA 5,909 7,472,000 1,265 

2 LDSCR + ASOFA 14,921 71,947,000 4,822 10,872a

2 TESCR + ASOFA 14,919 81,387,000 5,455 12,578a

2 SNCR + ASOFA 9,372 11,618,000 1,240 

 a Incremental cost of selected technology versus SNCR + ASOFA. 

b

 Average cost for the two scenarios. 

 B. Energy Impact Analysis 

Minnkota has evaluated the energy impacts associated with each control option. 

TESCR would have the highest power usage followed closely by LDSCR. The 

power usage by TESCR is approximately 100 times that of SNCR. Although 
8 

there is a large discrepancy in the power usage, the amount of power used, by 

itself, would not preclude the use of LDSCR or TESCR. However, it is a 

consideration in determining BACT for the source. 

 C. Environmental Impacts 

The installation of either SCR or SNCR at M.R. Young will increase ammonia 

emissions to the atmosphere due to ammonia slip. However, it is expected that 

the ammonia slip can be limited to 2-5 ppmvd at 3% O2. No adverse 

environmental impacts are expected from this amount of ammonia slip. Use of a 

SCR catalyst may lead to increased formation of ammonium bisulfate and/or 

ammonium sulfate. The Department believes these air contaminants will not be 

emitted in a quantity that adversely affect the environment. Catalyst disposal will 

be another environmental issue for SCR. The relatively small volume of catalyst 

that must be disposed will not present any significant effects. 

The increased power usage by LDSCR and TESCR will result in additional air 

pollutants being emitted to the atmosphere. The increase in CO2 emissions for 

SCR versus SNCR are as follows: 

Table 7 

CO2 Increase 

Unit Control Alternative 

CO2 Increase 

 (Tons/yr) 

1 TESCR (A) 78,300 

1 TESCR (B) 71,500 

1 LDSCR (A) 64,700 

1 LDSCR (B) 58,800 

2 TESCR (A) 114,600 

2 TESCR (B) 99,400 

2 LDSCR (A) 94,900 

2 LDSCR (B) 82,800 

Based on the information presented, there appears to be no environmental impacts 

that would preclude the selection of SCR or SNCR as BACT. However, the 

environmental impacts are considered in the BACT selection process. 

 D. Consideration of Emissions of Toxic or Hazardous Air Pollutants 

As discussed in the previous section, the Department believes any additional 

emissions of air contaminants, including toxic or hazardous contaminants, will not 

have a significant adverse effect on the public or the environment. 

 
9 

IV. STEP 5: Select BACT 

Minnkota maintains that SCR, no matter where it is located (i.e. HDSCR, LDSCR or TESCR), is 

not technically feasible for the units at the M.R. Young Station. Based on the information 

provided through June 2009, the Department made a determination that HDSCR was not 

technically feasible; however, LDSCR and TESCR were technically feasible. This 

determination was based, in part, on assurances by SCR and catalyst vendors that a catalyst life 

guarantee could be obtained without pilot-scale testing. Two of these vendors were CERAM 

Environmental, Inc. (CERAM) and Haldor Topsoe, Inc. Despite their concerns about technical 

feasibility, Minnkota worked with CERAM and Haldor Topsoe to develop a cost estimate for 

both LDSCR and TESCR. As part of the process to develop the cost estimate, Minnkota 

supplied both vendors with detailed information about the flue gas characteristics of the M.R. 

Young Station (see Microbeam Technologies report, July 1, 2009). Based on their review of the 

data, both vendors have refused to provide a catalyst life guarantee for either LDSCR or TESCR 

without pilot-scale testing. This is in direct contrast to earlier statements by both companies. 

In their proposals to Minnkota, both companies have made statements that bring into question 

the technical feasibility of both LDSCR and TESCR (see Appendix D). CERAM has stated that 

it is unaware of any SCR application experience in the industry with the level and form of 

sodium in the M. R. Young Station ash. Haldor Topsoe has stated that the potential exists that 

physical deactivation due to catalyst blinding and plugging could be severe enough to make SCR 

a non-viable option for controlling NOx emissions. 

Several times statements have been made by commenter’s that sodium and potassium aerosols 

are not a catalyst poison unless the temperature of the reactor is below the dew point (i.e. 

moisture carries the sodium and potassium to the active sites). CERAM has stated in their 

proposal that small aerosol particles can penetrate and neutralize active catalyst sites even in dry 

conditions. In addition, CERAM states that catalyst installed even in low dust and tailend 

locations are poisoned from the exposure to the flue gas and the high levels of phosphorous, 

sodium and potassium found in the mineral analyses at M.R. Young Station will increase 

deactivation rates. This is consistent with the findings of Kling, et.al.1 and Zheng, et.al.2 

EPA’s New Source Review Workshop Manual (Section IV.B) states “A control technique is 

considered available, within the context presented above, if it has reached the licensing and 

commercial sales stage of development. A source would not be required to experience extended 

time delays or resource penalties to allow research to be conducted on a new technique. Neither 

is it expected that an applicant would be required to experience extended trials to learn how to 

apply a technology to a totally new and dissimilar source type. Consequently, technologies in 

the pilot-scale testing states of development would not be considered available for BACT 

review.” CERAM’s statement that they are unaware of any SCR application experience in the 

industry with the level and form of sodium in the ash at M.R. Young Station indicates this is a 

new and dissimilar source type based on the flue gas characteristics. 

Vendors’ statements that they will not provide a catalyst guarantee without pilot-scale testing 

indicate SCR (HDSCR, LDSCR or TESCR) for use on a boiler firing North Dakota lignite could 

be considered in the pilot-scale testing stages of development. The lack of vendor guarantees 
10 

and statements from the vendors regarding physical deactivation (plugging and masking) 

indicate successful application of SCR technology is not assured. 

The NSR Manual (Section IV.D.2.c) states “...if the cost of reducing emissions with the top 

control alternative, expressed in dollars per ton, is on the same order as the cost previously borne 

by other sources of the same type in applying that control alternative, the alternative should 

initially be considered economically achievable, and therefore acceptable as BACT.” The 

Department has gathered information from recent BACT determinations that required SCR to 

determine the estimated cost at these sources. The results in Table 8 show a pattern of 

significantly higher costs at M.R. Young Station than at other recently permitted sources. 

Unfortunately, SCR is the most efficient NOx removal technology. Many BACT analyses do not 

contain cost data because it is the top technology. If the top control technology is selected as 

BACT, a cost estimate is not required (as allowed by the NSR Manual Section III.C). Where a 

cost for SCR was provided and SCR was selected at BACT, the costs were probably not verified 

by the reviewing agency. This leads to uncertainty regarding the actual cost effectiveness for 

sources where SCR was selected as BACT. 

Table 8 

BACT Costs

Source 

Cost Effectiveness 

($/ton) Estimated Efficiency 

M.R. Young Unit 1 4,201 93.8 

M.R. Young Unit 2 4,822 93.8 

Dry Fork 1,511 83 

Wygen 3a 4,037 89 

Norborne 2,600 85% 

Turk 2,439 74% 

TS Power Plant 2,047 66% 

 

a

 110 MWe Plant – LNB + OFA + SCR 

In order to gather more data about the cost of SCR, the Department reviewed the Best Available 

Retrofit Technology (BART) analyses that were submitted to surrounding states. The results in 

Table 9 show a much higher expected annualized cost ($/kw) and cost effectiveness at M.R. 

Young Station than sources subject to BART requirements. 

Table 9 

BART Costs

Source NOx Controls 

Expected 

Efficiency (%)

Annualized 

Cost ($/kw) 

Cost 

Effectiveness 

($/ton)a

M.R. Young 1d ASOFA + SCR 93.8 153.25 4,201 

M.R. Young 2d ASOFA + SCR 93.8 150.82 4,822 

Colstrip 1 & 2 LNB + SCR 57 23.74 2,272 

Dave Johnson 3 LNB + OFA+ SCR 90 42.17 1,401 

Laramie River 1 SCR 74 23.22 2,828 

Laramie River 2 SCR 74 24.07 2,844 
11 

Table 9 

BART Costs

Source NOx Controls 

Expected 

Efficiency (%)

Annualized 

Cost ($/kw) 

Cost 

Effectiveness 

($/ton)a

Laramie River 3 SCR 74 24.07 2,772 

Nebraska City 

Station #1 

LNB + OFA + SCR 86 32.77 2,633 

PGE Boardmanb LBN + OFA + SCR 84 47.81 3,096 

Sherco #1c CC + LNB + SOFA + 

SCR 

76 25.82 2,500 

Sherco #2c CC + SCR 60 21.99 4,600 

J.E. Corette SCR 42-54 23.52 4,354 

Big Stone SCR + SOFA 80-90 27.81 825 

Boswell Energy 

Center #3 

LNB + OFA + SCR 81 33.33 3,201 

GGS 1 & 2 LBN + OFA + SCR 82 41.94 2,297 

Healy SCR --- 35.90 3,374 

Jim Bridger 1 LNB + OFA+ SCR 84 29.43 1,736 

 a Consultant’s estimate except as noted. 

 b ERG, working for the Oregon DEQ, estimated the capital cost to be 27% less than 

 the PGE consultant. The ERG estimate would yield a cost of approximately 

 $39.78/kw and $2,600/ton. 

 c Baseline emission rate is 0.20 lb/106

 Btu. CC = combustion optimization system. 

 d Based on LDSCR and average of Scenarios A and B. 

The cost effectiveness in Tables 8 and 9 can be misleading since the calculated values are 

dependent on the projected efficiency of the NOx combustion controls and add on controls. 

Minnkota has used the highest efficiency (93.8%) of any analysis reviewed. This leads to a 

lower cost effectiveness. As noted in the NSR Manual (Section IV.D.2.b), unrealistically low 

estimates of the emission reduction potential of a certain technology could result in inflated cost 

effectiveness figures. 

The NSR (Section IV.D) also states “The determination that a control alternative is inappropriate 

involves a demonstration that circumstances exist at the source which distinguish it from other 

sources where the control alternative may have been required previously, or that argue against 

the transfer of technology or application of new technology”. Minnkota has claimed that the flue 

gas characteristics, even for SCR in a low dust or tailend position, are different from any other 

facility were SCR has been applied. This claim has been corroborated by CERAM which 

indicated they were unaware of any SCR experience with a source that has similar flue gas 

characteristics. The lack of a vendor guarantees and Haldor Topsoe’s statement that LDSCR and 

TESCR might not be a viable option for NOx control at M.R. Young appears to distinguish M.R. 

Young Station from other sources where SCR has been applied. 

The average cost effectiveness (excluding M.R. Young Station) from Table 8 is $2,527/ton and 

$2,664/ton from Table 9. The expected cost effectiveness at M.R. Young is significantly higher 
12 

than these values (54% - 91%). The cost effectiveness of SCR at M.R. Young Station is higher 

than any other facility in Table 7. The cost effectiveness at M.R. Young Station is higher than 

any BART facility in Table 8 except Sherco No. 2 and J.E. Coretta. However, the cost 

effectiveness at Sherco No. 2 was based on 60% removal efficiency and 42-54% at Corette. Had 

93.8% removal efficiency been used, the cost effectiveness would be substantially less than at 

M.R. Young Station. 

The Department has also considered the incremental cost of SCR (TESCR or LDSCR) versus 

SNCR. The incremental cost varies from $7,576/ton to $10,817/ton for LDSCR at Unit 1 based 

on Minnkota’s calculation and $8,330/ton to $13,360/ton at Unit 2. The Department considers 

this incremental cost to be very high. The State of Pennsylvania rejected wet scrubbing at the 

River Hill Power company facility which had an incremental cost of $5,000/ton. The State of 

Georgia rejected wet scrubbing at the Long Leaf Energy Station which had an incremental cost 

of $8,964/ton. The State of Nebraska rejected SNCR achieving 0.05 lb/MMBtu based on an 

incremental cost of $5,600/ton at an ADM facility in Columbus, Nebraska and limestone 

injection with an incremental cost of $6,700/ton. The State of Nebraska also rejected dry 

scrubbing at a Cargill, Inc. facility in Blair, Nebraska which had an incremental cost of 

$5,900/ton. The State of Texas rejected wet limestone scrubbing at the Sandy Creek Station 

which had an incremental cost of $5,000/ton. EPA, Region 8 rejected limestone injection and a 

wet scrubber at the Deseret Power Plant based on an incremental cost of $10,540/ton. The State 

of Wyoming rejected an SCR operating at 0.043 lb/106

 Btu at the Dry Fork Plant based on an 

incremental cost of $10,300/ton. 

In summary, the Department has significant concerns whether LDSCR and TESCR are 

technically feasible for the M.R. Young Station. Selection of SCR as BACT will increase CO2

emissions up to 193,000 tons per year (Units 1 and 2 combined) over SNCR. The expected cost 

effectiveness is higher than other plants where SCR has been applied as BACT. It is 

significantly higher than the average cost effectiveness values for sources subject to BART. 

Table 8 shows the disproportional annualized costs that Minnkota would have to bear. The 

incremental cost of SCR versus SNCR is very high. Incremental costs that are less than at M.R. 

Young Station have lead to rejection of BACT alternatives by other states and EPA. 

The Department has determined that HDSCR is not technically feasible. Based on concerns 

regarding technical feasibility of LDSCR and TESCR, the high cost effectiveness, the high 

incremental cost and increased greenhouse gas emissions, the Department has determined that 

neither LDSCR nor TESCR represent BACT at M.R. Young Station. The Department affirms 

its June 2008 proposal that BACT for both units is represented by SNCR + ASOFA. 

 
13 

References 

1. Kling, Asa; Anderson, Chester; Mryinger, Ase; Eskilsson, David; Jaras, Sven G; Alkali 

deactivation of higher dust SCR catalysts used for NOx reduction exposed to flue gas 

from 100 MW-scale biofuel and peat-fired boilers: Influence of flue gas composition; 

Applied Catalysis; 2007. 

2. Zheng, Yuanjing; Jensen, Anker Dega; Johnsson, Jan Erik; Thogersen, Jaokim Reimer; 

Deactivation of V205 – W03 – Ti02 SCR catalyst at biomass-fired power plants; 

Elucidation of mechanisms by lab – and pilot-scale experiments; Applied catalysis; 2008. 

3. EPA, 1990 New Source Review Workshop Manual, Prevention of Significant 

Deterioration and Nonattainment Area Permitting, Office of Air Quality Planning and 

Standards, Research Triangle Park, NC 27711.