Appendix 10.13 

Table 10-16 

Reference 10: 

Page 5 of "BART Determination for Stanton Station Unit 1" in 

Appendix B of Department BART Determination. 
Table 10-16 

Reference 11: Page 6 of "BART Determination for Milton R. Young Station Units 1 and 2" in 

Appendix B of Department BART Determination. 
Table 10-16 

Reference 12: Table 3-8 on page 18 of "South Dakota’s Regional Haze State Implementation 

Plan" and Tables 3.4-2 and 3.4-3 on page 39 of "Appendix C: Otter Tail Power Company Big 

Stone Generating Station Unit 1" 
1 

 BART Determination 11/18/09 

for 

 Stanton Station Unit 1 

I. Source Description

A. Owner/Operator: Great River Energy 

B. Source Type: Electric Utility Steam Generating Unit 

C. BART Eligible Units 

1. Unit 1 boiler 

2. Auxiliary Boiler 

3. Emergency Diesel Generator 

4. Emergency Fire Pump Engine 

5. Materials Handling Equipment 

a. Unit 1 coal bunker 

b. Flyash silo 

D. Unit Description 

1. Unit 1: 

Generator Nameplate Capacity: 188 MWe 

Boiler Rating: 1,800 x 106

 Btu/hr 

Startup: 1966 

Fuel: North Dakota Lignite, PRB Subbituminous 

Firing Method: Wall-fired 

Existing Air Pollution Control Equipment: Low NOx burners and an 

electrostatic precipitator 

2. Auxiliary Boiler: 

Boiler Rating: 38 x 106

 Btu/hr 

Fuel: #2 fuel oil 

3. Emergency Diesel Generator 

Rating: 10.35 x 106 Btu/hr 

Fuel: #2 fuel oil 

4. Emergency Fire Pump Engine: 

Rating: 370 horsepower 

Fuel: #2 fuel oil 

5. Materials Handling Equipment: 

a. Unit 1 coal bunker 

Existing Air Pollution Control Equipment: Baghouse 
4 

Therefore, the Department does not consider coal cleaning or the K-Fuel process available 

or technically and economically feasible. 

A circulating dry scrubber is not considered commercially available by Great River 

Energy. However, the Department is including this as an available technology. Costs for 

a circulating dry scrubber are estimated based on cost estimates included in other BART 

analyses. 

The Department considers the Powerspan ECO technology and the Pahlman Process not to 

be commercially available since no full size plant has been installed or is operating at this 

time. All other technologies or alternatives are considered technically feasible. 

Step 3: Evaluate Control Effectiveness of Each Remaining Control Technology 

The Department has calculated the baseline SO2 emission rate when burning lignite by 

utilizing the highest calendar year average SO2 emission rate of 1.81 lb/million Btu from 

2000-2004 and multiplying this value by the highest heat input for any two consecutive 

years for the 2000-2004 period. This results in a baseline SO2 emission rate as follows: 

Heat input (2001) = 9.965 x 1012 Btu 

Heat input (2002) = 1.075 x 1013 Btu 

Average heat input = (9.965 x 1012 + 1.075 x 1013) / 2 

= 1.036 x 1013 Btu 

Baseline SO2 emission rate when combusting lignite coal 

= 1.036 x 1013 Btu (1.81 lb/million Btu)(1 ton/2000 lb) = 9,376 tons/year

The control effectiveness of all remaining control technologies are shown in the following 

table. 

Alternative 

Control 

Efficiency (%) 

Inlet Loading 

(tons/yr) 

Controlled Emissions 

(tons/yr) (lb/106 Btu) 

Wet Scrubber 95 9,376 469 0.091 

Circulating Dry 

Scrubber 

93 9,376 656 0.127 

SD/FF 90 9,376 938 0.181 

Flash Dryer 

Absorber 

90 9,376 938 0.181 
5 

Alternative 

Control 

Efficiency (%) 

Inlet Loading 

(tons/yr) 

Controlled Emissions 

(tons/yr) (lb/106 Btu) 

Wet Scrubber 

with 10% bypass

86 9,376 1,313 0.263 

DSI/FF 55 9,376 4,219 0.817 

DSI/ESP 35 9,376 6,094 1.18 

The cost effectiveness and incremental costs for the various alternatives are as follows: 

Alternative 

Emissions 

Reduction 

(tons/yr) 

Annualized Cost 

($)* 

Cost Effectiveness 

($/ton) 

Incremental 

Cost ($/ton) 

Wet Scrubber 8,907 13,180,000 1,480 4,179**** 

Circulating Dry 

Scrubber 

8,720 14,220,000*** 1,631 10,638 

SD/FF 8,438 11,220,000 1,330 850** 

Wet Scrubber 

with 10% bypass

8,063 9,490,000 1,177 365 

DSI/FF 5,157 8,430,000 1,635 2,789 

DSI/ESP 3,282 3,200,000 975 --- 

Note: Flash Dryer Absorber not included since it costs more than a spray dryer with no additional 

emissions reduction. 

 * Costs provided by Great River Energy (except as noted). 

** The incremental cost shown is the incremental cost of SD/FF compared to DSI/FF. 

*** The cost is estimated based on other BART analyses. 

**** The incremental cost shown is the incremental cost of a wet scrubber compared to SD/FF. 

Step 4: Evaluate Impacts and Document Results 

Great River Energy has evaluated the energy and non-air quality effects of each option. 

The Department has determined that these effects will not preclude the selection of any of 

the control equipment. 

 
6 

Step 5: Evaluate Visibility Results 

The two primary alternatives are a wet scrubber operating at 95% removal efficiency and a 

spray dryer operating at 90% efficiency. The effects on visibility for each of these two 

control options at the Theodore Roosevelt National Park, South Unit (TRNP-SU), 

Theodore Roosevelt National Park, North Unit (TRNP-NU), Theodore Roosevelt National 

Park, Elkhorn Ranch (TRNP-Elkhorn Ranch) and the Lostwood Wilderness Area 

(Lostwood WA) are shown in the following tables. 

Unit 1 - Lignite Coal Combustion 

Delta Deciview 

90th Percentile 

SO2

Year Unit 90% Reduction 95% Reduction Difference 

2000 

2001 

2002 

Average 

TRNP-SU 

TRNP-SU 

TRNP-SU 

TRNP-SU 

0.066 

0.061 

0.096 

0.048 

0.043 

0.089 

0.018 

0.018 

0.007 

0.014 

2000 

2001 

2002 

Average 

TRNP-NU 

TRNP-NU 

TRNP-NU 

TRNP-NU 

0.080 

0.089 

0.097 

0.062 

0.061 

0.072 

0.018 

0.028 

0.025 

0.024 

2000 

2001 

2002 

Average 

TRNP-Elkhorn Ranch 

TRNP-Elkhorn Ranch 

TRNP-Elkhorn Ranch 

TRNP-Elkhorn Ranch 

0.054 

0.036 

0.074 

0.040 

0.024 

0.050 

0.014 

0.012 

0.024 

0.017 

2000 

2001 

2002 

Average 

Lostwood WA 

Lostwood WA 

Lostwood WA 

Lostwood WA 

0.118 

0.160 

0.088 

0.094 

0.139 

0.078 

0.024 

0.021 

0.01 

0.019 

Overall Average 0.019 

 
7 

Unit 1 - Lignite Coal Combustion 

Delta Deciview 

98th Percentile 

SO2

Year Unit 90% Reduction 95% Reduction Difference 

2000 

2001 

2002 

Average 

TRNP-SU 

TRNP-SU 

TRNP-SU 

TRNP-SU 

0.320 

0.322 

0.668 

0.290 

0.270 

0.556 

0.03 

0.052 

0.112 

0.065 

2000 

2001 

2002 

Average 

TRNP-NU 

TRNP-NU 

TRNP-NU 

TRNP-NU 

0.458 

0.385 

0.595 

0.369 

0.334 

0.516 

0.089 

0.051 

0.079 

0.073 

2000 

2001 

2002 

Average 

TRNP-Elkhorn Ranch 

TRNP-Elkhorn Ranch 

TRNP-Elkhorn Ranch 

TRNP-Elkhorn Ranch 

0.224 

0.241 

0.517 

0.183 

0.178 

0.429 

0.041 

0.063 

0.088 

0.064 

2000 

2001 

2002 

Average 

Lostwood WA 

Lostwood WA 

Lostwood WA 

Lostwood WA 

0.340 

0.526 

0.410 

0.320 

0.449 

0.341 

0.02 

0.077 

0.069 

0.055 

Overall Average 0.064 

Step 6: Select BART 

There are no energy or non-air quality environmental impacts that would preclude the 

selection of any of the feasible control options. The incremental cost of greater than 

$10,600 per ton of sulfur dioxide removed for a circulating dry scrubber compared to a 

spray dryer is considered excessive and a circulating dry scrubber is removed from further 

consideration as BART. 

The unit has no existing air pollution control equipment for removing sulfur dioxide and 

the plant is expected to have a remaining useful life of at least 20 years. The degree of 

visibility improvement achieved by selecting a wet scrubber operating at 95% control 

efficiency versus a spray dryer operating at 90% control efficiency does not exceed 0.028 

deciviews (90th percentile) or 0.112 deciviews (98% percentile) at any Class I area for the 

2000-2002 time frame. Although the amount of visibility improvement achieved by 

selecting a wet scrubber versus a spray dryer is small, the Department has placed the 

primary emphasis on the cost of each option. The incremental cost from a spray dryer to a 

wet scrubber is $4,179 per ton of SO2 removed. The Department does not consider this 
8 

incremental cost to be excessive. However, wet scrubbing does have additional 

environmental impacts when compared to a spray dryer with a fabric filter as outlined 

below: 

- A wet scrubber is estimated by GRE to use as much as 20% more water or 

approximately 15 million gallons per year of additional water. 

- It is assumed that a wet scrubber system will require additional on-site ponding. 

GRE has identified two potential areas on site that could be used for the additional 

ponding. The areas include the existing ash pile, which would have to be 

excavated and moved, or the abandoned ash disposal area adjacent to the river, 

which reportedly has geotechnical deficiencies. 

- Dry scrubbers are purported to achieve a higher mercury control efficiency on 

lignite and PRB as compared to a wet scrubber. In addition, future mercury 

control requirements could result in high concentrations of mercury in the ponds 

and prove problematic to discharge. 

Based upon the additional environmental impacts and the fact that a wet scrubber will 

remove at best an additional 469 tons/year of SO2 (with a small corresponding visibility 

improvement) beyond the control achieved by a spray dryer, the Department proposes 

BART as a spray dryer with a fabric filter. 

The highest calendar year average SO2 emission rate is approximately 1.81 lb/MM Btu for 

the 2000-2004 period when combusting lignite at Stanton Station Unit 1. Utilizing a 90% 

control efficiency for the spray dryer and fabric filter results in an annual average

controlled emission rate of approximately 0.181 lb/MM Btu. Based upon historical SO2

emissions data for spray dryers and fabric filters at North Dakota facilities, the Department 

has determined that an increase of 33% is warranted to adjust from an annual average SO2

emission rate to a 30-day rolling average SO2 emission rate. Multiplying the annual 

average emission rate of 0.181 lb/MM Btu by a factor of 1.33 (an increase of 33%) yields a 

30-day rolling average SO2 emission rate of 0.24 lb/MM Btu. Therefore, BART for SO2

when combusting lignite coal is an SO2 emission limit of 0.24 lb/million Btu heat input (on 

a 30 day rolling average) or a reduction efficiency of 90% (on a 30 day rolling average) on 

the inlet SO2 concentration to the pollution control equipment. 

B. Filterable Particulate Matter 

Step 1: Identify All Available Technologies 

New Baghouse 

New Electrostatic Precipitator (ESP) 

New Wet ESP 

Existing ESP 

Step 2: Eliminate Technically Infeasible Options 

All technologies are considered technically feasible.