Appendix 10.13 

Table 10-16 

Reference 12: 

Table 3-8 on page 18 and Table 6-7 on page 87 of "South Dakota’s 

Regional Haze State Implementation Plan." 
 SOUTH DAKOTA’S 

 REGIONAL HAZE 

 STATE IMPLEMENTATION PLAN 

South Dakota Department of Environment and Natural Resources
17

Table 3-7 – Baseline versus Natural Background (Deciviews) 

Class I Baseline Natural Difference Baseline Natural Difference 

Area 20% Least Impaired Days 20% Most Impaired Days 

Badlands 6.91 2.32 4.59 17.16 7.44 9.72 

Wind Cave 5.16 2.29 2.87 15.93 7.41 8.52 

3.2.4 Refined Natural Conditions 

EPA identifies any refined approach for determining natural visibility conditions should be based 

on accurate, complete, and unbiased information and should be developed using a high degree of 

scientific rigor. The refined natural concentration estimates must retain the distinction between 

natural and anthropogenic components. For example, just like EPA’s default natural 

concentrations, the refined natural concentrations should not exceed actual measured 

concentrations of that species over a 5-year period. 

EPA indicates additional information will become available over the years to improve on the 

default natural concentrations such as the following:

1. Implementation of a coordinated fire data system or fire tracking system; 

2. The collection of multiple years of speciated particulate matter data in mandatory Class I 

areas and the assessment of potential contributions by natural fire events using data from 

the fire tracking system; 

3. Development of chemical analysis techniques to identify carbon attributed to fire versus 

other sources; 

4. Development of improved emissions factors and tracking of fire activity levels; and

5. Improved regional scale fire modeling or remote sensing tools to retrospectively 

determine whether smoke from a fire impacted a Class I area air shed.

DENR agrees more refined natural species concentrations will be developed in the coming years 

that are more specific to a national park and will review this new information as it periodically 

reviews its Regional Haze State Implementation Plan. 

3.3 Uniform Rate of Improvement 

In accordance with 40 CFR § 51.308(d)(2)(iv)(A), the initial implementation plan shall address 

the difference between the baseline and natural conditions for the 20% most impaired and 20% 

least impaired days. In accordance with 40 CFR § 51.308(d)(1)(i)(B), the state is required to 

determine the rate of progress needed to attain natural visibility conditions by the year 2064. 

The rate of progress is based on the difference between the baseline visibility conditions and the 

natural visibility conditions for 20% most impaired days for each Class I area. 

The uniform rate of visibility improvement, measured in deciviews, is determined by taking the 

difference between the baseline visibility conditions and the natural visibility conditions and 

dividing by 60 years, which is the time frame for attaining natural visibility conditions by 2064. 

The uniform rate of improvement is required to be considered as the state establishes its 

reasonable progress goals for attaining natural visibility conditions. The uniform rate of 
18

improvement for the Badlands and Wind Cave National Parks is based on the formula in 

Equation 3-7 and the baseline and natural background valued in Table 3-7. The results are 

displayed in Table 3-8. The uniform rate of improvement was calculated for the 20% most 

impaired days for each national park. 

Equation 3-7 – Uniform Rate of Progress 

Uniform Rate of Pr ogress $ ! Baseline # Natural " 60

Table 3-8 – Annual Uniform Rate of Improvement 

Description Badlands Wind Cave 

Annual Improvement 0.1620 deciviews 0.1420 deciviews 

The uniform rate of improvement was used to establish the slope of reduction necessary to 

achieve the natural visibility conditions in 2064. The slope of reduction for the 20% most 

impaired days for the Badlands and Wind Cave National Parks are displayed in Figure 3-5.

The improvement needed by 2018 was calculated based on the annual uniform rate of 

improvement identified for each Class I area. The baseline is based on calendar years 2000 

through 2004. Therefore, there are 14 years from the baseline to the first planning period or 

2018. The improvement needed for the 20% most impaired days by calendar year 2018 for each 

Class I area was determined by multiplying the annual uniform rate of improvement by 14 years 

then subtracting that from the baseline value for the 20% most impaired days in Table 3-7. The 

result is displayed in Figure 3-5. 

Figure 3-5 – Uniform Rate of Improvement 

(a) Badlands National Park 

0.00

3.00

6.00

9.00

12.00

15.00

18.00

2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056 2060 2064

Year

Deciviews

Reasonable Progress 2018 (14.89 deciviews) Natural (7.44 deciviews)
19

(b) Wind Cave National Park 

0.00

3.00

6.00

9.00

12.00

15.00

18.00

2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056 2060 2064

Year

Deciviews

Reasonable Progress 2018 (13.94 deciviews) Natural (7.41 deciviews)

4.0 IMPROVE Data for Class I Areas 

The data from the IMPROVE monitoring sites identifies the composition of the pollutants 

impacting our Class I areas and consists of ammonia sulfates fine (ammSO4f), ammonia nitrates 

fine (ammNO3f), organic mass carbon (OMC), elemental carbon fine (Ecf), soil, coarse mass 

(CM), and sea salt. The IMPROVE data has been collected at the Badlands National Park since 

1988 and the Wind Cave National Park since 2000. DENR is using the IMPROVE data to help 

determine what air pollutants are causing or contributing to visibility impairment in the Class I 

areas and assist in evaluating if each state is achieving the reasonable progress goals. 

4.1 Aerosol Concentrations 

The average aerosol concentration (micrograms per cubic meter (ug/m3)) and visibility 

(deciviews) per year during the baseline period (2000-2004) for the 20% least (P10) and 20% 

most (P90) impaired days are summarized in Table 4-1 for the Badlands National Park and Table 

4-2 for the Wind Cave National Park. The last line in each Table provide the default natural 

conditions that should be achieved for the 20% most impaired days by 2064. 

The baseline aerosol concentrations at the Badlands and Wind Cave National Parks during the 

20% most impaired days are all similar and within 22% or less of each other except for the 

coarse mass and sea salt. If you neglect sea salt, the aerosol with the greatest dissimilarity is 

coarse mass with the Badlands National Park’s coarse mass baseline concentrations being greater 

than at the Wind Cave National Park. This would be expected because of the drier conditions 

associated with the Badlands National Park. Coarse mass is typically generated from crushing or 

grinding operations, dust from paved or unpaved roads, windblown dust, etc. 
86

Emerging control technologies such as Enviroscrub, Electro catalytic oxidation, and the Airborne 

process have not been commercially available and have not been demonstrated for long-term 

levels of performance. As noted in 40 CFR Part 51, Appendix Y, a control technology needs to 

be commercially available to be considered technically feasible. As such these emerging 

technologies are not considered technically feasible options for Otter Tail Power Company. 

DENR determined that the following sulfur dioxide control technologies were feasible for Otter 

Tail Power Company: 

1. Semi-dry flue gas desulfurization; and 

2. Wet flue gas desulfurization. 

6.3.2.3 Sulfur Dioxide Control Effectiveness 

Step 3 requires the evaluation of control effectiveness for each control technology. DENR 

evaluated the control effectiveness by comparing the effectiveness in Table 6.6. 

Table 6-6 – Comparison of Control Effectiveness for Sulfur Dioxide Controls 

Emission Rate 

Control 

Efficiency 

Otter Tail 1 RBLC 3 Basin 4 EPA 5

Rank Control (lbs/MMBtus) 2(lbs/MMBtus) 2(lbs/MMBtus) 2(%) 

#1 Wet Flue Gas 

Desulfurization 

0.043 to 0.15 0.1 to 0.167 0.05 90 to 98 

#2 Semi-Dry Flue 

Gas 

Desulfurization 

0.09 to 0.15 0.038 to 0.16 0.07 80 to 90 

1

 – The identified emission rates were identified in Otter Tail Power Company’s BART analysis; 

2

 – “lbs/MMBtus” means pounds per million British thermal units; 

3

 – The identified emission rates were obtained from EPA’s Reasonable Achievable Control 

Technology, Best Available Control Technology, and Lowest Achievable Emission Rate 

Clearinghouse (RBLC) considering data for permits issued after calendar year 2000; 

4

 – The emission rates are based on the BACT analysis provided by Basin Electric Power 

Cooperative’s proposed NextGen project in South Dakota; and 

5

 – The control efficiencies, in percent removal, are from EPA’s “Air Pollution Control Technology 

Fact Sheet on Flue Gas Desulfurization Systems”. 

6.3.2.4 Sulfur Dioxide Control Technology Impacts 

Step 4 requires DENR to look at impacts associated with the control alternatives such as cost of 

compliance, energy impacts, non-air quality environmental impacts, and the remaining useful life 

of the project. These impacts are intended to provide rational in choosing between the 

alternative control options when determining what is considered BART. 
87

Otter Tail Power Company identified cost estimates for each of the control options. In addition, 

Otter Tail Power Company identified cost estimated for two different operating scenarios for 

each of the two control alternatives. Table 6-7 summarizes Otter Tail Power Company’s 

estimated costs. 

In 40 CFR Part 51, Appendix Y – Guidelines for BART Determination Under the Regional Haze 

Rule, in the section titled “How should I determine visibility impacts in the BART 

determination” it notes that the model should use the 24-hour average actual emission rate from 

the highest emitting day of the meteorological period modeled (for the pre-control scenario). The 

18,000 tons per year of sulfur dioxide is based on the highest average 24-hour average emission 

rate (4,832 pounds per hour) for calendar years 2001 through 2003 and operating 85% of the 

time or 7,746 hours per year. Based on the BART guidelines, the baseline emissions are 18,000 

tons per year. 

Table 6-7 – Comparison of Control Effectiveness for Sulfur Dioxide Controls 

Control 

Option Capital Cost O&M 1 Annual Cost 2 Reduction 3

Cost 

Effectiveness 4

WFGD #1 5

$171,800,000 $9,600,000 $29,050,000 17,100 $1,699 

WFGD #2 6

$171,800,000 $9,490,000 $28,900,000 14,870 $1,944 

SDFGD #1 7

$141,300,000 $7,660,000 $23,570,000 16,120 $1,462 

SDFGD #2 8

$141,300,000 $7,480,000 $23,330,000 14,870 $1,569 

1

 – O&M represents the operational and maintenance cost estimate for the control alternative; 

2

 – Annual cost is the annualized cost for each control alternative taking into account both the capital 

and operational and maintenance costs; 

3

 – Reduction represents the amount of sulfur dioxide reduced in tons per year annual from the 

baseline level of 18,000 tons of sulfur dioxide per year; 

4

 – Cost Effectiveness represents the annualized cost divided by the identified emission reductions 

(dollar per ton); 

5

 – WFGD #1 represents a wet flue gas desulfurization system meeting an emission rate of 0.043 

pounds per million British thermal units; 

6

 – WFGD #2 represents a wet flue gas desulfurization system meeting an emission rate of 0.15 

pounds per million British thermal units; 

7

 – SDFGD #1 represents a semi-dry flue gas desulfurization system meeting an emission rate of 0.9 

pounds per million British thermal units; and 

8

 – SDFGD #2 represents a semi-dry flue gas desulfurization system meeting an emission rate of 0.15 

pounds per million British thermal units. 

Otter Tail Power Company did not identify the cost effectiveness on a dollar per visibility 

reduction. DENR considered this cost effectiveness in Step 5 of the analysis.

Otter Tail Power Company identified the energy impacts cost associated for each of the control 

options. Table 6-8 summarizes Otter Tail Power Company’s estimated energy impacts. 
88

Table 6-8 – Estimated Energy Impacts for Sulfur Dioxide Controls 

Control Energy Demand Percent of Generation 

Wet Flue Gas Desulfurization 9,500 kilowatts 2.0 percent 

Semi-Dry Flue Gas Desulfurization 3,325 kilowatts 0.7 percent 

The non-air quality environmental impacts of the two control alternatives include the solid and 

aqueous waste streams. The semi-dry flue gas desulfurization system would be installed 

upstream of the existing baghouse. The baghouse would be used to collect the injected lime and 

reacted sulfur dioxide emissions along with other existing particulate matter emissions. Otter 

Tail Power Company did not identify how much additional particulate matter would be collected 

by the baghouse due to the use of the semi-dry flue gas desulfurization system. At this time, it is 

assume the additional material collected in the baghouse is negligible compared to the existing 

collection. Otter Tail Power Company estimates that the wet flue gas desulfurization system 

would generate an additional 44,700 tons of gypsum solids which would need to be properly 

disposed.

In conducting its cost analysis, Otter Tail Power Company used 30 years as the life expectancy 

averaging period for the control alternatives. Since the useful life of Otter Tail Power 

Company’s Big Stone I facility is expected to be longer than 30 years, there is no difference 

between the control options based on useful life.

6.3.3 Nitrogen Oxide BART Review 

6.3.3.1 Nitrogen Oxide Control Technologies 

Step 1 requires the identification of all available retrofit control technologies. Otter Tail Power 

Company identified the following control options for nitrogen oxide: 

1. Low-nitrogen oxide burners (LNBs); 

2. Over-fire air (OFA); 

3. Separated over-fire air (SOFA); 

4. Selective non-catalytic reduction (SNCR); 

5. Rich reagent injection (RRI); and 

6. Selective catalytic reduction (SCR). 

DENR also identifies the following control technologies that may be used to control nitrogen 

oxide emissions: 

1. Flue-gas recirculation; 

2. Oxygen enhanced combustion; 

3. Catalytic absorption/oxidation; 

4. Gas reburn; and

5. Emerging control technologies such as Enviroscrub, Electro-catalytic oxidation, 

NOxStar, and Cascade processes.