SOUTH DAKOTA’S 

 REGIONAL HAZE 

 STATE IMPLEMENTATION PLAN 

South Dakota Department of Environment and Natural Resources
Table of Content 

 Page 

i 

Executive Summary .................................................................................................................... vii

1.0 Introduction ........................................................................................................................ 1

1.1 Initial Visibility Protection Program ......................................................................1

1.2 Visibility Impairment ...............................................................................................2

1.3 1990 Amendments to Regional Haze Program ......................................................2

2.0 Class I Areas in South Dakota ........................................................................................... 3

2.1 Badlands National Park ...........................................................................................5

2.2 Wind Cave National Park ........................................................................................6

3.0 Baseline, Natural and Uniform Rate of Improvement .................................................... 7

3.1 Baseline Visibility Conditions ................................................................................11

3.2 Natural Visibility Conditions .................................................................................11

3.2.1 Default Natural Conditions .................................................................... 12

3.2.2 Improved Default Natural Conditions .................................................. 14

3.2.3 Baseline and Default Natural Conditions Comparison ....................... 16

3.2.4 Refined Natural Conditions ................................................................... 17

3.3 Uniform Rate of Improvement ..............................................................................17

4.0 IMPROVE Data for Class I Areas .................................................................................. 19

4.1 Aerosol Concentrations ..........................................................................................19

4.2 Extinction Comparison ...........................................................................................21

4.3 Visibility Impairment Quarterly Trends ..............................................................27

4.3.1 Number of Occurrences per Quarter .................................................... 27

4.3.2 Extinction Trends by Quarter ............................................................... 29

4.3.3 Visibility Impairment Trends ................................................................ 33

5.0 Source Apportionment ..................................................................................................... 37

5.1 Air Emission Inventory ..........................................................................................37

5.1.1 Baseline Emission Inventory .................................................................. 38

5.1.2 Current Emission Inventory .................................................................. 42

5.1.3 WRAP’s 2018 Projections ...................................................................... 42

5.1.4 Air Emission Inventories for Other States and Countries .................. 45

5.1.5 Future Emission Inventory by South Dakota ....................................... 47

5.2 Source Apportionment Analysis ............................................................................50

5.3 Regional Haze Contributions in South Dakota’s National Parks ......................52

5.3.1 Sulfate Contributions ............................................................................. 53

5.3.2 Organic Carbon Mass Contributions.................................................... 59

5.3.3 Nitrate Contributions ............................................................................. 63

5.3.4 Coarse Particulate Matter Contribution .............................................. 68

6.0 Best Available Retrofit Technology (BART) ................................................................. 72

6.1 Bart-Eligible Sources ..............................................................................................72

6.1.1 Northern States Power Company – Sioux Falls ................................... 74

6.1.2 Pete Lien and Sons, Inc. – Rapid City ................................................... 75
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6.1.3 Otter Tail Power Company – Big Stone I ............................................. 76

6.2 Otter Tail Power Company’s Modeling Results ..................................................78

6.3 Otter Tail Power Company’s Case-by-Case BART Analysis .............................81

6.3.1 Particulate BART Review ...................................................................... 82

6.3.1.1 Particulate Control Technologies ........................................... 82

6.3.1.2 Technically Feasible Particulate Control Technologies ........ 83

6.3.1.3 Particulate Control Effectiveness ........................................... 83

6.3.1.4 Particulate Control Technology Impacts ................................ 84

6.3.2 Sulfur Dioxide BART Review ................................................................ 84

6.3.2.1 Sulfur Dioxide Control Technologies ..................................... 84

6.3.2.2 Technically Feasible Sulfur Dioxide Control Technologies . 84

6.3.2.3 Sulfur Dioxide Control Effectiveness ..................................... 86

6.3.2.4 Sulfur Dioxide Control Technology Impacts ......................... 86

6.3.3 Nitrogen Oxide BART Review ............................................................... 88

6.3.3.1 Nitrogen Oxide Control Technologies .................................... 88

6.3.3.2 Technically Feasible Nitrogen Oxide Control Technologies . 88

6.3.3.3 Nitrogen Oxide Control Effectiveness .................................... 90

6.3.3.4 Nitrogen Oxide Control Technology Impacts ........................ 91

6.3.4 Visibility Impact Evaluations................................................................. 93

6.3.5 BART Emissions Limits for Big Stone I ............................................... 99

6.3.5.1 Particulate Matter BART Recommendation .......................... 99

6.3.5.2 Sulfur Dioxide BART Recommendation .............................. 100

6.3.5.3 Nitrogen Oxide BART Recommendation ............................. 101

6.4 BART Requirements ............................................................................................103

7.0 Reasonable Progress ....................................................................................................... 103

7.1 State and Federal Rules ........................................................................................104

7.2 2018 Projected Visibility Conditions ...................................................................105

7.3 Key Pollutants Contributing to Visibility Impairment .....................................106

7.4 Four Factor Analysis ............................................................................................109

7.4.1 Four Factor Analysis – GCC Dacotah ................................................ 110

7.4.2 Four Factor Analysis – Black Hills Corporation (Ben French) ........ 113

7.4.3 Four Factor Analysis – Pete Lien and Sons ........................................ 115

7.4.4 Four Factor Analysis – Summary ....................................................... 116

8.0 Long Term Strategy ....................................................................................................... 116

8.1 Class I Areas in Other States Impacted by South Dakota ................................117

8.2 States Impacting South Dakota’s Class I Areas .................................................118

8.3 Technical Basis for Modeling, Monitoring and Emissions Information ..........118

8.4 Identification of Anthropogenic Sources of Visibility Impairment ..................119

8.5 Factors in Developing Long Term Strategy .......................................................119

8.5.1 Emission Reductions from Ongoing Air Pollution Control Programs

 ................................................................................................................ 119

8.5.2 Measures to Mitigate Impacts of Construction Activities ................. 121
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8.5.3 Emission Limitations and Schedules to Achieve Reasonable Progress 

Goals ...................................................................................................... 121

8.5.4 Retirement and Replacement Schedules ............................................. 121

8.5.5 Smoke Management.............................................................................. 122

8.5.6 Enforceable Emission Limits and Control Measures ........................ 123

8.5.7 Anticipated Net Effect on Visibility Due to Projected Changes ....... 123

9.0 Monitoring Strategy ....................................................................................................... 126

10.0 Consultation Requirements ........................................................................................... 129

10.1 Federal Land Manager Consultation ..................................................................129

10.1.1 Addressing Federal Land Manager Recommendations .................... 131

10.1.2 Continued Consultation with Federal Land Managers ..................... 131

10.2 Consultation with Other States............................................................................131

10.3 Public Input ...........................................................................................................133

11.0 Periodic Review .............................................................................................................. 134

11.1 Evaluation and Reassess Every 10 Years ...........................................................134

11.2 Report Every 5 Years ...........................................................................................135

11.3 Determination of Adequacy .................................................................................136
List of Tables 

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iv 

Table 3-1 – Baseline Visibility Conditions in South Dakota’s National Parks ......................... 11

Table 3-2 – Average Natural Background Concentration Levels .............................................. 13

Table 3-3 –Natural Background Conditions for South Dakota’s Class I Areas ....................... 14

Table 3-4 – Relative Humidity Correction Factor (f(RH)) ......................................................... 15

Table 3-5 –New Formula Natural Background Conditions for South Dakota’s Class I Areas 16

Table 3-6 – Comparison of Natural versus Baseline Concentrations 1 ..................................... 16

Table 3-7 – Baseline versus Natural Background (Deciviews) .................................................. 17

Table 3-8 – Annual Uniform Rate of Improvement ................................................................... 18

Table 4-1 – Badlands National Park Baseline Aerosol Concentrations 1 ................................. 20

Table 4-2 – Wind Cave National Park Baseline Aerosol Concentrations 1 ............................... 20

Table 4-3 – Badlands National Park 1 ......................................................................................... 21

Table 4-4 – Wind Cave National Park 1 ...................................................................................... 22

Table 5-1 – South Dakota’s 2002 Baseline Emission Inventory Summary (Base 02b) 1, 2 ....... 40

Table 5-2 –South Dakota’s 2002 Planning Emission Inventory Summary (Plan 02d) 1, 2 ....... 41

Table 5-3 – Comparison of 2002 and 2009 South Dakota Point Source Emissions 1 ............... 42

Table 5-4 –2018 South Dakota Projected Emission Inventory Summary (PRP 18b) 1, 2 .......... 46

Table 5-5 – Emission Changes projected for 2018 1 ................................................................... 47

Table 5-6 –2002 Contiguous State Planning Emission Inventory Summary (Plan 02d) 1, 2 .... 48

Table 5-7 –2018 Contiguous State Emission Inventory Summary (PRP 18b) 1, 2 ..................... 49

Table 6-1– List of BART-Eligible Sources 1 ............................................................................... 74

Table 6-2– WRAP’s Modeling Results for Pete Lien and Sons 1 ............................................... 76

Table 6-3– WRAP’s Modeling Results for Otter Tail Power Company Big Stone I 1 ............... 77

Table 6-4– Otter Tail Power Company’s Modeling Results for Big Stone I 1 ........................... 80

Table 6-5 – Comparison of Control Effectiveness for Particulate Controls .............................. 83

Table 6-6 – Comparison of Control Effectiveness for Sulfur Dioxide Controls ....................... 86

Table 6-7 – Comparison of Control Effectiveness for Sulfur Dioxide Controls ....................... 87

Table 6-8 – Estimated Energy Impacts for Sulfur Dioxide Controls ......................................... 87

Table 6-9 – Comparison of Control Effectiveness for Nitrogen Oxide Controls ...................... 90

Table 6-10 – Comparison of Control Effectiveness for Nitrogen Oxide Controls .................... 92

Table 6-11 – Estimated Energy Impacts for Nitrogen Oxide Controls ...................................... 92
List of Tables 

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v 

Table 6-12 – Potential Impact of Existing Big Stone I (98th Percentile) ................................... 93

Table 6-13 – Emission Rates for Each Control Option .............................................................. 94

Table 6-14 – Modeling Results for Each Control Option (98th Percentile – Deciviews) ........... 95

Table 6-15 – Cost per Deciview Comparison ($/deciview) ......................................................... 97

Table 6-16 – Visibility Comparison between Wet and Dry Scrubbers ..................................... 100

Table 7-5– Four Factor Analysis for Black Hills Corporation Based on 30 Year Life .......... 113

Table 7-6– Four Factor Analysis for Black Hills Corporation Based on 10 Year Life .......... 114

Table 7-7– Visibility Impacts from Black Hills Corporation (8th Highest).............................. 114

Table 7-8– Visibility Impacts from Pete Lien and Sons (8th Highest) ..................................... 115

Table 9-1– IMPROVE Monitoring Sites at Class I areas in South Dakota ............................ 127

Table 9-2– Ambient Air Monitoring Site Parameters Next to IMPROVE Sites ..................... 128
List of Figures 

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vi 

Figure 2-1 – Class I Areas in the United States............................................................................ 4

Figure 2-2 –Badlands National Park’s Boundary........................................................................ 5

Figure 2-3 – Wind Cave National Park’s Boundary .................................................................... 6

Figure 2-4 –Prairie, Forest, and Bison at Wind Cave (Courtesy of National Park Service) ...... 7

Figure 2-5 – View from Lookout Tower (Courtesy of National Park Service) ........................... 7

Figure 3-1 – Light Extinction-Haze Index-Visual Range Scale 1 ............................................... 8

Figure 3-2 – Comparison at Different Levels ............................................................................... 9

Figure 3-3 – Badlands’ IMPROVE and State Monitoring Site ................................................. 10

Figure 3-4 – Wind Caves’ IMPROVE and State Monitoring Site ............................................. 10

Figure 3-5 – Uniform Rate of Improvement ............................................................................... 18

Figure 4-1 – Badlands National Park Baseline Aerosol Extinction Comparison 1 .................. 23

Figure 4-2 – Wind Cave Baseline Aerosol Extinction Percentage ............................................ 24

Figure 4-3 – National Park Extinction Comparison 1 ................................................................ 26

Figure 4-4 –Number of Occurrences by Quarter – 20% Most Impaired Days ......................... 27

Figure 4-5 – Badlands’ Quarterly Extinction Values for 20% Most Impaired Days................ 29

Figure 4-6 – Wind Cave’s’ Quarterly Extinction Values for 20% Most Impaired Days .......... 31

Figure 4-7 – Badlands’ Quarterly Data for 20% Most Impaired Days ..................................... 34

Figure 4-8 – Wind Cave’s Quarterly Data for 20% Most Impaired Days ................................. 36

Figure 5-1 – Sulfate Contribution for 20% Most Impaired Days .............................................. 54

Figure 5-2 – Sulfate Contribution for 20% Least Impaired Days ............................................. 57

Figure 5-3 – Organic Carbon Mass Contribution for 20% Most Impaired Days ..................... 60

Figure 5-4 – Organic Carbon Mass Contribution for 20% Least Impaired Days .................... 62

Figure 5-5 – Nitrate Contribution for 20% Most Impaired Days .............................................. 64

Figure 5-6 – Nitrate Contribution for 20% Least Impaired Days .............................................. 67

Figure 5-7 – Coarse Particulate Matter Contribution for 20% Most Impaired Days ............... 70

Figure 5-8 – Coarse Particulate Matter Contribution for 20% Least Impaired Days .............. 71

Figure 7-1 – Glide Slope by Pollutant for 20% Worst Visibility Days (Extinction) 1 .............. 108
vii 

Executive Summary 

The Department of Environment and Natural Resources (DENR) worked with the Western 

Regional Air Partnership (WRAP), states not members of WRAP, federal land managers, the 

Environmental Protection Agency (EPA), the regulated community, and others to develop this 

document as part of South Dakota’s Regional Haze State Implementation Plan (SIP). This 

document along with the applicable Administrative Rules of South Dakota (ARSD) and the 

addition of ARSD, Chapter 74:36:21 will be South Dakota’s Regional Haze State 

Implementation Plan and implemented by DENR to ensure South Dakota’s Regional Haze 

Program meets the goal of achieving natural conditions in the Badlands and Wind Cave National 

Parks by 2064 as specified in Title 40 of the Code of Federal Regulations (CFR) §51.308. 

Chapter 1 provides background information on the initial federal visibility protection program, 

describes the causes of visibility impairment, and describes the new federal regional haze 

program regulations. Chapter 2 provides information on South Dakota’s two Class I areas. The 

two Class I areas are the Badlands National Park and Wind Cave National Park and both are 

located in the western third of South Dakota. 

Chapter 3 describes the process DENR followed to determine natural conditions, baseline 

conditions, and the uniform rate of improvement for both Class I areas. Chapter 4 discusses the 

IMPROVE (Interagency Monitoring of Protected Visual Environments) monitoring data for both 

Class I areas. This chapter looked at the aerosols impacting both Class I areas, what time of year 

they occur, and if they are increasing or decreasing over time. 

Chapter 5 describes South Dakota’s emission inventory for past, present, and future air emission 

inventories in South Dakota, what type of activities are emitting the air emissions, and if the air 

emissions are generated within South Dakota or from neighboring states and countries. Chapter 6 

describes the BART review DENR conducted and establishes the BART requirements for the 

BART-eligible sources in South Dakota. The BART review covers an analysis to determine 

BART-eligible sources, a modeling analysis to determine if the BART-eligible source 

contributes to visibility impairment in a Class I area, and the establishment of BART for those 

BART-eligible sources that reasonably contribute to visibility impairment in any Class I area. 

The BART review identified one electrical generating unit subject to the BART requirements. 

Otter Tail Power Company’s Big Stone I facility determined that it reasonably contributes to 

visibility impairment in Class I areas. DENR determined the control equipment considered 

BART for Big Stone I is the existing baghouse, a semi-dry flue gas desulfurization system, and 

selective catalytic reduction. The installation of the new control equipment and establishment of 

BART emission limits, compliance demonstration, recordkeeping, and reporting requirements 

will be established in an air quality construction permit and eventually in Otter Tail Power 

Company’s Title V air quality operating permit. The installation of the new control equipment 

and other requirements will be completed within five years of EPA’s approval of South Dakota’s 

Regional Haze State Implementation Plan. 

 
viii 

Chapter 7 discusses South Dakota’s goals for demonstrating reasonable progress such as 

outlining existing rules that already help minimize air emissions that cause visibility impairment 

and the modeling WRAP conducted of the western United States to determine if states are 

meeting the reasonable progress goals in 2018. Sulfur dioxide emissions in South Dakota from 

2002 through 2018 are expected to decline by 36%, nitrogen oxides emissions are expected to 

decline by 18%, organic carbon mass emissions are expected to decline by 6%, and elemental 

carbon emissions are expected to decline by 49%. Other states will also experience a reduction 

in air emissions that reasonably contribute to visibility impairment in Class I areas. Overall, 

sulfur dioxide emissions during the same time period are expected to decline by 26%, nitrogen 

oxide emissions are expected to decline by 29%, organic carbon mass are expected to decline by 

6%, and elemental carbon emissions are expected to decline by 31%. These reductions are 

expected to demonstrate reasonable progress is being made to improve visibility at all Class I 

areas. 

Chapter 8 describes South Dakota’s long-term goals in achieving natural conditions by 2064. It 

also outlines DENR’s proposed rules (ARSD, Chapter 74:36:21) to ensure new sources and 

modifications to existing sources will not reasonably contribute to visibility impairment at any 

Class I area. In addition, DENR will review, develop, and implement a Smoke Management 

Plan to address wildfires and prescribed fires. 

Chapter 9 discusses DENR’s monitoring plan for tracking our progress in achieving natural 

conditions by 2064. Chapter 10 describes the consultation DENR went through with federal land 

managers, states, and the public, how DENR responded to each comment, and their future 

involvement. 

Chapter 11 describes the reviews and reporting DENR will perform to track South Dakota’s 

progress in attaining natural conditions by 2064. 
1 

1.0 Introduction 

1.1 Initial Visibility Protection Program 

In August 1977, the federal Clean Air Act was amended by adding section 169A. In section 

169A(a)(1), Congress established the following national goal for visibility protection: 

“Congress hereby declares as a national goal the prevention of any future, and the 

remedying of any existing, impairment of visibility in mandatory class I Federal areas 

which impairment results from man-made air pollution.” 

 

To address this goal for each of the 156 mandatory federal Class I areas across the nation, the 

federal Environmental Protection Agency (EPA) developed regulations to reduce the impact of 

large industrial sources on nearby Class I areas. It was recognized at the time that regional haze, 

which comes from a wide variety of sources that may be located far from a Class I area, was also 

a part of the visibility problem. However, monitoring networks and visibility models at that time 

were not developed to the degree necessary to understand the causes of regional haze. 

The 1977 Clean Air Act Amendments also established the Prevention of Significant 

Deterioration (PSD) permit program, which included requirements for protecting visibility in 

national parks, national wilderness areas, national monuments and national seashores. The PSD 

permit program included area specific (e.g., Class I, II and III) increments or limits on the 

maximum allowable increase in air pollutants (e.g., particulate matter and sulfur dioxide) and a 

preconstruction permit review process for new or modifying major sources that allows for 

careful consideration of control technology, consultation with federal land managers on visibility 

impacts and public participation in permitting decisions. The PSD permit program was 

delegated to South Dakota on July 6, 1994, and later approved in South Dakota’s State 

Implementation Plan on January 22, 2008. 

Under Section 169A(b) of the Clean Air Act, Congress established new requirements on major 

stationary sources in operation within a 15-year period prior to enactment of the 1977 

amendments. Major stationary sources within that timeframe that may reasonably be anticipated 

to cause or contribute to visibility impairment in a Class I area must install best available retrofit 

technology (BART) as determined by the state. In determining BART, the state must take into 

consideration the costs of compliance, the energy and non-air quality environmental impacts of 

compliance, any existing pollution control technology in use at the source, the remaining useful 

life of the source, and the degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such technology. 

In 1980, EPA adopted regulations to address “reasonably attributable visibility impairment”, or 

visibility impairment caused by one or a small group of man-made sources generally located in 

close proximity to a specific Class I area. At that time, EPA deferred writing rules to address 

regional haze, because they lacked the monitoring, modeling and scientific information needed to 

understand the nature of long range transport and formation of regional haze. South Dakota did 

not adopt the visibility rules of 1980 in its State Implementation Plan. Therefore, EPA is 

currently implementing the program in a Federal Implementation Plan. 
2 

1.2 Visibility Impairment 

Most visibility impairment occurs when pollution in the form of small particles scatters or 

absorbs light. Air pollutants are emitted from a variety of natural and anthropogenic (man-made) 

sources. Natural sources can include windblown dust and smoke from wildfires. Anthropogenic 

sources can include motor vehicles, electric utility and industrial fuel burning, prescribed 

burning, and manufacturing operations. More pollutants mean more absorption and scattering of 

light, which reduce the clarity and color of scenery. Some types of particles such as sulfates and 

nitrates scatter more light, particularly during humid conditions. Other particles like elemental 

carbon from combustion processes are highly efficient at absorbing light. 

Commonly, visibility is observed by the human eye and the object may be a single viewing 

target or scenery. In the 156 Class I areas across the nation, a person’s visual range has been 

substantially reduced by air pollution. In eastern parks, the average visual range decreased from 

90 miles to 15-25 miles. In the West, the visual range decreased from an average of 140 miles to 

35-90 miles. 

Some particles that cause haze are directly emitted into the air while others are formed when 

gases emitted into the air form particles as they are carried from the source of the pollutants. 

Some haze forming pollutants are also linked to human health problems and others to 

environmental damage. Exposure to very small particles in the air has been linked with increased 

respiratory illness, decreased lung function, and premature death. In addition, particles such as 

nitrates and sulfates contribute to acid deposition potentially making lakes, rivers, and streams 

unsuitable for some forms of aquatic life and impacting flora in the ecosystem. These same acid 

particles can also erode materials such as paint, buildings or other natural and manmade 

structures. 

1.3 1990 Amendments to Regional Haze Program 

In the 1990 Clean Air Act Amendments, Congress added section 169B to strengthen and 

reaffirm the national goal and address visibility impairment from a collection of sources whose 

emissions are mixed and transported over long distances to the Class I areas. Section 169B(e) 

calls for EPA to “carry out the Administrator’s regulatory responsibilities under section 169A, 

including criteria for measuring ‘reasonable progress’ toward the national goal.” 

In response to these mandates, EPA promulgated the regional haze rule on July 1, 1999. Under 

40 CFR, § 51.308(d)(1), states must “establish goals (expressed in deciviews) that provide for 

reasonable progress towards achieving natural visibility conditions” for each Class I area within 

a state by 2064. The reasonable progress goals must provide for an improvement in visibility for 

the most impaired days over the period of the implementation plan and ensure no degradation in 

visibility for the least impaired days over the same period. 

The purpose of this submittal is to address the State Implementation Plan requirements for the 

State of South Dakota found in 40 CFR § 51.308 – Regional Haze Program Requirements of 40 

CFR Part 51 Subpart P – Protection of Visibility. The South Dakota Department of Environment 
3 

and Natural Resources (DENR), the agency designated to administer and coordinate a statewide 

program of air pollution control, has general legal authority under South Dakota Codified Laws 

Title 34A-1 – Air Pollution Control to adopt and enforce rules for visibility protection including 

regional haze visibility impairment. 

This document along with the adopted rules is South Dakota’s State Implementation Plan for 

adopting a Regional Haze Program meets these goals. Pursuant to the requirements in 40 CFR § 

51.308(a) and (b), the State Implementation Plan is intended to meet the requirements in EPA’s 

regional haze regulations that were adopted to comply with the requirements established in 

Section 169B of the Clean Air Act. This document addresses the following elements of South 

Dakota’s State Implementation Plan: 

1. In accordance with 40 CFR § 51.308(d), the core regional haze program requirements 

(e.g., identification of Class I areas; determination of baseline conditions, natural 

conditions, and uniform rate of progress; and baseline, current and future emissions 

inventories); 

2. In accordance with 40 CFR § 51.308(e), who is subject to BART and BART controls, 

emissions limits, compliance determinations, recordkeeping, and reporting requirements; 

3. In accordance with 40 CFR § 51.308(f), a commitment to conduct comprehensive 

periodic revisions of South Dakota’s Regional Haze State Implementation Plan; 

4. In accordance with 40 CFR § 51.308(g), a commitment to periodically report the progress 

towards achieving reasonable progress goals; 

5. In accordance with 40 CFR § 51.308(h), a commitment to determine the adequacy of the 

existing implementation plan; and 

6. In accordance with 40 CFR § 51.308(i), the requirements for continued coordination with 

states and federal land managers. 

South Dakota is a member of WRAP which is a collaborative effort of tribal governments, state 

governments and various federal agencies to help states and tribes develop and implement a 

regional haze program that complies with the EPA's regional haze regulations. 

2.0 Class I Areas in South Dakota 

In accordance with 40 CFR § 51.308(d), states must address regional haze in each Class I area 

located within the state and in each Class I area located outside the state which may be affected 

by emissions from within the state. There are 156 national parks and wilderness areas in the 

nation that are considered Class I areas in the Clean Air Act (see Figure 2-1). South Dakota is 

home to two of the 156 national parks and wilderness areas. They are the Badlands National 

Park and the Wind Cave National Park. 
4 

Figure 2-1 – Class I Areas in the United States

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Produced by NPS Ai, Resources Division 

Mandatory Class I Areas 

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5 

There are also national parks and wilderness areas considered Class I areas in our neighboring 

states. In Wyoming the Class I areas are located in the western part of the state. Montana’s 

Class I areas are located throughout the state but none are located in the southeastern corner 

which borders South Dakota. North Dakota has probably the closest Class I area of any 

neighboring state. Minnesota’s Class I areas are located in the northeastern corner of the state. 

Iowa and Nebraska do not have Class I areas. 

2.1 Badlands National Park 

The Badlands National Park is located in southwestern South Dakota and consists of 244,000 

acres of sharply eroded buttes, pinnacles, and spires blended with the largest protected mixed 

grass prairie in the United States (see Figure 2-2). The closest industrial area from the park 

boundary is in Rapid City which is approximately 40 miles to the northwest. The general 

topography is plains; therefore this site is well exposed to regional scale transport winds. The 

surrounding terrain is predominantly mixed grass prairie and bare rock and sand. 

Figure 2-2 –Badlands National Park’s Boundary 
6 

It was established as the Badlands National Monument in 1939, and was redesignated as a 

national park in 1978. The area of the park that is actually considered a Class I area is the 

Badlands Wilderness Area, which consists of 64,000 acres in the north unit. 

2.2 Wind Cave National Park 

Wind Cave National Park lies approximately 10 miles north of Hot Springs in southwestern 

South Dakota (see Figure 2-3). It was the first cave to be designated a national park anywhere in 

the world and is currently the fourth longest cave in the world with 119.58 miles (192.45 

kilometers) of explored cave passageways. 

Figure 2-3 – Wind Cave National Park’s Boundary 

Aboveground, the park includes 28,295 acres of mixed-grass prairie, ponderosa pine forest, and 

associated wildlife (see Figure 2-4). The park’s mixed-grass prairie is one of the largest 

remaining and home to bison, elk, pronghorn, mule deer, and prairie dogs. The view from 
7 

Lookout Tower on Rankin Ridge displays a spectacular view of the mixed-grass prairie and 

ponderosa pine forest (see Figure 2-5). 

Figure 2-4 –Prairie, Forest, and Bison at Wind Cave (Courtesy of National Park Service) 

Figure 2-5 – View from Lookout Tower (Courtesy of National Park Service) 

3.0 Baseline, Natural and Uniform Rate of Improvement 

In the mid-1980’s, the IMPROVE (Interagency Monitoring of Protected Visual Environments) 

program was established to measure visibility impairment in Class I areas throughout the United 

States. The monitoring sites are operated and maintained through a formal cooperative 

relationship between the EPA, National Park Service, U.S. Fish and Wildlife, Bureau of Land 

Management, and U.S. Forest Service. 

The objectives of the IMPROVE program include establishing the current visibility and aerosol 

conditions in Class I areas; identifying the chemical species and emission sources responsible for 

existing human-made visibility impairment; documenting long-term trends for assessing progress 

towards the national visibility goals; and support the requirements of the regional haze rule by 

providing regional haze monitoring representing all visibility-protected Class I areas where 

practical. 

The data collected at the IMPROVE monitoring sites are used by federal land managers, industry 

planners, scientists, public interest groups, and air quality regulators to better understand and 

protect the visual air quality resource in Class I areas. Most importantly, the IMPROVE 
8 

program scientifically documents for American citizens, the visual air quality of their wilderness 

areas and national parks. 

The IMPROVE network consists of aerosol and optical samplers. Every IMPROVE site deploys 

an aerosol sampler to measure speciated fine aerosols and coarse mass. Select sites also deploy a 

transmissometer and nephelometers to measure light extinction and scattering respectively, as 

well as automatic camera systems to visually measure the scenery. Particulate concentration data 

is obtained every 24 hours and converted into reconstructed light extinction through a complex 

calculation using the IMPROVE equation which may be viewed at: 

http://vista.cira.colostate.edu/improve/Tools/ReconBext/reconBext.htm 

Light extinction, the impairment of visibility, occurs due to particles and gases that reflect and 

absorb light. Reconstructed light extinction (denoted as bext) is expressed in units of inverse 

mega meters (1/Mm or Mm-1). 

In accordance with 40 CFR 51.308(d)(2), states are required to track visibility conditions in 

terms of the Haze Index (HI) metric expressed in the deciviews. The relationship between light 

extinction in Mm-1, Haze Index in deciviews, and visual range in kilometers is indicted by the 

scale in Figure 3-1. 

Figure 3-1 – Light Extinction-Haze Index-Visual Range Scale 1

 

 

A comparison of the light extinction, haze index, and visual range at different levels may be 

viewed in Figure 3-2 for the Badlands National Park. Generally, a one deciview change in the 

Haze Index is likely humanly perceptible under ideal conditions regardless of background 

visibility conditions. 

The IMPROVE data undergo quality assurance and control procedures and analyses by its 

contractors and the National Park Service before it is released. The aerosol and optical data are 

made publicly available approximately nine months after collection. In addition, seasonal 

analysis reports are prepared. IMPROVE program resources are available at: 

http://vista.cira.colostate.edu/Improve. 

There are two IMPROVE monitoring sites in South Dakota. One is located at the Badlands 

National Park and the other at Wind Cave National Park. The Badlands National Park operates 

an IMPROVE site (identified as “BADL1”) located on a gently sloping flat in the eastern portion 

of the Badlands National Park, approximately two miles northeast of Interior, South Dakota. 

DENR operates an ambient air monitoring site at the same location (see Figure 3-3). The site 
9 

elevation is 2,415 feet and the lowest elevation in the area is the White River at 2,320 feet, 

approximately two miles south of the monitoring site. 

The Wind Cave National Park operates an IMPROVE site (identified as “WICA1”) located near 

the park’s visitors center (see Figure 3-4). Site elevation at the monitoring site is 4,240 feet and 

the general topography is hilly. 

Figure 3-2 – Comparison at Different Levels

Deciview = 5; Bext = 16; visual range = 240 km 

Deciview = 11; Bext = 30; visual range = 130 km 

Deciview = 19; Bext = 65; visual range = 60 km 

Deciview = 23; Bext = 98; visual range = 40 km 
10 

Figure 3-3 – Badlands’ IMPROVE and State Monitoring Site

Figure 3-4 – Wind Caves’ IMPROVE and State Monitoring Site
11 

3.1 Baseline Visibility Conditions 

In accordance with 40 CFR § 51.308(d)(2)(i), baseline visibility conditions for the most impaired 

and least impaired days are calculated using available monitoring data from calendar year 2000 

to 2004. The rule requires the state to establish the average degree of visibility impairment for 

the most and least impaired days for each calendar year from 2000 to 2004 and average these 

annual values to determine the baseline visibility conditions. 

DENR determined the baseline visibility conditions for the Badlands and Wind Cave National 

Parks based on IMPROVE data from the respective park. In the case where a day in the 

IMPROVE database did not have enough data to calculate a deciview value, the data was not 

considered in determining the baseline visibility conditions. The baseline visibility conditions 

was determined by calculating the average deciview value for the 20% least impaired (best) and 

most impaired (worst) days for each of the five years (2000 through 2004) and by averaging 

those five year values. The baseline visibility conditions for the Badlands and Wind Cave 

National Parks are summarized in Table 3-1. 

Table 3-1 – Baseline Visibility Conditions in South Dakota’s National Parks 

Badlands National Park Wind Cave National Park 

20% Least 20% Most 20% Least 20% Most 

Calendar Year Deciviews Deciviews Deciviews Deciviews 

2000 7.46 18.14 5.62 16.07 

2001 7.45 17.63 5.11 15.47 

2002 6.69 16.18 5.24 16.75 

2003 6.34 17.81 5.02 16.12 

2004 6.62 16.04 4.82 15.25 

5-Year Average 6.91 17.14 5.16 15.84 

The actual raw IMPROVE data used to determine the baseline visibility conditions may be 

viewed at the following website: 

http://views.cira.colostate.edu/web/DataWizard/

3.2 Natural Visibility Conditions 

In accordance with 40 CFR § 51.308(d)(2)(iii), a core requirement in the State Implementation 

Plan for the regional haze program is the establishment of natural visibility conditions for the 

20% most impaired and 20% least impaired days. To assists states in determining natural 

visibility conditions, EPA published “Guidance for Estimating Natural Visibility Conditions 

Under the Regional Haze Program”, in September 2003. The guidance identifies the primary 

cause of regional haze for many parts of the country is due to light scattering resulting from fine 

particles (e.g., particulate matter 2.5 microns in diameter or less). The fine particulate is 

composed of a variety of chemical species such as carbonaceous species (e.g., organics and 
12 

elemental carbon) as well as ammonia, nitrate, sulfates, and soil. Coarse particulate which is 

particulate matter ranging in size from 2.5 to 10 microns in diameter can also contribute to light 

scattering. These components can occur both naturally and as the result of human activity. 

The ultimate goal of the regional haze program is to remedy existing and prevent human-caused 

impairments of visibility and achieve natural conditions in each Class I area by 2064. It is 

recognized that natural conditions are not constant; but change over time. To compensate for 

varying natural processes, natural visibility conditions are based on a long term average 

condition analogous to the 5-year average conditions for the 20% most impaired and 20% least 

impaired days. In addition, as the difference between current and natural conditions become 

smaller and methods of estimating natural conditions improve, natural conditions may change as 

the regional haze program for each state is re-evaluated. 

The natural condition for each Class I area is defined as the level of visibility (in deciviews) for 

the 20% most impaired days and 20% least impaired days that would exist if there were no 

manmade impairment. Since no visibility monitoring data exists from the pre-manmade 

impairment period, the EPA developed guidance on how to estimate natural conditions. 

Generally, for each Class I area in the western United States, the natural condition for the 20% 

most impaired days is determined by adding two standard deviations to the annual average of 

IMPROVE monitoring data. Similarly, the natural condition for the 20% least impaired days is 

determined by subtracting two standard deviations to the annual average of the IMPROVE 

monitoring data. 

EPA’s guidance on determining natural conditions provides two methods of estimating natural 

conditions. The first method is considered the default natural conditions. In this method, EPA 

provides estimates of natural conditions for each Class I area. In the second method, states may 

estimate site specific natural conditions if the state can provide sufficient evidence that supports 

refined natural conditions. 

3.2.1 Default Natural Conditions 

EPA developed default values for natural conditions to assist states in determining natural 

conditions. EPA’s estimates for the natural levels of fine particulate constituents and of coarse 

particles were derived from the National Acid Precipitation Assessment Program (NAPAP) 

“Acidic Deposition: State of Science and Technology: Report 24 – Visibility: Existing and 

Historical Conditions – Cause and Effects”, published in October 1990. The estimate of natural 

conditions presented in the NAPAP report separates the regions of the United States into the 

eastern half and western half. The eastern half consists of all states east of the Mississippi River, 

and up to one tier of states west of the Mississippi River. The western half includes the desert 

and mountain regions of the Mountain and Pacific Time zones. From this description, South 

Dakota is located in the western region; but should be evaluated to determine which natural 

conditions best represent South Dakota since it is on the border of the eastern and western half. 

The NAPAP report estimated natural background concentrations for six major components of 

fine aerosols: sulfates, organics, elemental carbon, ammonium nitrate, soil dust, and water for the 

eastern and western regions of the United States. The NAPAP report also estimated the natural 
13 

background for coarse particulate matter. The estimates of natural concentration were based on 

the following: 

1. Compilations of natural versus manmade emission levels; 

2. Ambient measurements in remote areas (especially in the Southern hemisphere); and 

3. Regressions studies using manmade and/or natural tracers. 

EPA mentioned in the guidance the studies cited in the Appendix of the NAPAP report were 

conducted in relatively remote areas. Therefore, EPA believes it is reasonable to assume the 

contribution of fire to the particulate matter mass in the NAPAP estimates represents the natural 

regional contribution of fire. DENR is not sure it agrees with this assumption since fire 

suppression has occurred for many years disrupting the natural fire process even in remote areas. 

Table 3-2 lists the average natural background levels of aerosols and light extinction and was 

derived from Table 2-1 of EPA’s guidance, which is different than the natural background levels 

established in the NAPAP report. The reason for the difference is noted in the footnotes for 

Table 3-2. There was no value listed for sea salt. 

Table 3-2 – Average Natural Background Concentration Levels 

Aerosol Component East (μg/m3) West (μg/m3) 

Ammonium sulfate 1 0.23 0.12

Organic carbon mass 2 1.40 0.47

Elemental carbon 0.02 0.02

Ammonium nitrate 0.1 0.1

Soil Dust 0.5 0.5

Coarse Mass 3.0 3.0

1

 – Values adjusted to represent chemical species in current IMPROVE light extinction algorithm; 

Trijonis estimates were 0.1 micrograms per cubic meter (μg/m3

) and 0.2 μg/m3 of ammonium 

bisulfate; and 2

 – Values adjusted to represent chemical species in current IMPROVE light extinction algorithm; 

Trijonis estimates were 0.5 μg/m3

 and 1.5 μg/m3 of organic compounds. 

The average natural background concentrations levels in Table 3-2 were used in the formula 

displayed in Equation 3-1 to determine the natural light extinction (bext), which is used to 

characterize air pollution impacts on visibility. Light extinction is the fractional loss of the 

intensity of light per unit of distance caused by the scattering and absorption of gases and 

particles in the air. 

Equation 3-1 – Natural Light Extinction Formula 

bext            3 f RH sulfate  3 f RH nitrate  4OCM  10LAC  soil     0.6 CM 10

Where: 

 bext = natural light extinction, in Mm-1

; 

 f(RH) = relative humidity correction factor; 

 OCM = organic carbon mass, in μ/m3

; 

 LAC = elemental carbon, in μ/m3

; and 

 CM = coarse mass, in μ/m3

. 
14 

The natural condition for South Dakota’s Class I areas based on the formula in Equation 3-1 are 

listed in Table 3-3 and derived from Appendix B in EPA’s guidance for estimating natural 

conditions. 

Table 3-3 –Natural Background Conditions for South Dakota’s Class I Areas 

Class I 

Area Bext 1 

Annual 

Average 

20% Least Impaired 

Days 

20% Most Impaired 

Days 

Badlands 16.06 4.74 deciview 2.18 deciview 7.30 deciview 

Wind Cave 15.97 4.68 deciview 2.12 deciview 7.24 deciview 

1

 – Natural light extinction in inverse Mega meters (Mm-1). 

3.2.2 Improved Default Natural Conditions 

Since EPA’s guidance was written a revised natural light extinction formula was developed and 

adopted by EPA as the basis for the regional haze metric used to track progress in reducing haze 

levels in Class I areas. The new IMPROVE equation accounts for the effect of particle size 

distribution on light extinction of small and large size sulfate, nitrate and organic carbon mass. 

The revised formula is displayed in Equation 3-2. 

Equation 3-2 – Revised Natural Light Extinction Formula 

0.33[ ( )]

10[ ] [ ] 0.6[ ] 1.7 ( )[ ]

5.1 ( )[ arg ] 2.8[ ] 6.1[ arg ]

2.2 ( )[ ] 4.8 ( )[ arg ] 2.4 ( )[ ]

Rayleigh Scattering NO2 ppb

light absorbing carbon soil coarse matter f RH sea salt

f RH l e nitrate small organic mass l e organic mass

b f RH small sulfate f RH l e sulfate f RH small nitrate

ss

L

ext s L s

 

   

  

  

The total sulfate, nitrate and organic compound concentrations are split into two fractions 

representing small and large size distributions of each component. The formula for the large and 

small sulfate, nitrate and organic mass is displayed in Equation 3-3. In addition, the relative 

humidity correction factor in Equation 3-2 is also based on small size distribution (fS(RH)) and 

large size distribution (fL(RH)) for sulfate and nitrate and for sea salt (fSS(RH)). The relative 

humidity correction factors were derived from the “Federal Land Managers’ Air Quality Related 

Values Workgroup (FLAG),” drafted June 27, 2008, and can be viewed in Table 3-4. 

Equation 3-3 – Large and Small Formulas 

     

  

    Small Total L e

m

ug L e Total for Total

m

ug Total for Total

m

ug

Total L e

arg

arg 20

, 20

20

arg

3

3

3

 

 

  
15 

Table 3-4 – Relative Humidity Correction Factor (f(RH)) 

Class I Month 

Size Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

Badlands 

Small 2.94 2.96 3.01 2.87 3.10 2.91 2.64 2.59 2.56 2.58 3.11 2.98 

Large 2.31 2.31 2.31 2.21 2.34 2.25 2.08 2.05 2.02 2.05 2.38 2.33 

Sea Salt 3.37 3.33 3.27 3.05 3.25 3.15 2.89 2.81 2.74 2.82 3.41 3.38 

Wind Cave 

Small 2.81 2.81 2.86 2.82 3.06 2.81 2.50 2.46 2.44 2.52 2.97 2.83 

Large 2.23 2.22 2.22 2.18 2.32 2.18 2.00 1.97 1.95 2.00 2.30 2.24 

Sea Salt 3.25 3.20 3.13 3.01 3.22 3.06 2.75 2.68 2.63 2.75 3.28 3.24 

The result of the revised light extinction is used in the formula displayed in Equation 3-4 to 

estimate the annual average of the haze index values (HI), in deciviews. DENR calculated the 

HI value for each month for each Class I area. The average HI value for each Class I area may 

be viewed in Table 3-5. 

Equation 3-4 – Annual Average Haze Index 

HI  10ln  bext 10

Where: 

 HI = annual average of the haze index values, in deciviews; and 

 bext = natural light extinction, in Mm-1. 

In EPA’s guidance, it was determined that the frequency distribution behaves normally (10th and 

90th percentile HI) for Class I areas. This allows the 20% least impaired and 20% most impaired 

days to be determined using the annual average haze index and the formulas in Equation 3-5 and 

3-6, respectively. In EPA’s guidance, it was determined that the average standard deviation in 

the East is 3 deciviews and in the West it is 2 deciviews. DENR stayed consistent with using 

western values and used a standard deviation of 2 deciviews. The 10th and 90th percentile was 

calculated for each month for each Class I area. The results may be viewed in Table 3-5. 

Equation 3-5 – Natural Least Impaired Days Formula 

P10  HI 1.28sd

Equation 3-6 – Natural Most Impaired Days Formula 

P90  HI 1.28sd

Where: 

 P10 = Natural 20% least impaired days, in deciviews; 

 P90 = Natural 20% most impaired days, in deciviews; 

 HI = annual average haze index, in deciviews; and 

 sd = standard deviation of the daily haze index values for that area, in deciviews. 
16 

Table 3-5 –New Formula Natural Background Conditions for South Dakota’s Class I Areas 

Class I Annual Average Natural Background 

Area Haze Index Least Impaired Days Most Impaired Days 

Badlands 4.88 deciview 2.32 deciview 8.06 deciview 

Wind Cave 4.85 deciview 2.29 deciview 7.41 deciview 

3.2.3 Baseline and Default Natural Conditions Comparison 

The natural background concentration levels are estimated for long term average conditions. In 

some cases the natural background concentration level may have higher concentrations than the 

baseline concentrations or for any other 5-year period. If this occurs, EPA’s guidance 

recommends that the natural background concentration level should be replaced with the 

corresponding measured value. 

DENR used the IMPROVE data from each national park to determine the baseline concentration 

and compared the concentrations to the natural background concentrations in Table 3-2. Table 

3-6 displays the comparison. 

Table 3-6 – Comparison of Natural versus Baseline Concentrations 1

Background 

Natural Badlands Wind Cave 

West Least Most Least Most 

Aerosol Component (μg/m3) (μg/m3) (μg/m3) (μg/m3) (μg/m3)

Ammonium sulfate 0.12 2

 0.49 2.63 0.41 2.07 

Organic carbon mass 0.47 3

 0.62 3.17 0.50 3.55 

Elemental carbon 0.02 0.08 0.26 0.07 0.30 

Ammonium nitrate 0.10 0.16 0.76 0.12 0.98 

Soil Dust 0.50 0.33 0.98 0.24 0.86 

Coarse Mass 3.00 2.53 9.90 1.78 5.89 

1

 – Units are in micrograms per cubic meter (μg/m3); 2

 – Values adjusted to represent chemical species in current IMPROVE light extinction algorithm; 

Trijonis estimate was 0.1 μg/m3

 of ammonium bisulfate; and 3

 – Values adjusted to represent chemical species in current IMPROVE light extinction algorithm; 

Trijonis estimate was 0.5 μg/m3

 of organic compounds. 

Based on the comparison, the aerosol components in the baseline data for 2000 through 2004 for 

the 20% least impaired days are less than the natural conditions for soil dust and coarse mass at 

both the Badlands and Wind Cave National Parks (see bolded values in Table 3-6). Although the 

soil dust and coarse mass for the baseline data is less than the values for natural conditions, 

DENR will use the values established in EPA’s guidance for the initial Regional Haze State 

Implementation Plan and re-evaluate this in future State Implementation Plan reviews. Table 3-7 

displays the natural conditions and compares it to the baseline data for 2000-2004. 
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 17.14 8.06 9.08 

Wind Cave 5.16 2.29 2.87 15.84 7.41 8.43 

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. 
20 

Table 4-1 – Badlands National Park Baseline Aerosol Concentrations 1

a) Aerosol Concentrations for 20% Least Impaired

 P10 ammSO4f ammNO3f OMC Ecf SOIL CM Sea Salt 

Year (Deciview) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) 

2000 7.46 0.64 0.20 0.64 0.08 0.26 2.08 0.01 

2001 7.45 0.57 0.21 0.64 0.09 0.39 2.60 0.00 

2002 6.69 0.37 0.12 0.62 0.09 0.44 3.21 0.00 

2003 6.34 0.44 0.11 0.61 0.06 0.25 2.38 0.00 

2004 6.62 0.43 0.17 0.57 0.07 0.33 2.39 0.01 

5-yr 6.91 0.49 0.16 0.62 0.08 0.33 2.53 0.00 

Natural 2.32 0.12 0.10 0.47 0.02 0.50 3.00 0.00 

b) Aerosol Concentrations for 20% Most Impaired 

 P90 ammSO4f ammNO3f OMC Ecf SOIL CM Sea Salt 

Year (Deciview) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) 

2000 18.14 2.72 0.50 4.78 0.40 1.00 10.14 0.00 

2001 17.63 3.13 0.95 2.38 0.26 1.29 9.79 0.00 

2002 16.18 2.45 0.63 2.22 0.19 1.14 12.17 0.10 

2003 17.81 2.27 0.91 4.03 0.29 0.73 11.65 0.06 

2004 16.04 2.55 0.83 2.43 0.16 0.74 5.77 0.02 

5-yr 17.16 2.63 0.76 3.17 0.26 0.98 9.90 0.04 

Natural 7.44 0.12 0.10 0.47 0.02 0.50 3.00 0.00 

1

 – Units are in micrograms per cubic meter (μg/m3), “P10” = 20% least impaired days, “P90” = 20% 

most impaired days, “ammSO4f” = ammonia sulfate fine; “ammNO3f” = ammonia nitrate fine, 

“OMC” = organic mass carbon, “Ecf” = Elemental carbon fine, and “CM” = coarse mass. 

Table 4-2 – Wind Cave National Park Baseline Aerosol Concentrations 1

a) Aerosol Concentrations for 20% Least Impaired 

 P10 ammSO4f ammNO3f OCM Ecf SOIL CM Sea Salt 

Year (Deciview) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) 

2000 5.62 0.49 0.15 0.59 0.09 0.18 1.24 0.00 

2001 5.11 0.43 0.13 0.44 0.06 0.28 1.75 0.00 

2002 5.24 0.36 0.10 0.48 0.07 0.30 2.57 0.01 

2003 5.02 0.40 0.08 0.54 0.06 0.22 1.89 0.00 

2004 4.82 0.38 0.12 0.44 0.07 0.22 1.44 0.00 

5-yr 5.16 0.41 0.12 0.50 0.07 0.24 1.78 0.00 

Natural 2.29 0.12 0.10 0.47 0.02 0.50 3.00 0.00 

b) Aerosol Concentrations for 20% Most Impaired 

 P90 ammSO4f ammNO3f OCM Ecf SOIL CM Sea Salt 

Year (Deciview) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) 

2000 16.07 1.86 0.68 4.33 0.37 0.97 6.57 0.00 

2001 15.47 2.25 1.26 2.48 0.23 0.82 5.99 0.00 

2002 16.75 2.26 0.87 4.15 0.31 0.98 6.78 0.00 
21 

 P90 ammSO4f ammNO3f OCM Ecf SOIL CM Sea Salt 

Year (Deciview) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) (u/m3) 

2003 16.12 2.03 0.86 4.00 0.24 0.75 6.60 0.01 

2004 15.25 1.94 1.24 2.79 0.33 0.77 3.49 0.02 

5-yr 15.93 2.07 0.98 3.55 0.30 0.86 5.89 0.01 

Natural 7.41 0.12 0.10 0.47 0.02 0.50 3.00 0.00 

1

 – Units are in micrograms per cubic meter (μg/m3), “P10” = 20% least impaired days, “P90” = 20% 

most impaired days, “ammSO4f” = ammonia sulfate fine; “ammNO3f” = ammonia nitrate fine, 

“OMC” = organic mass carbon, “Ecf” = Elemental carbon fine, and “CM” = coarse mass. 

The aerosol concentrations that appear to need to be reduced the most to achieve natural 

concentrations at both national parks are ammonia sulfate and elemental carbon. Ammonia 

sulfates are derived from fossil fuel combustion and the combustion of organic mass such as 

forest fires and the burning of grass. Elemental carbon is also generated from fossil fuel 

combustion; but is generally used as the main indicator of emissions from fires and other 

combustion sources such as diesel emissions. 

Organic carbon mass and ammonia nitrate aerosol concentrations at the two national parks would 

also need to be reduced since current concentrations are approximately seven to 10 times greater 

than natural conditions. Organic carbon mass is derived from biomass burning, automobile 

emissions, fossil fuel combustion, gas-to-particle conversion of hydrocarbons, etc. Ammonia 

nitrates are generated from similar sources that generate ammonia sulfates along with organic 

decomposition. 

4.2 Extinction Comparison 

Extinction (inverse mega meters (Mm-1)) is useful in relating visibility directly to particle species 

concentrations. DENR took the IMPROVE data for the baseline period (2000-2004) for the 20% 

least and 20% most impaired days and summarized it in Table 4-3 for the Badlands National 

Park and Table 4-4 for the Wind Cave National Park, except for sea salt since the concentrations 

for sea salt are minimal. 

Table 4-3 – Badlands National Park 1

a) Baseline Aerosol Concentrations for 20% Least Impaired 

 Extinction (bext) ammSO4f ammNO3f OMC Ecf SOIL CM 

Year (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1)

2000 21.28 4.53 1.50 1.88 0.82 0.26 1.25 

2001 21.15 3.85 1.58 1.87 0.89 0.39 1.56 

2002 19.58 2.57 0.91 1.82 0.91 0.44 1.93 

2003 18.90 3.00 0.81 1.78 0.63 0.25 1.43 

2004 19.44 3.01 1.32 1.64 0.66 0.33 1.43 

5-yr 20.07 3.39 1.23 1.80 0.78 0.33 1.52 

% Without Rayleigh 36% 14% 20% 9% 4% 17% 
22 

b) Baseline Aerosol Concentrations for 20% Most Impaired 

 Extinction (bext) ammSO4f ammNO3f OMC Ecf SOIL CM 

Year (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1)

2000 63.49 18.99 3.63 18.74 4.04 1.00 6.08 

2001 59.32 23.25 7.41 7.93 2.56 1.29 5.87 

2002 51.28 17.43 4.68 7.36 1.86 1.14 7.30 

2003 61.53 16.19 7.18 16.22 2.90 0.73 6.99 

2004 50.73 18.83 6.48 8.53 1.57 0.74 3.46 

5-yr 57.27 18.94 5.88 11.76 2.59 0.98 5.94 

% Without Rayleigh 41% 13% 25% 6% 2% 13% 

1

 – Units are in inverse Mega meters (Mm-1), “Bext” = natural light extinction, “ammSO4f” = 

ammonia sulfate fine; “ammNO3f” = ammonia nitrate fine, “OMC” = organic mass carbon, “Ecf” = 

Elemental carbon fine, and “CM” = coarse mass. 

Table 4-4 – Wind Cave National Park 1

a) Aerosol Concentrations for 20% Least Impaired 

 Extinction (bext) ammSO4f ammNO3f OMC Ecf SOIL CM 

Year (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1)

2000 17.71 3.12 1.07 1.72 0.87 0.18 0.74 

2001 16.75 2.65 0.88 1.27 0.63 0.28 1.05 

2002 16.95 2.27 0.68 1.38 0.74 0.30 1.54 

2003 16.58 2.48 0.53 1.58 0.63 0.22 1.14 

2004 16.26 2.41 0.82 1.27 0.67 0.22 0.86 

5-yr 16.85 2.58 0.80 1.44 0.71 0.24 1.07 

% Without Rayleigh 38% 12% 21% 10% 3% 16% 

b) Aerosol Concentrations for 20% Most Impaired 

 Extinction (bext) ammSO4f ammNO3f OMC Ecf SOIL CM 

Year (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1) (Mm-1)

2000 51.94 11.60 4.69 17.00 3.74 0.97 3.94 

2001 48.76 14.58 9.25 8.22 2.28 0.82 3.59 

2002 56.18 14.98 6.06 16.95 3.14 0.98 4.07 

2003 51.05 12.66 6.19 15.05 2.40 0.75 3.96 

2004 47.94 12.80 9.19 9.73 3.25 0.77 2.09 

5-yr 51.18 13.32 7.07 13.39 2.96 0.86 3.53 

% Without Rayleigh 32% 17% 33% 7% 2% 9% 

1

 – Units are in inverse Mega meters (Mm-1), “Bext” = natural light extinction, “ammSO4f” = 

ammonia sulfate fine; “ammNO3f” = ammonia nitrate fine, “OMC” = organic mass carbon, “Ecf” = 

Elemental carbon fine, and “CM” = coarse mass. 

DENR included in each table the percentage of visibility impairment based on each aerosol’s 

contribution to the extinction after subtracting out the Rayleigh affect. The Rayleigh affect is the 

scattering of light by particles much smaller than the wavelength of light. The percentages of 

extinction per aerosol for the 20% least and most impaired days for the Badlands and Wind Cave 

National Parks are displayed in Figure 4-1 and 4-2, respectively. 
23 

Figure 4-1 – Badlands National Park Baseline Aerosol Extinction Comparison 1

a) Baseline Aerosol Extinction Percentage for 20% Least Impaired Days 

36%

14%

20%

9%

4%

17%

0%

ammSO4f ammNO3f OCM Ecf SOIL CM Sea Salt

b) Baseline Aerosol Extinction Percentage for 20% Most Impaired Days 

41%

13%

25%

6%

2%

13%

0%

ammSO4f ammNO3f OCM Ecf SOIL CM Sea Salt

1

 – “ammSO4f” = ammonia sulfate fine; “ammNO3f” = ammonia nitrate fine, “OMC” = organic mass 

carbon, “Ecf” = Elemental carbon fine, and “CM” = coarse mass. 

In the 20% least impaired days for the Badlands National Park, the aerosol that contributed the 

greatest visibility impairment is ammonia sulfate at 36%, which is almost double the percentage 

of the second greatest contributor. The second greatest contributor is organic carbon mass at 

20%. The third greatest contributor is coarse mass at 17% followed closely by ammonia nitrates 

at 14%. Ammonia sulfate, organic carbon mass, coarse mass and ammonia nitrate represent 87% 
24 

of the aerosol concentrations impacting the 20% least impaired days in the Badlands National 

Park. 

In the 20% most impaired days for the Badlands National Park, the aerosol that contributed the 

greatest visibility impairment again is ammonia sulfate at 41%. Its contribution is not double the 

percentage of the second greatest contributor; but is close. The second greatest contributor is 

organic carbon mass at 25%. The third greatest contributor is coarse mass and ammonia nitrates 

at 13%, each. Ammonia sulfate, organic carbon mass, coarse mass and ammonia nitrate 

represent 92% of the aerosol concentrations impacting the 20% most impaired days in the 

Badlands National Park. 

Figure 4-2 – Wind Cave Baseline Aerosol Extinction Percentage 

a) Baseline Aerosol Extinction Percentage for 20% Least Impaired Days 1

38%

12%

21%

10%

3%

16%

0%

ammSO4f ammNO3f OCM Ecf SOIL CM Sea Salt

1

 – “ammSO4f” = ammonia sulfate fine; “ammNO3f” = ammonia nitrate fine, “OMC” = organic mass 

carbon, “Ecf” = Elemental carbon fine, and “CM” = coarse mass. 

In the 20% least impaired days for the Wind Cave National Park, the aerosol that contributed the 

greatest visibility impairment is ammonia sulfate at 38%, which is almost double the percentage 

of the second greatest contributor. The second greatest contributor is organic carbon mass at 

21%. The third greatest contributor is coarse mass at 16% followed by ammonia nitrates at 12%. 

Ammonia sulfate, organic carbon mass, coarse mass and ammonia nitrate represent 87% of the 

aerosol concentrations impacting the 20% least impaired days in the Wind Cave National Park. 

In the 20% most impaired days for the Wind Cave National Park, the aerosol that contributed the 

greatest visibility impairment is organic carbon mass at 33%, followed closely by ammonia 

sulfate at 32%. The third greatest contributor is ammonia nitrates at 17% followed by coarse 

mass at 9%. Ammonia sulfate, organic carbon mass, coarse mass and ammonia nitrate represent 

91% of the aerosol concentrations impacting the 20% most impaired days in the Wind Cave 

National Park. 
25 

b) Baseline Aerosol Extinction Percentage for 20% Most Impaired Days 1

32%

17%

33%

7%

2%

9% 0%

ammSO4f ammNO3f OCM Ecf SOIL CM Sea Salt

1

 – “ammSO4f” = ammonia sulfate fine; “ammNO3f” = ammonia nitrate fine, “OMC” = organic mass 

carbon, “Ecf” = Elemental carbon fine, and “CM” = coarse mass. 

There is a good comparison between the 5-year average concentration for each aerosol at the 

Badlands and Wind Cave National Park during the 20% least impaired days (see Figure 4-3(a)). 

Although these concentrations represent the 20% least impaired days, the concentrations are still 

greater than natural conditions. DENR did not anticipate the two national parks to have similar 

concentrations since the Badlands National Park is predominantly mixed prairie grasses, bare 

rock and sand while the Wind Cave National Park is mixed prairie grasses and ponderosa pine 

forest. 

Local influences on the 20% least impaired days would tend to influence just the park it is next 

to and not the other. If local influences were impacting the 20% least impaired days, 

concentrations at both parks would not be that similar. However, the 5-year averaging may 

smooth this out. 

Depending on the distance, concentrations from regional influence would be well mixed and 

uniform as it impacts South Dakota’s two Class I areas. A uniform regional influence would tend 

to influence both national parks similarly. 

DENR will evaluate this in its long-term strategy to determine if there are any impacts from local 

sources hidden by the 5-year average and/or if regional influence is the main reason for the 

elevated concentrations on the 20% least impaired days. 
26 

Figure 4-3 – National Park Extinction Comparison 1

a) National Park Comparison for 20% Least Impaired Days 

0%

5%

10%

15%

20%

25%

30%

35%

40%

ammSO4f OCM CM ammNO3f Ecf SOIL Sea Salt

Badlands Wind Cave

b) National Park Comparison for 20% Most Impaired Days 

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

ammSO4f OCM ammNO3f CM Ecf SOIL Sea Salt

Badlands Wind Cave

1

 – “ammSO4f” = ammonia sulfate fine; “ammNO3f” = ammonia nitrate fine, “OMC” = organic mass 

carbon, “Ecf” = Elemental carbon fine, and “CM” = coarse mass. 

For the 20% most impaired days, the comparison is not as similar. From Figure 4.3(b), ammonia 

sulfate is impacting visibility at the Badlands National Park at a greater degree than it is at the 

Wind Cave National Park. At the Wind Cave National Park, organic carbon mass and ammonia 

sulfate have the greatest impact and provide approximately the same percentage of visibility 

impairment. This indicates that fires contribute more to visibility impairment at Wind Cave 
27 

National Park then at Badlands National Park because of the higher organic carbon mass 

contribution. 

Ammonia sulfates and organic carbon mass are generated from similar sources. Ammonia 

sulfates are derived from fossil fuel combustion and the combustion of organic mass such as 

forest fires and the burning of grass. Organic carbon mass is derived from biomass burning, 

automobile emissions, fossil fuel combustion, gas-to-particle conversion of hydrocarbons, etc. 

The contribution of ammonia sulfates and organic carbon mass from fossil fuel combustion from 

industrial sources and mobile sources should tend to be constant throughout the year. The 

contribution from the burning of organic mass or from heating should tend to occur at certain 

times of the year and be evident by quarter. 

4.3 Visibility Impairment Quarterly Trends 

Visibility impairment is impacted by the aerosol concentrations, type of aerosols, and time of 

year. DENR looked at various charts to determine if there were any trends based on the time of 

year for the 20% most impaired days. DENR reviewed the charts by quarter. For this review, 

the first quarter represents the winter months (January through March); the second quarter 

represents the spring months (April through June); the third quarter represents the summer 

months (July through September); and the fourth quarter represents the fall months (October 

through December). 

4.3.1 Number of Occurrences per Quarter 

The first type of chart DENR looked at was the number of occurrences per quarter for the 20% 

most impaired days. Figure 4-4 provides the quarterly comparison for the Badlands National 

Park and Wind Cave National Park. 

Figure 4-4 –Number of Occurrences by Quarter – 20% Most Impaired Days 

a) Badlands National Park Occurrences by Quarter 

0

2

4

6

8

10

12

14

Occurrences

1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

1st 2nd 3rd 4th
28 

b) Wind Cave National Park Occurrences by Quarter 

0

2

4

6

8

10

12

14

16

Occurrences

2000 2001 2002 2003 2004 2005 2006 2007 2008

1st 2nd 3rd 4th

Based on the Badlands National Park data, the 4th quarter (fall months) consistently appear to 

have the least number of visibility impairment occurrences during the 20% most impaired days, 

especially for the baseline period (2000-2004). The 4th quarter did experience an increase in 

2008, which will need to be reviewed in the future to see if the increase continues. The 

occurrences in the remaining quarters increase and decrease with the 3rd quarter (summer 

months) having the most occurrences in the baseline period and in the last four years of data. 

One thing to note is the 2nd quarter (spring months) is showing an increase in occurrences in the 

last three years, which will also need to be reviewed if this trend continues. 

The number of occurrences ranged from zero to 13 occurrences per quarter. The greatest number 

of occurrences peaked in the 1st quarter of 1993 at 13. From 2000 to 2008, the greatest number 

of occurrences occurs in the 3rd quarter ranging from six to 12 occurrences per year. The 2nd and 

4th quarter saw a rise in 2008 with the 1st quarter showing a decline. 

Overall, in the last few years the 2nd and 3rd quarter tend to have the most occurrences while the 

1st and 4th quarter have the least number of occurrences. The number of occurrences in the 2nd

quarter has increased to where they had the most occurrences in 2008, followed by the 3rd

quarter, 4th quarter and 1st quarter. 

The number of occurrences in the Wind Cave National Park range from zero to 15 occurrences 

per quarter during the 20% most impaired days. The greatest number of occurrences occurred in 

the 3rd quarter during the baseline period (2000-2004) and peaked in 2003 at 15 occurrences. 

The 4th quarter consistently had the least number of occurrences in the baseline period and 

ranged from two to four occurrences per quarter. For the last four years, the greatest number of 

occurrences occurred in the 3rd quarter ranging from six to 10 occurrences per year. The 4th

quarter appears to have the least amount of occurrences ranging from zero to four occurrences 

per year. However, in 2008 the number of occurrences in the 1st quarter dropped to where it has 

the least number of occurrences at two. 
29 

4.3.2 Extinction Trends by Quarter 

DENR also charted the average extinction value for each quarter for ammonia sulfate, ammonia 

nitrate, organic carbon mass, and coarse mass during the 20% most impaired days for each 

national park since these four air pollutants comprise over 90% of the visibility impairment in 

each park. Figure 4-5 and 4-6 display the quarterly data from 2000, which is the start of the 

baseline period, to 2008 for the Badlands and Wind Cave National Parks, respectively. In some 

cases, there is no quarterly extinction value for a certain year, which means there were no days 

that contributed to the 20% most impaired days during that quarter. 

In the 1st quarter, ammonia sulfate followed by ammonia nitrate have the greatest impact on 

visibility impairment in the Badlands National Park. Organic carbon mass and coarse mass have 

minimal impact in the 1st quarter with an extinction value of approximately 5.0 inverse mega 

meters or less per pollutant. However, in 2008 organic carbon mass did increase from the 

normal trend to exceed ammonia nitrate in impacting visibility impairment but still had less 

impact then ammonia sulfate. 

Figure 4-5 – Badlands’ Quarterly Extinction Values for 20% Most Impaired Days 

a) Badlands: 1st Quarter Average Extinction Comparison 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

Mm-1

2000 2001 2002 2003 2004 2005 2006 2007 2008

Ammonia Sulfate Organic Carbon Mass Ammonia Nitrate Coarse Mass

In the 2nd quarter, ammonia sulfate still has the greatest impact on visibility impairment in the 

Badlands National Park. The 2nd quarter differs from the 1st quarter with organic carbon mass 

tending to contribute more than ammonia nitrate. However, in some cases, organic carbon mass, 

ammonia nitrate, and coarse mass have approximately equal share in visibility impairment. 
30 

b) Badlands: 2nd Quarter Average Extinction Comparison 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

Mm-1

2000 2001 2002 2003 2004 2005 2006 2007 2008

Ammonia Sulfate Organic Carbon Mass Ammonia Nitrate Coarse Mass

In the 3rd quarter, organic carbon mass tends to contribute the greatest impact on visibility 

impairment followed by ammonia sulfate. What is interesting is ammonia nitrate in the 3rd

quarter consistently contributes the least to visibility impairment with coarse mass being 

consistently higher than ammonia nitrate. The 3rd quarter is typically the driest months in the 

Badlands National Park which would increase in coarse mass contributions from windblown dust 

and from traffic on paved and unpaved roads. In 2008, organic carbon mass increased 

dramatically due to a one day extinction value in the 3rd quarter of 192 inverse mega meters on 

July 2, 2008. Looking ahead to the 3rd quarter for the Wind Cave National Park (see Figure 4-

6(d)), Wind Cave National Park experienced a high level of organic carbon mass on that same 

day.

c) Badlands: 3rd Quarter Average Extinction Comparison 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

Mm-1

2000 2001 2002 2003 2004 2005 2006 2007 2008

Ammonia Sulfate Organic Carbon Mass Ammonia Nitrate Coarse Mass
31 

d) Badlands: 4th Quarter Average Extinction Comparison 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

Mm-1

2000 2001 2002 2003 2004 2005 2006 2007 2008

Ammonia Sulfate Organic Carbon Mass Ammonia Nitrate Coarse Mass

In the 4th quarter, ammonia sulfate continues to contribute the greatest to visibility impairment in 

the Badlands National Park followed by ammonia nitrate. Organic carbon mass tends to be a 

significant contributor with extinction values greater than 5.0 inverse mega meters. Coarse mass 

extinction values were greater than 5.0 inverse mega meters in the early 2000 but have since 

dropped below that level and have minimal impacts on visibility in the 4th quarter. 

Figure 4-6 – Wind Cave’s’ Quarterly Extinction Values for 20% Most Impaired Days 

a) Wind Cave: 1st Quarter Average Extinction Comparison 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

Mm-1

2000 2001 2002 2003 2004 2005 2006 2007 2008

Ammonia Sulfate Organic Carbon Mass Ammonia Nitrate Coarse Mass

In the 1st quarter, ammonia sulfate and ammonia nitrate have the greatest impact on visibility 

impairment in the Wind Cave National Park. Organic carbon mass and coarse mass do not 

appear to have as much impact in the 1st quarter with extinction values of around 5.0 inverse 

mega meters or less. 
32 

b) Wind Cave: 2nd Quarter Average Extinction Comparison 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

Mm-1

2000 2001 2002 2003 2004 2005 2006 2007 2008

Ammonia Sulfate Organic Carbon Mass Ammonia Nitrate Coarse Mass

In the 2nd quarter, ammonia sulfate has the greatest impact on visibility impairment in the Wind 

Cave National Park in the last five years. Organic carbon mass increased during that period with 

ammonia nitrate and coarse mass having minimal impact. 

c) Wind Cave: 3rd Quarter Average Extinction Comparison 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

Mm-1

2000 2001 2002 2003 2004 2005 2006 2007 2008

Ammonia Sulfate Organic Carbon Mass Ammonia Nitrate Coarse Mass

In the 3rd quarter, organic carbon mass has the greatest impact on visibility impairment followed 

by ammonia sulfate. Coarse mass is next and consistently around 5.0 inverse mega meters. 

Ammonia nitrate tends to have minimal impact in the 3rd quarter. The high organic carbon mass 

average in 2008 was also due to a 179 inverse mega meter reading on July 2, 2008. This is the 

same date which resulted in a high reading at the Badlands National Park, which is indicative of 

regional transport. On June 28, 2008, smoke from Canada forest fires were observed in the 

Black Hills region and probably is the source of the organic carbon mass concentrations on July 

2, 2008. 
33 

d) Wind Cave: 4th Quarter Average Extinction Comparison 

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

Mm-1

2000 2001 2002 2003 2004 2005 2006 2007 2008

Ammonia Sulfate Organic Carbon Mass Ammonia Nitrate Coarse Mass

In the 4th quarter, ammonia sulfates and ammonia nitrate continue to contribute the greatest with 

one exception in 2005. In 2005, organic carbon mass increased based on an October 25, 2005 

extinction value of 109 inverse mega meters. In this case, the same high reading was not 

observed in the Badlands National Park, which means the higher level may be caused locally. 

After researching possible causes, it was discovered on October 25, 2005, a prescribed fire 

covering 1,215 acres was burned in the Wind Cave National Park which could be the contributor 

of the high organic carbon mass concentration. 

This analysis indicates that ammonia sulfates and ammonia nitrate contributions are the greatest 

in the 1st and 4th quarter of each year at both national parks which is an indication the sources are 

being impacted by fuel combustion or even prescribed fires. Since it is occurring during the 

colder months, the sources of these emissions could also be caused by industrial and residential 

heating. Organic carbon mass tends to start contributing more in the 2nd quarter and is the 

greatest contributor in the 3rd quarter at both national parks. The driest months usually occur in 

the 3rd quarter, which is also when most wild fires typically occur. 

Coarse mass contributions are the greatest during the 2nd and 3rd quarters. During these quarters, 

you would typically have greater coarse mass emissions from windblown dust, traffic on paved 

and unpaved roads, etc. 

4.3.3 Visibility Impairment Trends 

DENR charted the average visibility (deciviews) that occurred in each national park for each 

quarter during the 20% most impaired days. Figure 4-7 and 4-8 display the quarterly data for the 

Badlands and Wind Cave National Parks, respectively. 

The average visibility impairment for the 20% most impaired days per quarter per year in the 

Badlands National Park, measured in deciviews, appears to be declining in every quarter except 

the 3rd quarter. In the 3rd quarter the slope appears to be flat. As seen in the quarterly extinction 
34 

review, the aerosol with the greatest contribution in the 3rd quarter is organic carbon mass and 

may be the reason the deciview values in the 3rd quarter are flat. 

Figure 4-7 – Badlands’ Quarterly Data for 20% Most Impaired Days 

a) Badlands: 1st Quarter Visibility Impairment Trend 

0.00

5.00

10.00

15.00

20.00

25.00

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007

Deciviews

1st Linear (1st)

b) Badlands: 2nd Quarter Visibility Impairment Trend 

0.00

5.00

10.00

15.00

20.00

25.00

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

Deciviews

2nd Linear (2nd)
35 

c) Badlands: 3rd Quarter Visibility Impairment Trend 

0.00

5.00

10.00

15.00

20.00

25.00

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

Deciviews

3rd Linear (3rd)

d) Badlands: 4th Quarter Visibility Impairment Trend 

0.00

5.00

10.00

15.00

20.00

25.00

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

Deciviews

4th Linear (4th)

The average visibility impairment for the 20% most impaired days per quarter per year in the 

Wind Cave National Park, measured in deciviews, appear flat with a slight increase in the 1st and 

2nd quarter. The slight increase in the 1st quarter appears to be the greatest. A review of the 

quarterly extinction data for the 1st quarter does not display an increase in any particular 

pollutant (see Figure 4.6(a)). There is some fluctuation in the ammonia sulfate and ammonia 

nitrate extinction values but that does not appear to be enough to result in such an increase in the 

slope. This will need to be reviewed in the future to see if the trend continues and what may be 

causing it. 
36 

Figure 4-8 – Wind Cave’s Quarterly Data for 20% Most Impaired Days 

a) Wind Cave: 1st Quarter Visibility Impairment Trend 

0.00

5.00

10.00

15.00

20.00

25.00

2000 2001 2002 2003 2004 2005 2006 2007 2008

Deciviews

1st Linear (1st)

b) Wind Cave: 2nd Quarter Visibility Impairment Trend 

0.00

5.00

10.00

15.00

20.00

25.00

2000 2001 2002 2003 2004 2005 2006 2007 2008

Deciviews

2nd Linear (2nd)

c) Wind Cave: 3rd Quarter Visibility Impairment Trend 

0.00

5.00

10.00

15.00

20.00

25.00

2000 2001 2002 2003 2004 2005 2006 2007 2008

Deciviews

3rd Linear (3rd)
37 

d) Wind Cave: 4th Quarter Visibility Impairment Trend 

0.00

5.00

10.00

15.00

20.00

25.00

2000 2001 2002 2003 2004 2005 2006 2007 2008

Deciviews

2nd Linear (2nd)

5.0 Source Apportionment 

5.1 Air Emission Inventory 

In accordance with 40 CFR § 51.308(d)(4)(v), a statewide inventory of emissions of pollutants 

that are reasonably anticipated to cause or contribute to visibility impairment in any Class I area 

shall be included as part of the state’s monitoring strategy. The inventory must include 

emissions for a baseline year, emissions for the most recent year for which data is available, and 

estimates of future projected emissions. 

DENR and WRAP based the emission inventory on EPA’s “Emissions Inventory Guidance for 

Implementation of Ozone and Particulate Matter National Ambient Air Quality Standards 

(NAAQS) and Regional Haze Regulations.” The guidance establishes the baseline year as 2002. 

WRAP projected an emission inventory for 2018. The most current air emission inventory for 

South Dakota is 2009; but only contains air emissions from Title V air quality permitted sources. 

The guidance specified what pollutants should be inventoried, which are reasonably anticipated 

to cause or contribute to visibility impairment in a mandatory Class I area. The air pollutants of 

concern are primary particulate matter (PM), sulfur dioxide (SO2), nitrogen oxides (NOx), 

volatile organic compounds (VOCs), and ammonia (NH3). Particulate matter will be further 

separated into primary particulate matter coarse and fine. Primary particulate matter coarse is 

particulate matter 10 microns in diameter or less (PM10) minus primary particulate matter fine, 

which is particulate matter 2.5 microns in diameter or less (PM2.5). Where available, DENR 

will include primary organic aerosol (organic carbon) and elemental carbon (EC). The definition 

of VOC is defined in the Administrative Rules of South Dakota, Section 74:36:01:01(77), which 

is derived from 40 CFR § 51.100. 

The pollutants that are reasonably anticipated to cause or contribute to visibility impairment are 

emitted by natural and anthropogenic sources. The goal of the regional haze program is to 
38 

minimize the impacts from anthropogenic sources and bring our Class I areas into their natural 

condition. Determining natural condition is difficult since anthropogenic activity has influenced 

our Class I areas for many years. This influence includes mobile sources, electric generation, 

prescribed burning, manufacturing activities, farming, preventing and fighting fires, and many 

other activities that result in the air emissions of the above pollutants. 

In support of WRAP’s regional haze air quality modeling efforts, the Regional Modeling Center 

developed annual emissions inventories for a 2002 actual emissions base case, a planning case to 

represent the 2000-04 regional haze baseline period using averages for key emissions categories, 

and a 2018 base case of projected emissions determined using factors known at the end of 2005. 

All emission inventories developed by WRAP used the Sparse Matrix Operator Kernel 

Emissions (SMOKE) modeling system. Each of these inventories has undergone a number of 

revisions throughout the development process to arrive at the final versions used in Community 

Multi-Scale Air Quality (CMAQ) and CAMx air quality modeling. The WRAP emission 

inventories developed by the Regional Modeling Center include: 

1. The 2002 base case emissions scenario, referred to as “2002 Base Case” or “Base02”. 

The purpose of the Base02 inventory is to represent the actual conditions in calendar year 

2002 with respect to ambient air quality and the associated sources of criteria and 

particulate matter air pollutants. The Base02 emissions inventories are used to validate 

the air quality model and associated databases and to demonstrate acceptable model 

performance with respect to replicating observed particulate matter air quality. 

2. The 2000-04 baseline period planning case emissions scenario is referred to as “Plan02”. 

The purpose of the Plan02 inventory is to represent baseline emission patterns based on 

average, or “typical”, conditions. This inventory provides a basis for comparison with 

the 2018 projected emissions as well as to gauge reasonable progress with respect to 

future year visibility. 

3. The 2018 base case emissions scenario is referred to as “2018 Base Case” or “Base18”. 

These emissions are used to represent conditions in 2018 with respect to sources of 

criteria and particulate matter air pollutants taking into consideration growth and controls. 

Modeling results based on this emission inventory are used to define the future year 

ambient air quality and visibility metrics. 

5.1.1 Baseline Emission Inventory 

WRAP developed a baseline emission inventory for point, all fires (anthropogenic and wild), 

biogenic sources, area, oil and gas, on-road mobile, off-road mobile, road dust, fugitive dust, and 

windblown dust sources for calendar year 2002. The emission inventories includes sulfur 

dioxide, sulfur dioxide and particulate, nitrogen oxide, nitrogen oxide and particulate, primary 

organic aerosol, elemental carbon, particulate matter 2.5 microns in diameter or less (fine), 

particulate matter 10 microns in diameter or less but greater than particulate matter 2.5 microns 

in diameter (coarse), ammonia, volatile organic compounds, and carbon monoxide. Information 

on how these inventories were developed and quality assurance measures may be reviewed at the 

following website: 

http://vista.cira.colostate.edu/tss/results/Emissions.aspx 
39 

There were two versions of the baseline emission inventory conducted by WRAP. The two 

baseline versions were identified as “base 02a and 02b”. Version “a” of the 2002 base case 

inventory was developed based on preliminary 2002 modeling (Tonnesen et al., 2005). 

Improved 2002 emissions data for the United States, Mexico, and Canada were used to create a 

final base 2002 annual emissions database for use in the CMAQ and CAMx model performance 

evaluations. Sources for emissions inventory and ancillary modeling data included WRAP 

emissions inventory contractors, other regional planning organizations, and EPA. Building from 

the WRAP preliminary 2002 modeling cases completed earlier, several updates to the inventories 

and ancillary data were incorporated to create final 2002 emissions input files for the 2002 base 

case A, or Base02a. The purpose of the “base 02” scenario is to represent the actual conditions in 

calendar year 2002 with respect to ambient air quality and the associated sources of visibilityimpairing air pollutants. The second versions, base 02b, represents updates to the first version 

and is summarized in Table 5-1 for each of the emission sources. 

The 2000 through 2004 baseline period planning case emissions scenario is referred to as “plan 

02”. As with the “base 02” inventories, “plan 02” underwent a number of revisions and 

enhancements to arrive at the final versions used in visibility and source apportionment 

modeling. The “plan 02”series of inventories was developed to represent baseline period 

emissions patterns based on average, or “typical” conditions. The “plan 02”inventory was 

developed from the “base 02”emissions modeling scenarios by incorporating: 

1. Replacement of actual 2002 fire emissions inventories with the baseline typical fire 

emissions inventories; 

2. Replacement of the temporal profiles for large stationary point sources with profiles 

developed from an average of several years surrounding 2002; and 

3. Corrections to the off-road mobile, on-road mobile, offshore Pacific shipping lane and 

WRAP oil and gas inventories. 

The “plan 02d” emission inventory was based on the minor changes to the “plan 02c”emission 

inventory. The revisions included: 

1. Updating the current status of point sources related to the BART requirements under the 

regional haze rule; and 

2. Correcting erroneous or missing Standard Industrial Classification and/or source 

classification codes (SCC). 

Table 5-2 provides a summary of the 2002 South Dakota baseline planning emission inventory 

(plan 02d) for each of the emission sources. The base 02b and the plan 02d emissions data are 

similar except for the sulfur dioxide and nitrogen oxide emissions from area sources. Based on a 

Technical Memorandum from Paula Fields and Marty Wolf with ERG to WRAP Forums and 

Workgroups dated January 10, 2008, the South Dakota area source emissions from distillate fuel 

combustions was revised using data received during the PRP18 project. The end result was a 

reduction of just over 9,000 tons of sulfur dioxide and 3,000 tons of nitrogen oxide emissions. 

The January 10, 2008, memorandum may be viewed at: 
40 

Table 5-1 – South Dakota’s 2002 Baseline Emission Inventory Summary (Base 02b) 1, 2 

Particulate Matter

Source SO2 SO2 3 NOx NOx 3 POA EC Fine Coarse Amm

Point 14,022 14,059 20,697 20,698 46 2 160 727 All Fires 278 318 1,371 1,388 3,172 409 1,338 544 Biogenic Sources 0 0 52,852 52,852 0 0 0 0 Area 10,159 10,387 5,978 5,987 1,887 317 2,129 2,177 11Oil/Gas 4 8 8 367 367 0 0 0 0 On-Road Mobile 872 922 29,224 29,224 472 632 180 169 Off-Road Mobile 5,733 6,066 39,039 39,039 942 3,234 0 0 Road Dust 0 4 0 5 255 18 4,061 38,164 Fugitive Dust 0 9 0 26 1,277 87 25,035 93,734 Wind Blown Dust 0 0 0 0 0 0 50,274 452,470 

Total 31,072 31,773 149,528 149,586 8,051 4,699 83,177 587,985 120

1 – Derived from WRAP’s website at http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx. To get to the dataclick on “Emissions and Source Apportionment”, and click on “Emission Review Tool”; 2 – “SO2” means sulfur dioxide, “NOx” means nitrogen oxide, “POA” means primary organic aerosol, “EC” means e

“VOCs” means volatile organic compounds, and “CO” means carbon monoxide; 

3 – The emission total for sulfur dioxides and nitrogen oxides includes gas and particulate; and 4 – VOC emissions from secondary oil and gas production were estimated based on an analysis of the gas and gas flow 
41 

Table 5-2 –South Dakota’s 2002 Planning Emission Inventory Summary (Plan 02d) 1, 2 

Particulate Matter 

Source SO2 SO2 3 NOx NOx 3 POA EC Fine Coarse Amm

Point 14,024 14,037 20,698 20,699 10 0 216 727 

Big Stone I 4 11,171 14,552 209 209 

All Fires 367 469 1,698 1,713 4,574 717 839 754 Biogenic Sources 0 0 52,852 52,852 0 0 0 0 Area 1,071 1,198 2,897 2,903 1,792 306 1,804 156 11Oil/Gas 5 6 6 361 361 0 0 0 0 On-Road Mobile 872 922 29,224 29,224 278 339 0 169 Off-Road Mobile 5,733 6,066 39,039 39,039 942 3,234 0 0 Road Dust 0 4 0 5 255 18 4,061 38,164 Fugitive Dust 0 24 0 27 1,317 89 25,220 122,914 Wind Blown Dust 0 0 0 0 0 0 50,274 452,470 

Total 22,073 22,726 146,769 146,823 9,168 4,703 82,414 615,354 12

1 – Derived from WRAP’s website at http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx. To get to the dataclick on “Emissions and Source Apportionment”, and click on “Emission Review Tool”; 2 – “SO2” means sulfur dioxide, “NOx” means nitrogen oxide, “POA” means primary organic aerosol, “EC” means e

“VOCs” means volatile organic compounds, and “CO” means carbon monoxide; 

3 – The emission total for sulfur dioxides and nitrogen oxides includes gas and particulate; 4 – Otter Tail Power Company’s Big Stone I emissions are included in the “Point” emissions row but separated here for 

5-4, 6-1 and 6-3; and 

5 – VOC emissions from secondary oil and gas production were estimated based on an analysis of the gas and gas flow 
42 

http://www.wrapair.org/forums/ssjf/documents/Pivot_Tables/2008‐01_Plan02d_Tech_Memo%281‐

10%29.pdf

DENR revised the data for South Dakota for both the baseline and planning emission inventories 

to include oil and gas area source emissions. Through a compliance initiative in EPA’s Region 

VIII, it was determined that secondary oil and gas production in northwestern South Dakota was 

generating volatile organic compound emissions from storage tanks that needed to be addressed. 

The oil companies quantified the volatile organic compound emissions which resulted in air 

emissions of 33,433 tons. DENR added the volatile organic compound emissions from a 

secondary oil recovery field to the 2002 baseline and planning emission inventory calculated by 

WRAP to account for the area volatile organic compound emissions from the oil and gas fields.

The 33,433 tons of volatile organic compound emissions in Table 5-1 and 5-2 were not included 

in the modeling conducted by WRAP. However, the increase in criteria air pollutants (e.g., 

particulate matter, nitrogen oxide, and carbon monoxide) from the reduction in volatile organic 

compound emissions were used in the modeling for 2018 projections and reasonable progress 

purposes. 

5.1.2 Current Emission Inventory 

A complete air emission inventory is not available for the most recent year. DENR does 

calculate an annual air emission inventory for point sources that are required to pay fees under 

the Title V air quality permit program. The most current year is 2009. The point source data for 

2009 is displayed in Table 5-3 and compared to the same data collected in WRAP’s 2002 

baseline emission inventory to compare air emission trends from point sources. 

Table 5-3 – Comparison of 2002 and 2009 South Dakota Point Source Emissions 1

Year PM10 2 SO2 NOx VOCs CO 

2002 WRAP 887 14,022 20,697 2,542 4,700 

2009 DENR 1,125 13,321 15,611 3,694 2,907 

Difference 238 -701 -5,086 1,152 -1,793 

1

 – “PM10” means particulate matter less than or equal to 10 microns in diameter or less, “SO2” 

means sulfur dioxide, “NOx” means nitrogen oxide, “VOCs” means volatile organic compounds, and 

“CO” means carbon monoxide; and 

2

 - The PM10 emissions are based on coarse and fine particulate matter. 

The comparison shows that air emissions increased from 2002 to 2009 for all pollutants except 

sulfur dioxide, nitrogen oxide and carbon monoxide. 

5.1.3 WRAP’s 2018 Projections 

WRAP projected an air emissions inventory for 2018 (PRP18a) for the same source types and 

pollutants as the base year. The projection methodology included the following steps: 

 
43 

1. Adjustments: Emission increases for new facilities that have come on-line since 2002, 

deletion of emissions for facilities that retired in 2003 or 2004 and will not return to 

operation in the future; and other adjustments (e.g., ratios to correct certain PM10 and 

PM2.5 emission factors/Standard Classification Codes for combustion of natural gas); 

2. Control Factors: Emission reductions due to known (e.g., on-the-books) controls, consent 

decrees reductions, State Implementation Plan control measures, and other relevant 

regulations that have gone into effect since 2002, or will go into effect before the end of 

2018. These controls do not include impacts from any future control scenarios that have 

yet to be determined; 

3. Growth Factors: Standard Classification Code specific growth factors developed from the 

Economic Growth and Analysis System projection factor model; special analysis of 

electric generating unit growth relative to unit capacity threshold; 

4. Retirement & Replacement Rates: Effects of retirement estimates using annual retirement 

rates based on expected equipment lifetimes. Retired equipment replaced by loweremitting new equipment. Unit lifetime examined for natural gas-fired electric generating 

units. No retirements assumed for coal-fired electric generating units; 

5. Permit Limits: Used in the cases where the projected emissions may have inadvertently 

exceeded an enforceable emission limit (e.g., emissions were adjusted downward to the 

permit limit, as applicable); and 

6. Section 309 Flags: Point sources in the Grand Canyon Visibility Transport States (e.g., 

AZ, CA, CO, ID, NV, NM, OR, UT, and WY) whose 2002 facility-level sulfur dioxide 

emissions are at least 100 tons per year.) 

Just like the baseline inventory, WRAP improved on the projections and produced a second 

version. The objective of the “PRP 18b” version was to make a second revision to the 2018 

emissions inventory projections for point and area sources in the WRAP region to provide a 

more current assessment of the reasonable progress toward visibility goals by the WRAP. The 

focus of this project was to address specific changes that have occurred since completion of the 

“PRP 18a” inventory in 2007. The resulting product is the second version of the WRAP region 

Preliminary Reasonable Progress emissions inventory for 2018, known as “PRP 18b”. 

The “PRP 18b” inventory revisions included the following elements: 

1. Included all updated BART information available such as incorporating all available 

formal BART determinations; incorporating estimates of expected BART control levels 

where BART determinations had not been finalized (BART estimates made for both 

sulfur dioxide and nitrogen oxide); and addressing all “BART-eligible” or “Subject to 

BART” sources, both for electric generating units and for the non-electric generating unit 

universe; 

2. Revised projections of “future” fossil-fuel plants needed to meet federal electrical 

generation demand forecasts in 2018 (e.g., used updated Energy Information 

Administration of the federal Department of Energy projections of 2018 energy 

requirements – for the first time incorporated Renewable Energy Portfolios where 

available – determined that existing WRAP region electric generating capacity, when 

added to existing State and Local agency electric generating unit permits, was sufficient 

to meet 2018 demand without addition of any new future electric generating units); 
44 

3. Incorporated all new rulemaking, permit limits, and consent decrees instituted since 

2007; and 

4. Corrected other outstanding issues that were identified by the federal, state, or local 

agencies within the WRAP domain as needing to be revised/updated such as modification 

of various inventory data to be consistent with the Plan 02d emissions inventory (e.g., 

name changes, updated stack parameters, new or removed sources); revision of a limited 

number of area source categories (e.g., fuel combustion emissions in South Dakota and 

California, gasoline distribution emissions in Idaho, residential wood combustion 

emissions in Washington, construction dust in Clark County, Nevada); revision of facility 

information (e.g., facility identifications, facility names, unit identifications, process 

identifications, Standard Classification Codes, Standard Industrial Classifications) based 

upon agency input; revision of stack parameters based upon agency input; and addition of 

WRAP Phase II oil and gas project emissions to “PRP 18a” area source emission 

summaries in order to provide relevant comparisons to the emission totals in “PRP 18b” 

which also contained oil and gas emission totals. 

The 2018 projected air emissions for South Dakota included three large facilities that are 

currently permitted but not constructed or have submitted an application to construct. The first 

facility is Big Stone II, which was a proposed 600 megawatt coal-fired power plant located next 

to an existing coal-fired power plant (Big Stone I) in the northeast corner of the state. A 

Prevention of Significant Deterioration air quality permit was issued to Big Stone II on 

November 20, 2008. The increase in air emissions from this facility would be limited to 

particulate matter, volatile organic compounds, and possibly ammonia. There would be no 

increase of air emissions for sulfur dioxide and nitrogen oxide because of decreases in air 

emissions from the Big Stone I facility. The air emission increases from this facility are included 

in the 2018 projections and are shown in Table 5-4. However, on December 1, 2009, Otter Tail 

Power Company submitted a letter notifying DENR the Big Stone II facility will not be built and 

it relinquished all rights and obligations granted through and by the Prevention of Significant 

Deterioration permit. Therefore, the 2018 emission inventory will need to be updated. 

The other facility that was issued a Prevention of Significant Deterioration air quality permit was 

the Hyperion Energy Center that received a permit on August 20, 2009. The Hyperion Energy 

Center will be located in Union County which is located in the southeastern corner of the state 

and is a 400,000 barrel per day oil refinery and integrated gasification combine cycle power 

plant. The air emission increases from this facility are included in the 2018 projections and are 

shown in Table 5-4. 

The third facility involves Basin Electric Power Cooperative’s NextGen application for another 

coal-fired power plant with a maximum capacity of 700 megawatts located in the north central 

area of the state. The application is currently on hold; but the air emission increases from this 

facility are included in the 2018 projections and are shown in Table 5-4. 

DENR has also received a Prevention of Significant Deterioration permit application for a 300 

megawatt natural gas fired combined cycle power generating facility in Brookings County, 

which is on eastern edge of South Dakota boarding Minnesota. The air emission increases from 

this facility will be included in the next 2018 projections and modeling analysis. 
45 

Table 5-4 displays the 2018 projected air emissions for South Dakota using the “PRP 18b” 

inventory. The specific contribution from each project are displayed in Table 5-4 and derived 

from WRAP website at the following location: 

http://www.wrapair.org/forums/ssjf/pivot.html 

To review, click on the 2018 PRP 18b zip file to review the pivot tables that when clicked on 

will display each facilities contribution. 

As discussed for the baseline, through a compliance initiative in EPA’s Region VIII, it was 

determined that secondary oil and gas production in northwestern South Dakota was generating 

volatile organic compound emissions from storage tanks that needed to be addressed. The 

installation of four thermal oxidizers in the northwestern portion of South Dakota resulted from 

the compliance initiative. Each of the thermal oxidizers are permitted under South Dakota’s 

minor air quality permit program and requires the thermal oxidizers to maintain a volatile 

organic compound destruction efficiency of 98.6% or greater. The installation of four thermal 

oxidizers did increase the emission of fine particulate matter, nitrogen oxide, and carbon 

monoxide. South Dakota’s minor air quality permit program is included in its State 

Implementation Plan. 

DENR added volatile organic compound emissions to Table 5-4 to account for the volatile 

organic compounds that are not destroyed by the thermal oxidizers. The fine particulate matter, 

nitrogen oxide and carbon monoxide emissions from the thermal oxidizers are included as area 

sources in WRAP’s projected air emissions in the “PRP 18b” inventory. 

5.1.4 Air Emission Inventories for Other States and Countries 

The visibility in the Class I areas in South Dakota is influenced not only by air emissions from 

within South Dakota but from surrounding states, Canada, and sources outside WRAP’s 

modeling domain. The six contiguous states are North Dakota, Minnesota, Iowa, Nebraska, 

Wyoming and Montana. The 2002 plan year emissions (Plan 02d) and 2018 projected emissions 

(PRP 18b) from the respective states are shown in Table 5-6 and 5-7, respectively. 

For the base year, South Dakota’s emissions when combined with the neighboring states’ 

emissions represent only three to 17 percent of the total emissions for each type of pollutant. For 

2018, South Dakota’s emissions are similar at two to 18 percent of the total emissions for each 

type of pollutant. The small percentage for each type of pollutant is a good indication that South 

Dakota’s Class I areas are being influenced by emissions from sources beyond South Dakota’s 

borders. Based on WRAP’s attribution analysis, which will be discussed further, South Dakota’s 

Class I areas are also impacted by states beyond the contiguous states and other countries such as 

Canada. Emission inventory data for the states beyond the contiguous states and other countries 

are available on WRAP’s website but were not included in this document. 
 46 

Table 5-4 –2018 South Dakota Projected Emission Inventory Summary (PRP 18b) 1, 2

Particulate Matter 

Source SO2 SO2 

3 NOx NOx 4 POA EC Fine Coarse Am

Point 11,986 11,996 30,185 30,186 8 0 205 9,847 

Big Stone I 3,425 15,323 318 

Big Stone II 3,942 2,891 6,758 

Hyperion 627 455 1,041 

NextGen 1,534 1,621 1,155 

Existing 2,458 9,895 575 

All Fires 365 465 1,679 1,694 4,531 715 821 751 Biogenic Sources 0 0 52,852 52,852 0 0 0 0 Area 1,662 1,789 3,303 3,309 1,769 314 1,920 190 1Oil/Gas 5 0 0 557 557 0 0 0 0 On-Road Mobile 108 129 8,059 8,059 270 86 0 188 Off-Road Mobile 50 199 23,785 23,785 386 1,072 0 0 Road Dust 0 5 0 6 325 23 5,190 48,773 Fugitive Dust 0 26 0 27 1,322 90 25,840 129,009 Wind Blown Dust 0 0 0 0 0 89 50,274 452,470 

Total 14,171 14,609 120,420 120,475 8,611 2,389 84,250 641,228 1

1 – Derived from WRAP’s website at http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx. To get to the dataclick on “Emissions and Source Apportionment” and click on “Emission Review Tool”; 2 – “SO2” means sulfur dioxide, “NOx” means nitrogen oxide, “POA” means primary organic aerosol, “EC” means e

“VOCs” means volatile organic compounds, and “CO” means carbon monoxide; 3 – Sulfur oxides (gas and particulate); 

4 – Nitrogen oxides (gas and particulate); and 5 – VOC emissions from secondary oil and gas production were estimated based on an analysis of the gas and gas flow 
47 

Table 5-5 provides the percent of difference between 2002 planned emission inventory (Table 5-

6) and the 2018 projected emissions (Table 5-7). From this you can see that both South Dakota 

and the contiguous states will decrease air emissions for most pollutants from 2002 to 2018. 

This decrease will represent improvements in visibility in Class I areas in South Dakota and 

neighboring Class I areas. 

Table 5-5 – Emission Changes projected for 2018 1

SD Contiguous States 

Pollutant % Difference % Difference 

SO2 36% Decrease 26% Decrease

SO2 

2

 36% Decrease 26% Decrease

NOx 18% Decrease 30% Decrease

NOx 3 18% Decrease 30% Decrease

POA 6% Decrease 6% Decrease

EC 49% Decrease 29% Decrease

PM fine 2% Increase 4% Increase

PM coarse 4% Increase 1% Increase

Ammonia No change 20% Increase

VOCs 6% Decrease 5% Increase

CO 17% Decrease 22% Decrease

1

 – “SO2” means sulfur dioxide, “NOx” means nitrogen oxide, “POA” means primary organic 

aerosol, “EC” means elemental carbon, “PM” means particulate matter, “VOCs” means volatile 

organic compounds, and “CO” means carbon monoxide; 

2

 – Sulfur oxides (gas and particulate); and 

3

 – Nitrogen oxides (gas and particulate). 

5.1.5 Future Emission Inventory by South Dakota 

DENR conducts an annual air emission inventory for stationary sources that are required to pay 

air fees under the Title V air quality permit program. The air emission inventory consists of 

criteria air pollutants. The stationary sources required to report consist of major sources (actual 

air emissions that exceed 100 tons per year) and area sources. DENR will expand the air 

emission inventory to include all air emissions that impact visibility from these stationary 

sources. 

DENR will continue to work with other organizations and states to ensure all inventory data used 

in future modeling will be accurate. The future emission inventories and the data provided by 

states in EPA’s National Emission Inventory database will be used to track the progress of South 

Dakota and neighboring states on controlling and reducing air pollution that cause or contribute 

to visibility impairment in our Class I areas and neighboring Class I areas. 
 48 

Table 5-6 –2002 Contiguous State Planning Emission Inventory Summary (Plan 02d) 1, 2

Source SD ND Minnesota Iowa Nebraska Wyoming Montana Total 

SO2 22,073 170,477 158,484 199,339 94,247 145,840 50,198 840,658 

SO2 

3 22,726 171,611 162,516 201,419 95,603 148,487 51,923 854,285 

NOx 146,769 229,460 522,727 378,150 322,915 287,974 242,978 2,130,973 

NOx 4 146,823 229,536 523,008 378,306 323,015 288,095 243,142 2,131,925 

POA 9,168 8,840 33,414 13,953 10,709 29,194 48,089 153,367 

EC 4,703 4,847 13,034 7,790 6,312 8,066 11,873 56,625 

PM fine 82,414 61,519 98,542 109,660 82,851 22,833 77,239 535,058 

PM coarse 615,354 360,936 541,408 701,377 610,843 102,660 621,276 3,553,854 

Ammonia 120,406 120,493 194,699 272,173 177,774 33,032 66,229 984,806 

VOCs 552,373 334,020 1,127,795 574,151 561,172 816,904 1,181,318 5,147,733 

CO 509,702 470,129 2,644,613 1,809,356 1,054,477 909,702 1,639,949 9,037,928 

1 – Derived from WRAP’s website at http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx. To get to the dataclick on “Emissions and Source Apportionment” and click on “Emission Review Tool”; 2 – “SO2” means sulfur dioxide, “NOx” means nitrogen oxide, “POA” means primary organic aerosol, “EC” means e

means particulate matter, “VOCs” means volatile organic compounds, and “CO” means carbon monoxide; 3 – Sulfur oxides (gas and particulate); and 

4 – Nitrogen oxides (gas and particulate). 
 49 

Table 5-7 –2018 Contiguous State Emission Inventory Summary (PRP 18b) 1, 2

Source SD ND Minnesota Iowa Nebraska Wyoming Montana Total 

SO2 14,171 66,942 111,532 198,444 60,473 122,446 44,269 618,277 

SO2 

3 14,609 67,810 115,735 200,953 61,912 125,692 45,794 632,505 

NOx 120,420 187,032 316,762 249,248 206,443 248,100 179,878 1,507,883 

NOx 4 120,475 187,103 317,037 249,422 206,545 248,234 180,043 1,508,859 

POA 8,611 7,126 31,649 12,774 9,686 28,464 46,502 144,812 

EC 2,389 2,447 9,387 4,938 3,286 6,855 9,948 39,250 

PM fine 84,250 62,731 97,229 114,324 83,456 28,055 83,047 553,092 

PM coarse 641,228 373,428 517,566 697,526 591,464 116,054 675,985 3,613,251 

Ammonia 120,758 120,120 260,671 326,247 230,762 33,974 67,030 1,159,562 

VOCs 516,567 337,735 1,160,320 580,816 566,667 1,005,916 1,174,587 5,342,608 

CO 422,983 341,118 2,094,422 1,253,075 743,082 813,609 1,378,778 7,047,067 

1 – Derived from WRAP’s website at http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx. To get to the dataclick on “Emissions and Source Apportionment” and click on “Emission Review Tool”; 2 – “SO2” means sulfur dioxide, “NOx” means nitrogen oxide, “POA” means primary organic aerosol, “EC” means e

means particulate matter, “VOCs” means volatile organic compounds, and “CO” means carbon monoxide; 3 – Sulfur oxides (gas and particulate); and 

4 – Nitrogen oxides (gas and particulate).
50 

5.2 Source Apportionment Analysis 

Visibility impairment occurs when pollutants emitted into the atmosphere scatter and absorb 

light thereby creating haze. These pollutants can remain suspended in the atmosphere for long 

periods and be transported long distances thereby contributing to regional-scale impacts on 

visibility in Class I areas. Air quality models are one of the tools that states can use to help 

understand how these impacts occur by identifying the sources contributing to haze and to select 

the most effective emissions reduction strategies to improve visibility. 

In order to determine the significant sources contributing to haze in South Dakota’s Class I areas, 

DENR relied on an apportionment analysis provided by WRAP, which can be reviewed on 

WRAP’s website at: 

http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx. 

There were two techniques used by WRAP for analyzing source apportionment of regional haze. 

One was the Particulate Matter Source Apportionment Technology (PSAT) analysis used for the 

attribution of sulfate and nitrate sources only. The second was the Weighted Emissions Potential 

(WEP) analysis used for attribution of sources of sulfate, nitrate, organic carbon, elemental 

carbon, fine particulate matter and coarse particulate matter. 

The Particulate Matter Source Apportionment Technology analysis used the CAMx air quality 

model to show nitrate-sulfate-ammonia chemistry and applies this chemistry to a system of 

tracers or “tags” to track the chemical transformations, transport and removal of nitrogen oxides 

and sulfur dioxide. These pollutants are important because they tend to originate from 

anthropogenic (human-caused) sources. Therefore, the results from this analysis can be useful in 

determining contributing sources that may be controllable, both in-state and in neighboring 

states. Emission scenarios used for the Particulate Matter Source Apportionment Technology 

analyses were the “plan02c” and “base 18b”. 

The Weighted Emissions Potential analysis is a screening tool that helps to identify sources in 

regions that have the potential to contribute to haze formation at specific Class I areas. Unlike 

the Particulate Matter Source Apportionment Technology analysis, this method does not account 

for chemistry or deposition. The Weighted Emissions Potential analysis combines emissions 

inventories, wind patterns, and residence time of air mass over each area where emissions occur 

to estimate the percent contribution of different pollutants. Like the Particulate Matter Source 

Apportionment Technology analysis, the Weighted Emissions Potential analysis compares 

baseline (2000-2004) to 2018, to show the improvement expected by the 2018 uniform rate of 

progress for sulfate, nitrate, organic carbon, elemental carbon, fine particulate matter, and coarse 

particulate matter. 

DENR believes the Particulate Matter Source Apportionment Technology analysis is a better tool 

than Weighted Emissions Potential tool for identifying the contribution of sulfates and nitrates to 

South Dakota’s Class I areas because it accounts for chemistry and deposition and is better at 

identifying regional contribution of sources from outside the WRAP region. For these reasons, 
51 

DENR relied on the Particulate Matter Source Apportionment Technology results as the primary 

source for determining apportionment for sulfates and nitrates and thus the better tool for 

identifying anthropogenic sources. The results from the Weighted Emissions Potential analysis 

were used by DENR primarily to identify the pollutants more commonly associated with natural 

sources. Even though these sources are mostly uncontrollable, it is still important to consider 

their relative contribution to haze. 

The primary tool utilized by DENR for modeling regional haze improvements by 2018 and for 

determining South Dakota’s Reasonable Progress Goals was the CMAQ model. The CMAQ 

model was used by WRAP to estimate 2018 visibility conditions in South Dakota and all 

Western Class I areas based on application of the regional haze strategies presented by states to 

WRAP, including assumed controls on BART sources. 

The modeling was conducted by the Regional Modeling Center (RMC) at the University of 

California Riverside under the oversight of WRAP’s Modeling Forum. A more in depth 

description of the CMAQ model used to project 2018 visibility conditions by WRAP and the 

results of the modeling can be found on WRAP’s website at: 

http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx. 

The CMAQ model was designed as a “one atmosphere” modeling system to encompass 

modeling of multiple pollutants and issues including ozone, particulate matter, visibility, and air 

toxics. This is in contrast to many earlier air quality models that focused on a single pollutant. 

CMAQ takes into account emissions, advection and dispersion, photochemical transformation, 

aerosol thermodynamics and phase transfer, aqueous chemistry, and wet and dry deposition of 

trace species. The model requires inputs of three-dimensional wind grids, temperature, humidity, 

cloud/precipitation, and boundary layer parameters. The current version of CMAQ can only 

utilize output fields from the MM5 meteorological model. MM5 meteorological model is a 

state-of-the-science atmosphere model that has proven useful for air quality applications and has 

been used extensively in past local, state, regional, and national modeling efforts. MM5 

meteorological model has undergone extensive peer review, with all of its components 

continually undergoing development and scrutiny by the modeling community. 

The Regional Modeling Center developed air quality modeling inputs including annual 

meteorology and emissions inventories for a 2002 actual emissions base case, a planning case to 

represent the 2000-2004 regional haze baseline period using averages for key emissions 

categories, and a 2018 base case of projected emissions determined using factors known at the 

end of 2005. All emission inventories were prepared for CMAQ using the Sparse Matrix 

Operator Kernel Emissions (SMOKE) modeling system. Each of these inventories underwent a 

number of revisions throughout the development process to arrive at the final versions used in 

CMAQ modeling. The development of each of these emission scenarios is documented under 

the emissions inventory sections on WRAP’s website at: 

http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx. 
52 

The 2018 visibility projections were made using the planning case to represent the 2000-2004 

regional haze baseline period (Plan02c) and base case projected emissions (Base18b). The 

CMAQ modeling grid design was established at 36-kilometers. Projections were made using 

relative response factors, which are defined as the ratio of the future-year modeling results to the 

current-year modeling results. The calculated relative response factors are applied to the 

baseline observed visibility conditions to project future-year observed visibility. 

Generally, emissions inputs were prepared by individual states and tribes for point, area, and 

most dust emissions categories. The following WRAP forums were relied upon to summarize 

this data and provide it to the Regional Modeling Center: 

1. Point source emissions were obtained from projects commissioned by the Stationary 

Sources Joint and Emissions forums; 

2. Area source emissions were obtained from projects commissioned by the Stationary 

Sources Joint and Emissions forums; 

3. Mobile source emissions were obtained from projects commissioned by the Emissions 

forum; 

4. Fire (natural and anthropogenic) emissions were obtained from projects commissioned by 

the Fire Emissions Joint forum; 

5. Ammonia, dust, and biogenic emissions were obtained from projects commissioned by 

the Dust Emissions Joint and Modeling forums; 

6. Emissions from Pacific offshore shipping were obtained from a project conducted by the 

Regional Modeling Center; 

7. Other emissions from North America were obtained from projects commissioned by the 

Emissions and Modeling forums. Mexico’s emissions were based on a 1999 emission 

inventory and Canada’s were based on a 2000 emission inventory. Both were held 

constant for 2018; and 

8. Boundary conditions reaching North America from the rest of the world were obtained 

from a project commissioned by the VISTAS Regional Planning Organization on behalf 

of the five regional Planning organizations working on regional haze. 

5.3 Regional Haze Contributions in South Dakota’s National Parks 

WRAP developed graphs showing the profile of the relative contribution of in-state versus outof-state sources contributing to air pollutant concentrations in South Dakota’s Class I areas for 

the 20% least and most impaired days during the 2002 baseline and 2018 projections using the 

Particulate Matter Source Apportionment Technology and Weighted Emissions Potential 

analyses.

As previously mentioned, there are several differences between the Particulate Matter Source 

Apportionment Technology analysis and Weighted Emissions Potential analysis. The Particulate 

Matter Source Apportionment Technology focuses on sulfate and nitrate contribution taking into 

account chemistry and deposition; but also estimates the contribution from all regions such as the 

WRAP states, CENRAP states, Canada, Mexico, Pacific offshore (shipping), and “outside the 

domain” (global transport). CENRAP is a regional planning organization similar to the WRAP 
53 

that is comprised of Nebraska, Kansas, Oklahoma, Texas, Minnesota, Iowa, Missouri, Arkansas, 

and Louisiana. 

The Weighted Emissions Potential analysis estimates the contribution from Canada and Pacific 

offshore regions; but does not include other regional contributions. Therefore, WRAP’s 

apportionment analysis is based on the Particulate Matter Source Apportionment Technology 

results for identifying the contribution of sulfates and nitrates (the primary anthropogenic source 

pollutants) and Weighted Emissions Potential results for identifying the contribution of organic 

carbon mass, elemental carbon, fine particulate matter, and coarse particulate matter. 

5.3.1 Sulfate Contributions 

Based on the IMPROVE data, ammonia sulfate contributes to visibility impairment in both the 

Badlands and Wind Cave National Parks. At the Badlands National Park, ammonia sulfate has 

the greatest impact and at the Wind Cave National Park it has the second greatest impact during 

the 20% most impaired days. Figure 5-1 and 5-2 illustrates the state and regional contribution of 

sulfate during the 20% most and least impaired days in South Dakota’s two Class I areas. The 

contributions are based on modeling of 2002 emission inventories of actual emissions and 

projected emissions in 2018. The pie chart in each figure displays the regional contribution to 

the total annual modeled sulfate mass at the respective sites for the 2002 base year and 2018 

projections. The bar chart identifies what state or region is contributing, the amount of 

contribution, and what type of sources are contributing to sulfate concentrations in the 2002 base 

year and 2018 projections. There are five source categories listed: 1) point; 2) area; 3) mobile; 4) 

anthropogenic fires (controlled burns); and 5) natural fires and biogenic sources (mostly wildfire 

and windblown dust). In each figure, the first bar for each state and region is not labeled but 

represents the 2002 base year. 

Based on the WRAP modeling, the sulfate concentrations for the 20% most impaired days (worst 

days) in the Badlands National Park will decrease from 1.8 micrograms per cubic meter in 2002 

to 1.6 micrograms per cubic meter in 2018 (see Figure 5-1(a)). The decrease appears to be 

attributed to decreases of sulfate emission in the CENRAP region, Eastern U.S. region, South 

Dakota and Colorado. 

The WRAP modeling indicates the greatest sulfate contribution for the 20% most impaired days 

at the Badlands National Park in 2002 is generated from the CENRAP region followed by 

Outside the Domain, Eastern U.S., Canada, and North Dakota. If you exclude Outside Domain 

because the source categories were not identified, a majority of the sulfate contribution is 

generated from point sources followed by area and mobile sources. 

In 2018, the greatest sulfate contribution for the 20% most impaired days at the Badlands 

National Park switches from the CENRAP region to Outside the Domain. This occurs because 

Outside the Domain’s sulfate contributions slightly increase while the CENRAP region’s sulfate 

contribution decreases during the same period. Even with the decreases in sulfate emissions, the 

CENRAP region is the second greatest contributor followed by Canada, North Dakota and 

Eastern U.S. Again, point sources are the major contributor followed by area sources with 

mobile source contribution minimized in 2018. 
54 

Figure 5-1 – Sulfate Contribution for 20% Most Impaired Days

a) Regional Sulfate Contributions at Badlands 

 (WRAP TSS – http://vista.cira.colostate.edu/tss/) 

South Dakota’s sulfate contribution in 2002 at the Badlands National Park is minimal at less than 

0.06 micrograms per cubic meter. The sources of sulfate emissions in South Dakota are 

generated from point, area, and mobile sources evenly in 2002. In 2018, South Dakota’s sulfate 

contribution switch mainly to point and area sources, and like other states and regions in the 

United States, mobile source contributions are minimal due to new changes in federal emission 

standards from mobile sources. 

Based on the WRAP modeling, the sulfate concentrations for the 20% most impaired days (worst 

days) in the Wind Cave National Park will decrease from 1.4 micrograms per cubic meter in 

2002 to 1.3 micrograms per cubic meter in 2018 (see Figure 5-1(b)). The decrease appears to be 
55 

attributed to decreases of sulfate emission in the CENRAP region, Eastern U.S. region, South 

Dakota and Colorado. 

The WRAP modeling indicates the greatest sulfate contribution for the 20% most impaired days 

at the Wind Cave National Park in 2002 is generated from Outside the Domain followed by the 

CENRAP region, Canada, Wyoming, and North Dakota. If you exclude Outside Domain 

because the source categories were not identified, a majority of the sulfate contribution is 

generated from point sources followed by area and mobile sources. The source category 

contribution is similar to what you see at the Badlands National Park 

In 2018, the greatest sulfate contribution for the 20% most impaired days at the Wind Cave 

National Park remains from Outside the Domain. The next four greatest contributors is Canada, 

the CENRAP region, Wyoming and North Dakota. The CENRAP region’s sulfate contribution 

decreases in 2018 which reduces its contribution lower than Canada; but continues to be greater 

than Wyoming and North Dakota. Again, point sources are the major contributor followed by 

area sources with mobile source contribution minimized in 2018. 

South Dakota’s sulfate contribution in 2002 at the Wind Cave National Park is minimal at 

approximately 0.04 micrograms per cubic meter. The sources of sulfate emissions in South 

Dakota are generated from point, area, and mobile sources evenly in 2002. In 2018, South 

Dakota’s sulfate contribution switch mainly to point and area sources, and like other states and 

regions in the United States, mobile source contributions are minimal due to new changes in 

federal emission standards from mobile sources. 

Point sources contribute a majority to the sulfate concentrations in South Dakota’s two national 

parks during the 20% most impaired days. The state or region that contributes to the sulfate 

concentrations the greatest is dependent on where the national park is located. For example, in 

the WRAP region, North Dakota contributes more to the Badlands National Park while 

Wyoming contributes more to the Wind Cave National Park. 

Based on the WRAP modeling, the sulfate concentrations for the 20% least impaired days (best 

days) in the Badlands National Park will increase from 0.6 micrograms per cubic meter in 2002 

to 0.7 micrograms per cubic meter in 2018 (see Figure 5-2(a)). Although Wyoming is not the 

greatest sulfate contributor during the 20% least impaired days, the increase appears to be 

attributed to increases of sulfate emission in the Wyoming, Idaho, and Montana. 
56 

b) Regional Sulfate Contributions at Wind Cave 

 (WRAP TSS – http://vista.cira.colostate.edu/tss/) 

The WRAP modeling indicates the greatest sulfate contribution for the 20% least impaired days 

at the Badlands National Park in 2002 is generated from Outside the Domain followed by 

Wyoming, Canada, Idaho, and Montana. If you exclude Outside Domain because the source 

categories were not identified, a majority of the sulfate contribution is generated from point 

sources. 

In 2018, the greatest sulfate contribution for the 20% least impaired days at the Badlands 

National Park does not change from 2002. The five greatest sulfate contributors are Outside the 

Domain, Wyoming, Canada, Idaho, and Montana. Again, point sources are the major contributor 

of sulfate concentrations. 
57 

Figure 5-2 – Sulfate Contribution for 20% Least Impaired Days

a) Regional Sulfate Contributions at Badlands 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

South Dakota’s sulfate contribution in 2002 at the Badlands National Park for the 20% least 

impaired days is minimal at approximately 0.01 micrograms per cubic meter. The sources of 

sulfate emissions in South Dakota are generated from point, area, and mobile sources in 2002. In 

2018, South Dakota’s sulfate contribution is less than 0.01 micrograms per cubic meter. 

Based on the WRAP modeling, the sulfate concentrations for the 20% least impaired days (best 

days) in the Wind Cave National Park will also increase from 0.6 micrograms per cubic meter in 

2002 to 0.7 micrograms per cubic meter in 2018 (see Figure 5-2(b)). Although Wyoming is not 

the greatest sulfate contributor during the 20% least impaired days, the increase appears to be 

attributed to increases of sulfate emission in the Wyoming, Idaho, and Montana, which is similar 

to what is predicted at the Badlands National Park. 

b) Regional Sulfate Contributions at Wind Cave 
58 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

The WRAP modeling indicates the greatest sulfate contribution for the 20% least impaired days 

at the Wind Cave National Park in 2002 is generated from Outside the Domain followed by 

Wyoming, Canada, Idaho, and Montana. If you exclude Outside Domain because the source 

categories were not identified, a majority of the sulfate contribution is generated from point 

sources. 

In 2018, the greatest sulfate contribution for the 20% least impaired days at the Wind Cave 

National Park does not change from 2002. The five greatest sulfate contributors are Outside the 

Domain, Wyoming, Canada, Idaho, and Montana. Again, point sources are the major contributor 

of sulfate concentrations. 

South Dakota’s sulfate contribution in 2002 at the Wind Cave National Park for the 20% least 

impaired days is minimal at approximately 0.01 micrograms per cubic meter. The sources of 
59 

sulfate emissions in South Dakota are generated from point, area, and mobile sources in 2002. In 

2018, South Dakota’s sulfate contribution stays about the same. 

Point sources contribute a majority to the sulfate concentrations in South Dakota’s two national 

parks during the 20% least impaired days. The state or region that contributes to the sulfate 

concentrations the greatest is not dependent on where the national park is located. For each 

national park, the greatest contributors are the same.

5.3.2 Organic Carbon Mass Contributions 

Based on the IMPROVE data, organic carbon mass also contributes to visibility impairment in 

both the Badlands and Wind Cave National Parks. At the Wind Cave National Park, organic 

carbon mass has the greatest impact and at the Badlands National Park it has the second greatest 

impact during the 20% most impaired days. Figure 5-3 and 5-4 illustrates the state and regional 

contribution of organic carbon mass during the 20% most and least impaired days in South 

Dakota’s two Class I areas. The contributions are based on modeling of 2002 emission 

inventories of actual emissions and projected emissions in 2018. The bar chart identifies what 

state or region is contributing, the percentage of contribution, and what type of sources are 

contributing to organic carbon mass for the 2002 base year and 2018 projections. WRAP 

identified 12 source categories: 1) windblown dust; 2) fugitive dust; 3) road dust; 4) off-road 

mobile; 5) on-road mobile; 6) off-shore; 7) WRAP area oil and gas; 8) area; 9) biogenic; 10) 

natural fires; 11) anthropogenic fire; and 12) point sources. 

The WRAP modeling indicates the greatest percentage of organic carbon mass contribution for 

the 20% most impaired days at the Badlands and Wind Cave National Park in 2002 and 2018 is 

generated from within South Dakota (see Figure 5-3). The percentage at the Badlands and Wind 

Cave National Park is approximately 30 and 41 percent, respectively. The CENRAP region 

contributes approximately 17 percent at the Badlands National Park; but only around eight 

percent at the Wind Cave National Park. Wyoming contributes approximately five percent at the 

Badlands National Park while up to eight percent at the Wind Cave National Park. 

In all but the CENRAP region, the source of organic carbon mass contributions is generated from 

natural fires. For example, approximately 23 percent of South Dakota’s 30 percent at the 

Badlands National Park is attributed to natural fires. South Dakota’s natural fire percentage at 

the Wind Cave National Park is even greater at 33 percent. In the CENRAP region, organic 

carbon mass contributions are generated from area sources such as woodstoves or other urban 

related sources. 

There appears to be slight decreases in organic carbon mass contributions from 2002 to 2018; but 

the reductions are minimal and mainly due to a decrease in off-road mobile and anthropogenic 

fires. 
60 

Figure 5-3 – Organic Carbon Mass Contribution for 20% Most Impaired Days

a) Regional Organic Carbon Mass Contributions at Badlands 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

It is interesting that the WRAP modeling indicates the greatest percentage of organic carbon 

mass contribution for the 20% least impaired days at the Badlands National Park in 2002 and 

2018 is generated from Montana (see Figure 5-4(a)) at approximately 35 percent. South Dakota, 

Oregon, and Idaho contribute approximately 20 percent, 12 percent, and seven percent, 

respectively. The source of organic carbon mass contributions is generated mainly from natural 

fires. Natural fire generated organic carbon mass from Montana contributes approximately 34 

percent of the organic carbon mass in the Badlands National Park. There appears to be slight 

decreases in organic carbon mass contributions from 2002 to 2018; but the reductions are 

minimal and mainly due to a decrease in off-road mobile and anthropogenic fire. 

For the Wind Cave National Park, the WRAP modeling for the 20% least impaired days agrees 

better with the 20% most impaired days in that the greatest percentage of organic carbon mass 

contribution in 2002 and 2018 is generated from within South Dakota (see Figure 5-4(b)) at 

approximately 42 percent. Montana, Wyoming, Idaho, and Oregon all contribute over eight 

percent. The major source of organic carbon mass contribution is generated from natural fires. 

There appears to be slight decreases in organic carbon mass contributions from 2002 to 2018; but 

the reductions are minimal and mainly due to a decrease in off-road mobile and anthropogenic 

fire. 
61 

b) Regional Organic Carbon Mass Contributions at Wind Cave 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

It appears from this information that natural fires are the greatest contributor to visibility 

impairment from organic carbon mass in the two national parks. Based on South Dakota having 

the greatest contribution percentage for both the 20% most and least impaired days at the Wind 

Cave National Park, it appears natural fires within the Black Hills area have a greater impact on 

contributing to visibility impairment at the Wind Cave National Park then at the Badlands 

National Park. DENR believes this will have to be reviewed further to determine the best 

method for minimizing the impacts natural fires and prescribed fires have on South Dakota’s two 

national parks. 
62 

Figure 5-4 – Organic Carbon Mass Contribution for 20% Least Impaired Days 

a) Regional Organic Carbon Mass Contributions at Badlands 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

b) Regional Organic Carbon Mass Contributions at Wind Cave 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 
63 

5.3.3 Nitrate Contributions 

Based on the IMPROVE data, ammonia nitrate contributes to visibility impairment in both the 

Badlands and Wind Cave National Parks. Ammonia nitrate contributions are not as great as 

ammonia sulfate or organic carbon mass but are significant enough to determine where the 

nitrates are being generated. Figure 5-5 and 5-6 illustrates the state and regional contribution of 

sulfate during the 20% most and least impaired days in South Dakota’s two Class I areas. The 

contributions are based on modeling of 2002 emission inventories of actual emissions and 

projected emissions in 2018. The pie chart in each figure displays the regional contribution to 

the total annual modeled nitrate mass at the respective sites for the 2002 base year and 2018 

projections. The bar chart identifies what state or region is contributing, the amount of 

contribution, and what type of sources are contributing to nitrate concentrations in the 2002 base 

year and 2018 projections. There are five source categories listed: 1) point; 2) area; 3) mobile; 4) 

anthropogenic fires (controlled burns); and 5) natural fires and biogenic sources (mostly wildfire 

and windblown dust). In each figure, the first bar for each state and region is not labeled but 

represents the 2002 base year. 

Based on the WRAP modeling, the nitrate concentrations for the 20% most impaired days (worst 

days) in the Badlands National Park will decrease from 1.3 micrograms per cubic meter in 2002 

to 1.2 micrograms per cubic meter in 2018 (see Figure 5-5(a)). The decrease appears to be 

attributed to decreases of nitrate emission in the CENRAP region, South Dakota, Wyoming, and 

North Dakota from mobile sources. 

The WRAP modeling indicates the greatest nitrate contribution for the 20% most impaired days 

at the Badlands National Park in 2002 is generated from Canada followed by Outside the 

Domain, the CENRAP region, South Dakota, and Wyoming. If you exclude Outside the Domain 

because the source categories were not identified, a majority of the nitrate contribution is 

generated from point, area, and mobile sources in 2002 from influences outside of South Dakota; 

and in South Dakota the nitrate contribution is from mobile, natural fires and biogenic, and point 

sources. 

In 2018, the greatest nitrate contribution for the 20% most impaired days at the Badlands 

National Park remains from Canada followed by Outside the Domain, South Dakota, Wyoming, 

and North Dakota. The CENRAP region is no longer in the top five contributors because of 

nitrate decreases mainly due from mobile sources. The sources of nitrate contribution remain the 

same from 2002 to 2018. 

South Dakota’s nitrate contribution in 2002 at the Badlands National Park is approximately 0.18 

micrograms per cubic meter. The sources of nitrates in South Dakota are generated from mobile, 

natural fires and biogenic, and point sources in 2002. In 2018, South Dakota’s nitrate 

contribution drops to 0.14 micrograms per cubic meter due mainly to reduction in mobile 

contributions. The reduction in mobile source contributions is due to new changes in federal 

emission standards from mobile sources. 
64 

Figure 5-5 – Nitrate Contribution for 20% Most Impaired Days 

a) Regional Nitrate Contributions at Badlands 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

Based on the WRAP modeling, the nitrate concentrations for the 20% most impaired days (worst 

days) in the Wind Cave National Park will decrease from 1.3 micrograms per cubic meter in 

2002 to 1.1 micrograms per cubic meter in 2018 (see Figure 5-5(b)). The decrease appears to be 

attributed to decreases of nitrate emission in Wyoming, the CENRAP region, South Dakota, 

North Dakota and Colorado from mobile sources. 
65 

b) Regional Nitrate Contributions at Wind Cave 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

The WRAP modeling indicates the greatest nitrate contribution for the 20% most impaired days 

at the Wind Cave National Park in 2002 is generated from Canada followed by Wyoming, 

Outside the Domain, the CENRAP region, and South Dakota. If you exclude Outside the 

Domain because the source categories were not identified, a majority of the nitrate contribution 

is generated from point, area, and mobile sources in 2002 from influences outside of South 

Dakota; and in South Dakota the nitrate contribution is from mobile, natural fires and biogenic, 

and point sources. 

In 2018, the greatest nitrate contribution for the 20% most impaired days at the Wind Cave 

National Park remains from Canada followed by Wyoming, Outside the Domain, South Dakota, 

and North Dakota. The CENRAP region is no longer in the top five contributors because of 

nitrate decreases mainly due from mobile sources. The sources of nitrate contribution remain the 

same from 2002 to 2018. 
66 

South Dakota’s nitrate contribution in 2002 at the Wind Cave National Park is approximately 

0.13 micrograms per cubic meter. The sources of nitrates in South Dakota are generated mainly 

from mobile sources followed by natural fires, biogenic and point sources in 2002. In 2018, 

South Dakota’s nitrate contribution drops to 0.10 micrograms per cubic meter due mainly to 

reduction in mobile contributions. The reduction in mobile source contributions is due to new 

changes in federal emission standards from mobile sources. 

Based on the WRAP modeling, the nitrate concentrations for the 20% least impaired days (best 

days) in the Badlands National Park will decrease from 1.7 micrograms per cubic meter in 2002 

to 1.5 micrograms per cubic meter in 2018 (see Figure 5-6(a)). The decrease appears to be 

attributed to decreases of nitrate emission in the states and regions is due to reductions from 

mobile sources. 

The WRAP modeling indicates the greatest nitrate contribution for the 20% least impaired days 

at the Badlands National Park in 2002 is generated from Wyoming followed by Outside the 

Domain, Canada, Montana, and South Dakota. If you exclude Outside the Domain because the 

source categories were not identified, a majority of the nitrate contribution is generated from 

point, area, and mobile sources in 2002 from influences outside of South Dakota; and in South 

Dakota the nitrate contribution is from mobile, natural fires and biogenic, and point sources. 

In 2018, the greatest nitrate contribution for the 20% most impaired days at the Badlands 

National Park remains from Wyoming followed by Outside the Domain, Canada, Montana, and 

South Dakota. The sources of nitrate contribution remain the same from 2002 to 2018. 

South Dakota’s nitrate contribution in 2002 at the Badlands National Park is approximately 0.11 

micrograms per cubic meter. The sources of nitrates in South Dakota are generated mainly from 

mobile sources followed by natural fires, biogenic and point sources in 2002. In 2018, South 

Dakota’s nitrate contribution drops to 0.10 micrograms per cubic meter due mainly to reduction 

in mobile contributions. The reduction in mobile source contributions is due to new changes in 

federal emission standards from mobile sources. 

Based on the WRAP modeling, the nitrate concentrations for the 20% least impaired days (best 

days) in the Wind Cave National Park will decrease from 1.0 micrograms per cubic meter in 

2002 to 0.9 micrograms per cubic meter in 2018 (see Figure 5-6(b)). The decrease appears to be 

attributed to decreases of nitrate emission in the states and regions is due to reductions from 

mobile sources. 
67 

Figure 5-6 – Nitrate Contribution for 20% Least Impaired Days 

a) Regional Nitrate Contributions at Badlands 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

The WRAP modeling indicates the greatest nitrate contribution for the 20% least impaired days 

at the Wind Cave National Park in 2002 is generated from Wyoming followed by Outside the 

Domain, Canada, Utah, and Montana. If you exclude Outside the Domain because the source 

categories were not identified, a majority of the nitrate contribution is generated from point, area, 

and mobile sources in 2002. 
68 

b) Regional Nitrate Contributions at Wind Cave 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

In 2018, the greatest nitrate contribution for the 20% most impaired days at the Wind Cave 

National Park remains from Wyoming followed by Outside the Domain, Canada, Montana, and 

Utah. The sources of nitrate contribution remain the same from 2002 to 2018. 

South Dakota’s nitrate contribution in 2002 at the Wind Cave National Park is approximately 

0.03 micrograms per cubic meter. The sources of nitrates in South Dakota are generated mainly 

from mobile sources in 2002. In 2018, South Dakota’s nitrate contribution drops to 0.02 

micrograms per cubic meter due mainly to reduction in mobile contributions. The reduction in 

mobile source contributions is due to new changes in federal emission standards from mobile 

sources. 

5.3.4 Coarse Particulate Matter Contribution 
69 

Based on the IMPROVE data, coarse particulate matter contributes to visibility impairment in 

both the Badlands and Wind Cave National Parks. Coarse particulate matter contributions are 

not as great as ammonia sulfate or organic carbon mass but are significant enough to determine 

where the coarse particulate matter is being generated. Coarse particulate matter has the greater 

impact at the Badlands National Park then it does at the Wind Cave National Park during the 

20% most impaired days. Figure 5-7 and 5-8 illustrates the state and regional contribution of 

coarse particulate matter during the 20% most and least impaired days in South Dakota’s two 

Class I areas. The contributions are based on modeling of 2002 emission inventories of actual 

emissions and projected emissions in 2018. The bar chart identifies what state or region is 

contributing, the percentage of contribution, and what type of sources are contributing to coarse 

particulate matter for the 2002 base year and 2018 projections. WRAP identified 12 source 

categories: 1) windblown dust; 2) fugitive dust; 3) road dust; 4) off-road mobile; 5) on-road 

mobile; 6) off-shore; 7) WRAP area oil and gas; 8) area; 9) biogenic; 10) natural fires; 11) 

anthropogenic fire; and 12) point sources. 

The WRAP modeling indicates the greatest percentage of coarse particulate matter contribution 

for the 20% most impaired days at the Badlands and Wind Cave National Park in 2002 and 2018 

is generated from within South Dakota (see Figure 5-7). The percentage at the Badlands and 

Wind Cave National Park is approximately 62 and 44 percent, respectively. The CENRAP 

region contributes approximately 21 percent at the Badlands National Park; and almost 25 

percent at the Wind Cave National Park. Montana contributes approximately four percent at the 

Badlands National Park while up to 12 percent at the Wind Cave National Park. 

In all cases, the source of coarse particulate matter contributions is generated from windblown 

dust with some contribution from fugitive and road dust. For example, approximately 53 percent 

of South Dakota’s 61 percent in 2002 at the Badlands National Park is attributed to windblown 

dust. South Dakota’s windblown dust percentage at the Wind Cave National Park is less at 32 

percent; but that is to be expected because of the dryer conditions and wide open areas in the 

Badlands National Park. 

The WRAP modeling indicates the greatest percentage of coarse particulate matter contribution 

for the 20% least impaired days at the Badlands and Wind Cave National Park in 2002 and 2018 

is also generated from within South Dakota (see Figure 5-8). The percentage at the Badlands 

and Wind Cave National Park is approximately 72 and 39 percent, respectively. The only other 

notable contributor at the Badlands National Park is Montana at approximately 12 percent. At 

the Wind Cave National Park, Montana’s influence is greater at approximately 29 percent. 

Wyoming contributes approximately 11 percent at the Wind Cave National Park. 
70 

Figure 5-7 – Coarse Particulate Matter Contribution for 20% Most Impaired Days 

a) Regional Coarse Particulate Matter Contributions at Badlands 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

b) Regional Coarse Particulate Matter Contributions at Wind Cave 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 
71 

In the Badlands National Park, the source of coarse particulate matter contributions is generated 

from windblown dust with some contribution from fugitive and road dust. For example, 

approximately 64 percent of South Dakota’s 72 percent in 2002 at the Badlands National Park is 

attributed to windblown dust. At Wind Cave National Park, windblown dust is still the major 

contributor but fugitive and road dust have a greater role in South Dakota and Montana; while in 

Wyoming point sources have a greater role. South Dakota’s windblown dust percentage at the 

Wind Cave National Park is less at 25 percent; but that is to be expected because of the dryer 

conditions and wide open areas in the Badlands National Park. 

Figure 5-8 – Coarse Particulate Matter Contribution for 20% Least Impaired Days 

a) Regional Coarse Particulate Matter Contributions at Badlands 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 
72 

b) Regional Coarse Particulate Matter Contributions at Wind Cave 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

6.0 Best Available Retrofit Technology (BART) 

6.1 Bart-Eligible Sources 

In accordance with 40 CFR § 51.308(e), South Dakota’s State Implementation Plan is required to 

contain emission limitations representing BART and schedules for compliance with BART for 

each BART-eligible source that may reasonably be anticipated to cause or contribute to any 

impairment of visibility in any mandatory Class I area. A BART-eligible source is an existing 

stationary facility that is any of the following stationary sources of air pollutant that was not in 

operation prior to August 7, 1962, was in existence on August 7, 1977, and has the potential to 

emit 250 tons per year or more of any air pollutant. Fugitive emissions must be included in the 

potential to emit, to the extent quantifiable. 

1. Fossil-fuel fired steam electric plants of more than 250 million British thermal units per 

hour heat input, 

2. Coal cleaning plants (thermal dryers), 

3. Kraft pulp mills, 

4. Portland cement plants, 

5. Primary zinc smelters, 

6. Iron and steel mill plants, 

7. Primary aluminum ore reduction plants, 

8. Primary copper smelters, 

9. Municipal incinerators capable of charging more than 250 tons of refuse per day, 
73 

10. Hydrofluoric, sulfuric, and nitric acid plants, 

11. Petroleum refineries, 

12. Lime plants, 

13. Phosphate rock processing plants, 

14. Coke oven batteries, 

15. Sulfur recovery plants, 

16. Carbon black plants (furnace process), 

17. Primary lead smelters, 

18. Fuel conversion plants, 

19. Sintering plants, 

20. Secondary metal production facilities, 

21. Chemical process plants, 

22. Fossil-fuel boilers of more than 250 million British thermal units per hour heat input, 

23. Petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels, 

24. Taconite ore processing facilities, 

25. Glass fiber processing plants, and 

26. Charcoal production facilities. 

In February 2004, DENR followed the procedures in 40 CFR Part 51, Appendix Y in identifying 

emission units at stationary facilities in South Dakota meeting the above categories, identifying 

the startup date of the emission units, comparing the potential emissions to the 250 tons per year 

cutoff, and identifying the emissions units and pollutants that constitute the BART-eligible 

sources. The following terms are defined below: 

1. “In Operation” means engaged in activity related to the primary design function of the 

source. The date the unit is permitted is not important to meet this test because the focus 

is on actual operation of the unit; 

2. “In Existence” means that the owner or operator has obtained all necessary 

preconstruction approvals or permits required by federal, state, or local air pollution 

emissions and air quality laws or regulations and either has (1) begun, or caused to begin, 

a continuous program of physical on-site construction of the facility or (2) entered into 

binding agreements or contractual obligations, which cannot be canceled or modified 

without substantial loss to the owner or operator, to undertake a program of construction 

of the facility to be completed in a reasonable time; 

3. “Date of Reconstruction” must occur during the August 7, 1962 to August 7, 1977 time 

period; and 

4. “Potential to Emit” means the maximum capacity of a stationary source to emit a 

pollutant under its physical and operational design. Any physical or operational limitation 

on the capacity of the source to emit a pollutant including air pollution control equipment 

and restrictions on hours of operation or on the type or amount of material combusted, 

stored, or processed, shall be treated as part of its design if the limitation or the effect it 

would have on emissions is federally enforceable. Secondary emissions do not count in 

determining the potential to emit of a stationary source. However, fugitive emissions, to 

the extent quantifiable, must be counted for the 26 categories. 
74 

In accordance with 40 CFR § 51.308(e)(1)(i), Table 6-1 provides a list of existing stationary 

facilities from the February 2004 analysis that may be considered a BART-eligible source and 

need further investigation to determine if they are subject to BART. 

Table 6-1– List of BART-Eligible Sources 1

Maximum Potential to Emit BART 

Unit Date Capacity TSP SO2 NOx VOC Eligible 

Northern States Power Company – Sioux Falls 

#1 – Babcock boiler 1969 330 MMBtus/hr 7 1 795 2 Yes 

#2 – Babcock boiler 1969 330 MMBtus/hr 7 1 795 2 Yes 

#3 – Babcock boiler 1969 330 MMBtus/hr 7 1 795 2 Yes 

Total = 990 MMBtus/hr 21 3 2,385 6 Yes 

Pete Lien and Sons, Inc. – Rapid City 

#6 – Vertical kiln 1966 - 561 0 13 1 Yes 

#7 – Pebble lime crusher 1970 - 1 0 0 0 Yes 

#8 – Large hydrator 1965 - 97 0 0 0 Yes 

#12 – Lime bagging 1963 - 48 0 0 0 Yes 

Total = 707 0 13 1 Yes 

Otter Tail Power Company – Big Stone I Power Plant 

#1 – Babcock boiler 1975 5,609 MMBtus/hr 300 19,863 17,179 125 Yes 

1

 – “TSP” means total suspended particulate, “SO2” means sulfur dioxide, “NOx” means nitrogen 

oxide, and “VOCs” means volatile organic compounds. 

In accordance with 40 CFR Part 51, Appendix Y, the next step is to identify those BART-eligible 

sources that may “emit any pollutant which may reasonably be anticipated to cause or contribute 

to any impairment of visibility.” For each source subject to BART, DENR is required to identify 

the best system of continuous emission control technology for each source after considering the 

following as specified in section 169A(g)(2) of the federal CAA: 

1. Cost of compliance; 

2. The energy and non-air quality environmental impacts of compliance; 

3. Any existing pollution control technology in use at the source; 

4. The remaining useful life of the source; and 

5. The degree of visibility improvement which may reasonably be anticipated from the use 

of BART. 

The results of the BART review are required to be submitted in the Regional Haze State 

Implementation Plan identifying the BART emission limitations and timeline for demonstrating 

compliance. The timeline for demonstrating compliance shall not exceed five years after EPA 

approves the Regional Haze State Implementation Plan. DENR may establish design, 

equipment, work practice or other operational standards when limitations on measurement 

technologies make emission standards infeasible. 

6.1.1 Northern States Power Company – Sioux Falls 
75 

The three units at Northern States Power Company in Sioux Falls, South Dakota is considered 

fossil-fuel fired steam electric plant. The units were built in 1969 and have a maximum capacity 

greater than 250 million Btus per hour per unit. However, Northern States Power Company 

decommissioned these three units and they are no longer permitted to operate in Northern States 

Power Company’s Title V air quality permit. Therefore, these three units at Northern States 

Power Company’s Sioux Falls site are not subject to BART. 

6.1.2 Pete Lien and Sons, Inc. – Rapid City 

Pete Lien and Sons operates a limestone quarry operation and lime plant in northwest Rapid 

City. There are four operations that were identified in the February 2004 analysis, not in 

operation prior to August 7, 1962, and in existence on August 7, 1977. The four operations are a 

1966 vertical kiln, 1970 pebble lime crusher, 1965 large hydrator, and 1963 lime bagging 

operation. Only the 1966 vertical kiln has the potential to emit over the 250 tons per year 

threshold. 

As identified in Pete Lien and Sons’ existing Title V air quality permit issued November 12, 

2008, the 1970 pebble lime crusher was replaced with a 1982 pebble lime crusher and the 1963 

bagging operation was replaced with a 2004 lime bagging operation. Therefore, these two units 

will not be evaluated further. 

Pete Lien and Sons falls under the “lime plant” category listed above. DENR researched the 

definition of “lime plant” to determine if the large hydrator is included in the definition of a lime 

plant. DENR determined that typically the definition for the 26 categories coincides with the 

definitions under the New Source Performance Standards. Under 40 CFR Part 60, Subpart HH, a 

lime manufacturing plant means, “...any plant which used a rotary lime kiln to produce lime 

product from limestone by calcinations.” Based on this definition of a lime plant, Pete Lien and 

Sons would not be considered a lime plant because the kiln in question is a vertical kiln and not a 

rotary kiln. In addition, only the kiln would be considered a “lime plant”. 

DENR assumed the vertical kiln was considered a lime plant and on April 21, 2006, DENR 

requested that WRAP model Pete Lien and Sons emissions to determine if they would cause or 

contribute to any impairment of visibility in a Class I area. WRAP initiated this process by 

running CALMET/CALPUFF modeling using WRAP’s “CALMET/CALPUFF Protocol for 

BART Exemption Screening Analysis for Class I Areas in the Western United States,” August 15, 

2006. The basic assumptions in the protocol are: 

1. Use of three years of modeling consisting of calendar year 2001, 2002 and 2003; 

2. Visibility impacts due to emissions of sulfur dioxide, nitrogen oxide and primary 

particulate matter emissions were calculated. Unless a state provided speciated 

particulate matter emissions, all PM emissions were modeled as PM2.5. In this case all 

PM emissions were modeled as PM2.5; 

3. Visibility was calculated using the original IMPROVE equation and annual average 

natural conditions; and 

4. CALPUFF version 6.112 was used in the analysis. 
76 

The CALPUFF modeling procedures are outlined in WRAP’s BART Modeling Protocol, which 

can be reviewed at the following website: 

http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf. 

Table 6-2 provides a summary of the modeling outputs based on annual sulfur dioxide and 

nitrogen oxide emissions of 0.4 and 277 tons per year, respectively. 

Table 6-2– WRAP’s Modeling Results for Pete Lien and Sons 1

Minimum

Max 

Delta 99th Days Annual 98th percentile 

Class I Area State Distance (dv) (dv) >0.5 2001 2002 2003 

Badlands SD 73 km 0.267 0.140 0 0.120 0.160 0.105 

Boundary Waters MN 946 km 0.014 0.007 0 0.005 0.003 0.003 

Bridger WY 489 km 0.021 0.003 0 0.001 0.002 0.001 

Fitzpatrick WY 501 km 0.018 0.002 0 0.001 0.001 0.001 

Grand Teton WY 570 km 0.005 0.001 0 0.000 0.000 0.000 

Lostwood ND 509 km 0.040 0.009 0 0.006 0.005 0.007 

Medicine Lake MT 488 km 0.030 0.011 0 0.006 0.005 0.010 

North Absaroka WY 487 km 0.008 0.002 0 0.001 0.001 0.001 

Teton WY 513 km 0.009 0.001 0 0.001 0.001 0.000 

Theodore Roosevelt ND 311 km 0.049 0.023 0 0.014 0.016 0.015 

Ul Bend MT 516 km 0.024 0.006 0 0.005 0.003 0.005 

Voyageurs MN 921 km 0.012 0.006 0 0.004 0.002 0.003 

Washakie WY 461 km 0.019 0.003 0 0.001 0.002 0.001 

Wind Cave SD 52 km 0.366 0.203 0 0.128 0.137 0.139 

Yellowstone WY 524 km 0.008 0.002 0 0.001 0.001 0.001 

1

 - “dv” means deciview and “km” means kilometers. 

The modeling conducted by WRAP demonstrated that Pete Lien and Sons did not cause or 

contribute to visibility impairment at a Class I area. After reviewing the modeling inputs, DENR 

determined the vertical kiln should be modeled again because of errors in the UTM coordinates 

and emission rates. However, before the modeling could be re-run, the vertical kiln was 

shutdown and dismantled in 2009. 

Although Pete Lien and Sons’ existing Title V air quality permit still identifies the vertical kiln 

as a unit, permit condition 1.1 specifies in the footnote of Table 1-1 that Pete Lien and Sons is 

required to shutdown and dismantle the vertical kiln before the initial startup of Unit #45. Pete 

Lien and Sons fulfilled this commitment by notifying DENR on March 13, 2009, that the vertical 

kiln was shutdown and dismantled. Therefore, Pete Lien and Sons’ shutdown and dismantled the 

unit subject to BART and DENR did not re-model the vertical kiln. 

6.1.3 Otter Tail Power Company – Big Stone I 
77 

Unit #1 at the Big Stone I Power Plant was built in 1975, has a maximum capacity greater than 

250 million Btus per hour, and has the potential to emit greater than 250 tons per year of any air 

pollutant. The next step in this analysis is to determine if Unit #1’s emissions may reasonably be 

anticipated to cause or contribute to any impairment of visibility in a Class I area. On April 21, 

2006, DENR requested that WRAP model Unit #1’s emissions from Otter Tail Power 

Company’s Big Stone I Power Plant. 

WRAP initiated this process by running CALMET/CALPUFF modeling using WRAP’s 

“CALMET/CALPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in 

the Western United States,” August 15, 2006. The basic assumptions in the protocol are: 

1. Use of three years of modeling of 2001, 2002 and 2003; 

2. The sulfur dioxide, nitrogen oxide and particulate emission rates represent the 24-hour 

average actual emission rate from the highest emitting day of the meteorological period 

modeled, not including periods of startup, shutdown, or malfunctions; 

3. Visibility impacts due to emissions of sulfur dioxide, nitrogen oxide and primary 

particulate matter emissions were calculated. Unless a state provided speciated 

particulate matter emissions, all PM emissions were modeled as PM2.5; 

4. Visibility was calculated using the original IMPROVE equation and annual average 

natural conditions; and 

5. CALPUFF version 6.112 was used in the analysis. 

The CALPUFF modeling procedures are outlined in WRAP’s BART Modeling Protocol and can 

be reviewed at the following website: 

http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf. 

Table 6-3 provides a summary of the modeling outputs based on annual sulfur dioxide and 

nitrogen oxide emissions of 12,409 and 15,580 tons per year, respectively. The annual sulfur 

dioxide and nitrogen oxide emissions were derived from WRAP’s BART protocol identified 

above. 

Table 6-3– WRAP’s Modeling Results for Otter Tail Power Company Big Stone I 1

Min 

Max 

Delta 99th Days Annual 98th percentile 

Class I Area State Distance (dv) (dv) >0.5 2001 2002 2003 

Badlands SD 470 km 3.047 1.076 21 0.364 0.417 0.683 

Boundary Waters MN 431 km 1.653 1.133 63 0.951 0.659 1.034 

Bridger WY 1,041 km 0.147 0.003 0 0.001 0.001 0.000 

Fitzpatrick WY 1,050 km 0.079 0.005 0 0.001 0.001 0.000 

Grand Teton WY 1,112 km 0.029 0.003 0 0.001 0.001 0.000 

Lostwood ND 585 km 0.779 0.370 7 0.263 0.175 0.204 

Medicine Lake MT 690 km 0.678 0.345 7 0.256 0.211 0.218 

North Absaroka WY 1,013 km 0.121 0.026 0 0.011 0.008 0.001 

Teton WY 1,052 km 0.049 0.008 0 0.004 0.002 0.001 

Theodore Roosevelt ND 555 km 2.061 0.840 27 0.581 0.443 0.687 
78 

Min 

Max 

Delta 99th Days Annual 98th percentile 

Class I Area State Distance (dv) (dv) >0.5 2001 2002 2003 

Ul Bend MT 902 km 0.840 0.196 3 0.089 0.065 0.043 

Voyageurs MN 438 km 1.658 0.915 52 0.666 0.703 0.729 

Washakie WY 1,006 km 0.090 0.018 0 0.007 0.005 0.001 

Wind Cave SD 572 km 1.545 0.631 13 0.224 0.263 0.261 

Yellowstone WY 1,049 km 0.068 0.018 0 0.009 0.004 0.001 

1

 - “dv” means deciview and “km” means kilometers. 

WRAP had determined that Big Stone I would be reasonably anticipated to contribute to an 

impairment of visibility at the Badlands National Park in South Dakota, Theodore Roosevelt 

National Park in North Dakota, and Boundary Waters Wilderness and Voyageurs National Park 

in Minnesota. 

6.2 Otter Tail Power Company’s Modeling Results 

Otter Tail Power Company was notified of the results and requested an opportunity to verify the 

results after identifying several errors in actual emission rates and stack parameters. The 

department allowed Otter Tail Power Company to re-run the models using the correct emission 

rates and stack parameters. On March 19, 2008, Otter Tail Power Company submitted an 

individual source analysis using CALMET/CALPUFF; but after review by the state, EPA, and 

federal land managers (U.S. Fish and Wildlife Service, U.S. Forest Service and National Park 

Service) it was determined that a BART modeling protocol should be submitted and approved by 

all parties, Otter Tail Power Company would run the model using the approved protocol, and 

submit before Otter Tail Power Company’s results could be approved. 

Otter Tail Power Company submitted the BART modeling protocol on January 16, 2009. After 

several conference calls and discussions, a revised protocol identified as June 2009, was 

submitted July 1, 2009. After several submittals and conference calls, Otter Tail Power 

Company committed to make the following changes to the protocol in an email dated August 31, 

2009: 

1. Although Otter Tail Power Company attached the CALMET switches it would use, it 

committed to using the CALMET switches recommended and approved by EPA and 

Federal Land Managers (FLMs) dated August 20, 2009. However, to ensure the most upto-date CALMET switches are used, DENR is requiring Otter Tail Power Company to 

use the CALMET switches identified in EPA’s memorandum dated August 31, 2009, 

from Tyler J Fox, Group Leader, Air Quality Modeling Group, to EPA Regional 

Modeling Contacts. The date on the listing of CALMET switches is August 28, 2009. 

The memorandum may be viewed in Attachment C. 

2. Otter Tail Power Company committed to use the CALPUFF switches that Penny 

Shamblin, with Hunton and Williams, submitted to DENR by email on August 19, 2009. 

Although the document contains CALMET switches, only the CALPUFF switches (see 

Attachment D) in this email will be used by Otter Tail Power Company in the BART 

analysis. The CALMET switches mentioned above will be the ones used in the analysis. 
79 

3. Otter Tail Power Company proposes to revise the June 2009 modeling protocol by using 

a 12 kilometer MM5 grid and a 4 kilometer CALMET grid rather than the 4 kilometer 

MM5 grid and 4 kilometer CALMET grid identified in the June 2009 modeling protocol. 

DENR reviewed other acceptable modeling protocols and is acceptable to this change. 

4. Although Otter Tail Power Company may run POSTUTIL option MNITRATE=2 for its 

own purposes, the modeling results DENR will accept for the BART analysis will be 

MNITRATE=1. 

The CALPUFF switches Otter Tail Power Company is recommending contains five switches that 

are different than those recommended by EPA as defaults. The following identifies the variable, 

EPA’s default, recommended default by Otter Tail Power Company, and DENR’s response: 

1. “NSPEC” – Identifies the number of species modeled. The EPA default is 5 and Otter 

Tail Power Company is proposing 11, which follows the FLM guidance on particle 

speciation and size. DENR is agreeable to this change. 

2. “NSE” – Number of species emitted. The EPA default is 3 and Otter Tail Power 

Company is proposing 9. 

3. “MSPLIT” – Allows puffing. The EPA default is 0 (No) and Otter Tail Power 

Company is proposing 1 (Yes). Puff splitting in necessary due to the distance from Big 

Stone I to a federal Class I area. DENR is agreeable to this change. 

4. “MESHDN” – Grid receptor spacing. The EPA default is 1; however, Otter Tail Power 

Company is stating this is “Not Applicable”. DENR is agreeable to this change. 

5. “BCKNH3” – Ammonia background. The EPA default is 10 parts per billion and Otter 

Tail Power Company is recommending 1 part per billion. During the June 3, 2009, 

conference call, EPA stated it was okay with this change. DENR is agreeable to this 

change. 

On September 18, 2009, the department determined that Otter Tail Power Company’s BART 

modeling protocol as identified above. See Appendix A for the approval letter and the BART 

modeling protocol dated June 2009. 

The modeling results identified that Otter Tail Power Company’s Big Stone I Power Plant would 

be reasonably anticipated to contribute to an impairment of visibility at the Boundary Waters and 

Voyageurs federal Class I areas in northern Minnesota and the Isle Royale federal Class I area in 

Michigan. The reasonably anticipated to contribute to an impairment is based on visibility 

impacts greater than 0.5 deciview based on the 98th percentile at the three federal Class I areas. 

See Appendix B for the modeling report dated October 2009, and Table 6-4 for a summary of the 

modeling results. 

 
80 

Table 6-4– Otter Tail Power Company’s Modeling Results for Big Stone I 1

Min Max Delta 99th 98th

Class I Area State Distance (dv) (dv) (dv) 

Badlands SD 470 km 2.202 0.698 0.481 (0.5) 

Boundary Waters MN 431 km 3.574 1.351 1.079 (1.1) 

Lostwood ND 585 km 1.110 0.722 0.409 (0.4) 

Theodore Roosevelt ND 555 km 2.232 0.772 0.459 (0.5) 

Voyageurs MN 438 km 2.162 1.376 0.724 (0.7) 

Wind Cave SD 572 km 1.671 0.591 0.325 (0.3) 

Isle Royale MI 1,049 km 1.806 0.789 0.665 (0.7) 

1

 - “dv” means deciview and “km” means kilometers. 

Otter Tail Power Company results did not match up entirely with the modeling conducted by 

WRAP. In particular, Otter Tail Power Company’s modeling also showed that Big Stone I 

would reasonably contribute to impairment at the Isle Royale National Park in Michigan. DENR 

believes Otter Tail Power Company’s modeling best represent the visibility impacts from Big 

Stone I since the original modeling did not have the correct emission rates and stack parameters 

and the CALPUFF modeling conducted by Otter Tail Power Company included puff splitting, 

which helps improve the accuracy of the model when used for great distances. 

In accordance with the 40 CFR Part 51, Appendix Y, DENR used a contribution threshold of 0.5 

deciviews for determining if Otter Tail Power Company’s Big Stone I facility is subject to 

BART. The guideline provides the state the discretion to set a threshold below 0.5 deciviews if 

“the location of a large number of BART-eligible sources within the state and proximately to a 

Class I area justifies this approach. The discretion was based on the following factors: 

1. It equates to the 5 percent extinction threshold for new sources under the PSD New 

Source Review rules; 

2. It is consistent with the threshold selected by other states in the west, which all selected 

0.5 deciviews; and 

3. It represents the limit of perceptible change. 

DENR chose the 0.5 deciview threshold because there is only one source that is BART-eligible 

and it is greater than 300 kilometers from any Class I area. Therefore, DENR will establish this 

threshold in its proposed ARSD Chapter 74:36:21 – Regional Haze Program. Otter Tail Power 

Company’s Big Stone I power plant exceeded this threshold and is subject to BART. In 

accordance with 40 CFR § 51.308(e)(1)(i), the only source subject to BART in South Dakota is 

Otter Tail Power Company’s Big Stone I facility. 

In accordance with 40 CFR § 51.308(e)(1)(ii), DENR requested that Otter Tail Power Company 

complete a Case-by-Case BART analysis, which includes determining the visibility 

improvements expected at each of these Class I areas (see Appendix C). 
81 

6.3 Otter Tail Power Company’s Case-by-Case BART Analysis 

In accordance with 40 CFR 51.301, Best Available Retrofit Technology (BART) is defined as

“an emission limitation based on the degree of reduction achievable through the application of 

the best system of continuous emission reduction for each pollutant which is emitted by an 

existing stationary facility. The emission limitation must be established, on a case-by-case basis, 

taking into consideration the technology available, the costs of compliance, the energy and 

nonair quality environmental impacts of compliance, any pollution control equipment in use or 

in existence at the source, the remaining useful life of the source, and the degree of improvement 

in visibility which may reasonably be anticipated to result from the use of such technology.”

In accordance with 40 CFR § 51.308(e)(1)(ii)(B), the determination of BART for fossil fuel fired 

power plants having a total generating capacity greater than 750 megawatts must be made 

pursuant to the guidelines in Appendix Y of this part (Guidelines for BART Determinations 

under the Regional Haze Rule). Appendix Y identifies a five step process in determining BART. 

The five steps are as follows: 

1. STEP 1—Identify All Available Retrofit Control Technologies: In identifying ‘‘all’’ 

options, one should identify the most stringent option and a reasonable set of options for 

analysis that reflects a comprehensive list of available technologies. It is not necessary to 

list all permutations of available control levels that exist for a given technology. The list 

is complete if it includes the maximum level of control each technology is capable of 

achieving. Where a New Source Performance Standard (NSPS), under 40 CFR Part 60, 

exists for a source category, one should include a level of control equivalent to the NSPS 

as one of the control options; 

2. STEP 2—Eliminate Technically Infeasible Options: One evaluates the technical 

feasibility of the control options identified in Step 1. One should document a 

demonstration of technical infeasibility and should explain, based on physical, chemical, 

or engineering principles, why technical difficulties would preclude the successful use of 

the control option on the emissions unit under review. One may then eliminate such 

technically infeasible control options from further consideration in the BART analysis; 

3. STEP 3—Evaluate Control Effectiveness of Remaining Control Technologies: One 

evaluates the control effectiveness of all the technically feasible control alternatives 

identified in Step 2 for the pollutant and emissions unit under review. Two key issues in 

this process include: (1) Make sure that you express the degree of control using a metric 

that ensures an ‘‘apples to apples’’ comparison of emissions performance levels among 

options; and (2) Give appropriate treatment and consideration of control techniques that 

can operate over a wide range of emission performance levels; 

4. STEP 4—Evaluate Impacts and Document the Results: Once the available and 

technically feasible control technology options are identified, one should conduct the 

following analyses when you make a BART determination: (1) Impact analysis part 1 – 

costs of compliance; (2) Impact analysis part 2 – energy impacts, (3) Impact analysis part 

3 – non-air quality environmental impacts; and (4) Impact analysis part 4 – remaining 

useful life; and 

5. STEP 5—Evaluate Visibility Impacts: One should evaluate the net visibility 

improvement form the available and technically feasible control technology options. 
82 

This is accomplished by modeling the pre-control and post-control emission rates 

according to an accepted methodology. 

In determining what is considered BART, Appendix Y identifies that the state should develop a 

chart (or charts) displaying each of the alternatives and include: (1) Expected emission rate (e.g., 

tons per year, pounds per hour); (2) Emissions performance level (e.g., percent pollutant 

removed, emissions per unit product, pounds per million Btus, parts per million); (3) Expected 

emissions reductions (e.g., tons per year); (4) Costs of compliance (e.g., total annualized costs in 

dollars, cost effectiveness (dollar per ton), incremental cost effectiveness (dollar per ton), any 

other cost-effectiveness measures (dollar per deciview)); (5) Energy impacts; (6) Non-air quality 

environmental impacts; and (7) Modeled visibility impacts. 

Otter Tail Power Company’s Big Stone I facility does not have a total generating capacity 

greater than 750 megawatts. Therefore, DENR is not required to follow these guidelines. As 

such, DENR will follow the steps identified in Appendix Y with some slight differences. For 

example, in identifying the available control technologies, DENR is not listing any of the 

permutations of the control levels for each identified control technology as suggested by EPA’s 

guidance. DENR will use the initial step to identify control technologies without including the 

control levels. Step 3 is used to evaluate the control effectiveness or permutations of the control 

levels for those control technologies that are considered feasible to install or maintain as 

identified in Step 2. 

6.3.1 Particulate BART Review 

6.3.1.1 Particulate Control Technologies 

Step 1 requires the identification of all available retrofit control technologies. The particulate 

matter emissions from fossil-fuel fired units can be categorized as either filterable or 

condensable particulate. The filterable particulate matter exists as a solid or liquid particle in the 

exhaust of a boiler as it leaves the stack. As such, the filterable particulate may be collected by 

placing a control device in the flue gas stream prior to the stack. Condensable particulates are 

emitted out the stack in a gaseous state but rapidly condense into particles when released into the 

atmosphere and cooled. Therefore, condensable particulates may not be readily collected by 

placing a control device in the stack. 

Those control technologies being reviewed under Step 1 are those that would control the 

filterable particulate matter. Otter Tail Power Company identified the following control options 

for particulate matter. 

1. Existing fabric filter (baghouse); 

2. New fabric filter (baghouse); 

3. Compact hybrid particulate collector; and 

4. Electrostatic precipitator. 

DENR also identified two more control technologies that may be used to control particulate 

emissions and are listed below: 
83 

1. Wet scrubber; and 

2. Cyclone(s)/Multicyclone(s). 

6.3.1.2 Technically Feasible Particulate Control Technologies 

Step 2 requires the elimination of any control technologies identified in Step 1 that are 

technically infeasible. A compact hybrid particulate collector is a combination of an electrostatic 

precipitator and a baghouse in series. The compact hybrid particulate collector is generally 

operated with a higher air-to-cloth ratio than a typical baghouse. Since Otter Tail Power 

Company already has a baghouse installed at Big Stone I, Otter Tail did not further consider the 

compact hybrid particulate collector. 

Even though Otter Tail Power Company identified a reason for not selecting the compact hybrid 

particulate collector, the reasoning does not identify that the technology is infeasible to install. 

Since both an electrostatic precipitator and a baghouse are both technically feasible options and 

without further evidence, DENR considers the compact hybrid particulate collector as a feasible 

control technology. 

DENR determined that the following particulate control technologies were feasible for Otter Tail 

Power Company: 

1. Existing fabric filter (baghouse); 

2. New fabric filter (baghouse); 

3. Compact hybrid particulate collector; 

4. Electrostatic precipitator; 

5. Wet scrubber; and 

6. Cyclone(s)/Multicyclone(s). 

6.3.1.3 Particulate 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 6.5. 

Table 6-5 – Comparison of Control Effectiveness for Particulate Controls 

Emission Rate Control Efficiency 

Otter Tail 1 RBLC 3 PFDR 4 IEA 5

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

#1 Baghouse 0.015 0.010 to 0.03 95 to 99.9 >99 to >99.9999 

#2 Electrostatic 

Precipitator 

0.015 0.015 to 0.03 80 to 99.5 >99 to >99.99 

#3 COHPAC 6 Not Provided 0.015 Not Identified Not Identified 

#4 Wet 

Scrubber(s) 

Not Provided Not Identified 75 to 99 90 to 99.9 

#5 Cyclone(s)/ 

Multicyclone(s) 

Not Provided Not Identified 50 to 95 75 – 99 
84 

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 control efficiencies, in percent removal, are derived from page 473 of “Particulates and Fine 

Dust Removal Process and Equipment by Marshal Sittig”; 

5

 – The control efficiencies, in percent removal, are derived from the IEA Clean Coal Centre’s 

Webpage at http://www.iea-coal.org.uk/site/ieacoal/home; and 

6 – “COHPAC” means Compact Hybrid Particulate Collector. 

6.3.1.4 Particulate Control Technology Impacts 

In Step 4, DENR looked 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. Otter Tail Power 

Company already has installed and is operating a baghouse, which is the top particulate control 

technology. Therefore, there is no additional compliance cost, energy impacts, etc. that Otter 

Tail Power Company would have to endure. As such, no additional impacts analysis will be 

conducted to determine the appropriate controls for particulate matter. 

6.3.2 Sulfur Dioxide BART Review 

6.3.2.1 Sulfur Dioxide Control Technologies 

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

Company identified the following control options for sulfur dioxide: 

1. Fuel switching; 

2. Semi-dry flue gas desulfurization; and 

3. Wet flue gas desulfurization. 

DENR also identified the following control technologies that may be used to control sulfur 

dioxide emissions: 

1. Coal cleaning; 

2. Coal upgrading; 

3. Hydrated lime injection; and 

4. Emerging control technologies such as Enviroscrub, Electro catalytic oxidation, and 

Airborne process. 

6.3.2.2 Technically Feasible Sulfur Dioxide Control Technologies 

Fuel switching is a viable method to reduce sulfur dioxide emissions by switching to a fuel with 

lower sulfur content. Otter Tail Power Company’s Big Stone facility’s primary fuel source is 

subbituminous coal obtained from the Powder River Basin in Wyoming. Powder River Basin 
85 

subbituminous coal has one of the lowest sulfur contents available in the United States. As such, 

Otter Tail Power Company has already implemented fuel switching. 

Coal cleaning is typically performed by physical gravimetric separation which is capable of 

reducing sulfur, ash and impurities from the coal. The effectiveness of gravimetric separation is 

dependent on the ash content and the distribution of fuel bound sulfur between organic and 

inorganic. If the sulfur compounds are predominantly inorganic materials, then coal cleaning is 

fairly effective, but if the sulfur compounds are predominantly organic materials, then coal 

cleaning is not effective. Physical cleaning or gravimetric separation may be effective with 

bituminous coals that contain high levels of inorganic sulfur and ash. However, gravimetric coal 

cleaning is not technically feasible for low sulfur, low ash, and low inorganic-sulfur content coal 

such as the coal from the Powder River Basin in Wyoming. Otter Tail Power Company’s Big 

Stone facility’s primary fuel source is subbituminous coal obtained from the Powder River Basin 

in Wyoming. As such, coal cleaning is not a technical feasible option for Otter Tail Power 

Company. 

Coal upgrading such as a process developed by Evergreen Energy (formerly KFx) called the KFuel process enriches the coal by utilizing high pressure and temperature conditions to reduce 

moisture and inorganic materials. Typically, the K-Fuel process is utilized to reduce the moisture 

content and increase the coal heating value, however, the process may remove some sulfur 

compounds. Evergreen Energy constructed a K-Fuel production facility in Gillette, Wyoming 

which may produce approximately 750,000 tons per year of K-Fuel. Otter Tail Power Company 

burned approximately 2,268,000 tons of coal in 2008. As such, coal upgrading is not a 

technically feasible option for Otter Tail Power Company because there is not enough being 

produced to supply Otter Tail Power Company’s needs. In addition, based on Evergreen 

Energy’s webpage, this facility has been idle since calendar year 2008. 

Hydrated lime injection is a system that injects hydrated lime prior to the particulate collection 

system. The hydrated lime absorbs the sulfur dioxide and is collected in the particulate control 

device. Hydrated lime is also referred to as calcium hydroxide. The sulfur dioxide reacts with 

the calcium hydroxide to form calcium sulfate or calcium sulfite. Fly ash from the Powder River 

Basin has a calcium content of up to 30 percent. Since the Powder River Basin coal is already 

providing additional calcium to adsorb sulfur dioxide, the hydrated lime will not likely provide 

additional sulfur dioxide removal. Otter Tail Power Company’s primary fuel source is 

subbituminous coal obtained from the Powder River Basin in Wyoming. As such, hydrated lime 

injection is not considered a technically feasible option for Otter Tail Power Company since the 

concept is already taking place by using Power River Basin coal. 

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: 
86 

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. 

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 
87 

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. 

 

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. 
88 

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. 

6.3.3.2 Technically Feasible Nitrogen Oxide Control Technologies 

Low-nitrogen oxide burners limit nitrogen oxide formation by controlling the stoichiometric and 

temperature profiles of the combustion process. Low-nitrogen oxide burners attempt to delay the 

complete mixing of fuel and air as long as possible within the constraints of the furnace design. 

This is the reason flames from low-nitrogen oxide burners are longer than conventional burners. 

Cyclone furnace’s length and diameter are not designed with sufficient size to allow for lownitrogen oxide burners to be installed allowing stable combustion. As such, low-nitrogen oxide 

burners are not considered a technically feasible option for Otter Tail Power Company. 

 

Flue-gas recirculation reduces the formation of thermal nitrogen oxide emissions in a boiler by 

limiting the amount of oxygen available for oxidation in the fuel rich zone of the boiler. Fluegas recirculation is not known to reduce nitrogen oxide emissions any further when added with 

an over-fire air system. Therefore, Otter Tail Power Company did not conduct any further 

review of flue-gas recirculation. However, this reasoning does not justify that flue-gas 
89 

recirculation is not a feasible technology to consider. Therefore, DENR will consider the fluegas recirculation as a feasible control technology. 

Catalytic absorption/oxidation such as SCONOx or EMx systems is a nitrogen oxide control 

technology that utilizes a proprietary catalytic oxidation and absorption technology which 

oxidizes nitrogen oxide (NO) and carbon monoxide (CO) to nitrogen dioxide (NO2) and carbon 

dioxide (CO2), respectively. The nitrogen dioxide is then absorbed onto an absorption media 

while carbon dioxide is released to the atmosphere. Once the absorption media becomes 

saturated, the nitrogen dioxide is desorbed and treated by a proprietary catalyst. The SCONOx 

system is being considered as a cross over technology to coal-fired boilers, but to date has only 

been applied to “clean flue gas” systems such as natural-gas fired combustions turbines. The 

catalytic absorption/oxidation system requires a high operating temperature and low particulate 

loading. Therefore, the system would have to be installed after the particulate control device and 

require a flue gas reheater. DENR was unable to find a coal-fired system that was using a 

catalytic absorption/oxidation system or find that this system was being marketed commercially 

for coal fired boilers. As noted in 40 CFR Part 51, Appendix Y, a control technology needs to be 

commercially available to be considered technically feasible. As such the catalytic 

absorption/oxidation system is not considered a technically feasible option for Otter Tail Power 

Company. 

Gas reburning is a nitrogen oxide control technology that uses a second combustion zone 

following the primary combustion zone in the boiler. In a cyclone boiler, such as the one being 

operated at Otter Tail Power Company’s Big Stone I facility, burning the coal produces molten 

slag along the cyclone barrels. The molten slag catches subsequent coal until the combustion is 

complete. Generally, cyclone burners operate near the slag-tapping limits. Therefore, using 

natural gas or another fuel source as the reburn fuel may inhibit the molten slag formation. In 

addition, by trying to lower the air to fuel ratio more than achieved by the existing over-fire air 

systems may cause slag “freezing” at low load levels. As such gas reburn is not considered a 

technically feasible option for Otter Tail Power Company. 

Oxygen enhanced combustion is a nitrogen oxide combustion control technology that reduces the 

formation of thermal nitrogen oxides in the boiler. Developed by Praxair Technology Inc., this 

method uses oxygen in the burner instead of air to achieve additional nitrogen oxide reductions. 

To date, the largest demonstration of this technology is a 30 megawatt pilot demonstration at 

Babcock and Wilcock’s Clean Environmental Development facility in Alliance, Ohio. As noted 

on Babcock and Wilcock’s website - http://www.babcock.com/, the project was a pilot test of the 

technology and the next step is to demonstrate the technology at a commercial scale. As noted in 

40 CFR Part 51, Appendix Y, a control technology needs to be commercially available to be 

considered technically feasible. As such the oxygen enhanced combustion is not considered a 

technically feasible option for Otter Tail Power Company. 

 

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. 
90 

DENR determined that the following nitrogen oxide control technologies were feasible for Otter 

Tail Power Company: 

1. Over-fire air (OFA); 

2. Separated over-fire air (SOFA); 

3. Selective non-catalytic reduction (SNCR); 

4. Rich reagent injection (RRI); 

5. Selective catalytic reduction (SCR) ; and 

6. Flue-gas recirculation. 

6.3.3.3 Nitrogen Oxide 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 6.9. 

Table 6-9 – Comparison of Control Effectiveness for Nitrogen Oxide Controls 

Emission Rate Control Efficiency 

Otter Tail 1 RBLC 3 Basin 4 EPA 5 IEA 6

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

#1 SCR and 

SOFA 7

0.10 0.05 to 0.1 0.05 35 to 90 80 to 90 

#2 RRI, SNCR 

and SOFA 8

0.20 0.07 to 0.15 0.10 35 to 90 30 to 50 

#3 SNCR and 

SOFA 9

0.35 0.07 to 0.15 0.10 35 to 90 30 to 50 

#4 Separated 

over-fire air 

0.50 Not Identified Not Identified 30 to 70 Not 

Identified 

#5 Over-fire air 0.65 Not Identified Not Identified 30 to 70 Not 

Identified 

#6 Flue Gas 

Recirculation 

Not Identified Not Identified Not Identified 30 to 70 Not 

Identified 

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 which is for a new pulverized-fired boiler 

equipped with a low-NOx burner combustion technology. The emission rates were primarily based 

on if the system used selective catalytic reduction or selective non-catalytic reduction; 

5

 – The emission rates are from page 27 of the EPA’s Technical Bulletin – “Nitrogen Oxides; Why 

and How they are Controlled”. 6

 – The emission rates were obtained from the IEA Clean Coal Centre’s Webpage - http://www.ieacoal.org.uk/site/ieacoal/home. The emission rates were primarily based on if the system used 

selective catalytic reduction or selective non-catalytic reduction. 
91 

7

 – SCR and SOFA refers to selective catalytic reduction and separated over-fire air; 

8

 – RRI, SNCR, and SOFA refers to rich reagent injection, selective non-catalytic reduction and 

separated over-fire air, respectively; and 

9

 – SNCR and SOFA refers to selective non-catalytic reduction and separated over-fire air. 

6.3.3.4 Nitrogen Oxide 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. 

Otter Tail Power Company identified cost estimates for five control options. Table 6-10 

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 nitrogen oxide is based on the highest average 24-hour average emission 

rate (4,855 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. 
92 

Table 6-10 – Comparison of Control Effectiveness for Nitrogen Oxide Controls 

Control 

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

Cost 

Effectiveness 4

SCR and 

SOFA 5

$81,800,000 $4,110,000 $13,210,000 16,000 $825 

RRI, SNCR 

and SOFA 6

$16,200,000 $7,260,000 $11,390,000 13,910 $818 

SNCR and 

SOFA 7

$11,900,000 $2,120,000 $3,990,000 10,780 $197 

SOFA 8 $4,800,000 $152,000 $650,000 7,640 $85 

Over-fired air $0 $106,000 $140,000 4,510 $31 

1

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

2

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

and operational and maintenance costs; 

3

 – Reduction represents the amount of nitrogen oxide reduced in tons per year annual from the 

baseline level of 18,000 tons of nitrogen oxide per year; 

4

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

(dollar per ton); 

5

 – SCR and SOFA refers to selective catalytic reduction and separated over-fire air; 

6

 – RRI, SNCR, and SOFA refer to rich reagent injection, selective non-catalytic reduction and 

separated over-fire air; 

7

 – SNCR and SOFA refers to selective non-catalytic reduction and separated over-fire air; and 

8

 – SOFA refers to separated over-fire air. 

Otter Tail Power Company did not identify a 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 6-11 summarizes Otter Tail Power Company’s estimated energy impacts. 

Table 6-11 – Estimated Energy Impacts for Nitrogen Oxide Controls 

Control Energy Demand Percent of Generation

Selective catalytic reduction and 

Separated over-fire air 

400 to 1,000 kilowatts Less than 0.2 percent 

Rich reagent injection, Selective 

non-catalytic reduction and 

Separated over-fire air 

150 to 400 kilowatts Less than 0.1 percent 

Selective non-catalytic reduction 

and Separated over-fire air 

150 to 400 kilowatts Less than 0.1 percent 

Separated over-fire air 1 kilowatt Negligible 

Over-fire air 1 kilowatt Negligible 

The over-fire air and the separated over-fire air will increase the amount of unburned carbon in 

the flyash, which will increase the amount of flyash that needs to be properly disposed. Otter 

Tail Power Company considers this increase negligible compared to the existing amount flyash 

being properly disposed. 
93 

The selective non-catalytic reduction and the selective catalytic reduction will generate a small 

amount of unreacted ammonia or urea to be emitted. Even though ammonia and urea are not 

considered regulated air pollutants, these emissions are involved in the formation of ammonium 

sulfates and ammonium nitrates, which contribute to the amount of visibility impairment. 

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. 

6.3.4 Visibility Impact Evaluations 

In accordance with 40 CFR Part 51, Appendix Y, a source that has an impact equal to or greater 

than 1.0 deciviews is considered to “cause” a visibility impairment and that establishing a 

threshold for what is considered to “contribute” to a visibility impairment should not be any 

higher than 0.5 deciviews. DENR is proposing to define “contribute” to visibility impairment as 

a change in visibility impairment in a mandatory Class I federal area of 0.5 deciviews or more, 

based on a 24-hour average, above the average natural visibility baseline. A source exceeds the 

threshold when the 98th percentile (eighth highest value) of the modeling results, based on one 

year of the three years of meteorological data modeled, exceeds the 0.5 deciviews. 

Otter Tail Power Company modeled its existing operations impact on seven Class I areas that are 

located in Michigan, Minnesota, North Dakota, and South Dakota. Table 6-12 identifies the 

potential impact based on the 98th percentile for the existing Big Stone I facility has while 

emitting approximately 18,000 tons of sulfur dioxide, 18,000 tons of nitrogen oxides, and 300 

tons of particulate matter per year. 

Table 6-12 – Potential Impact of Existing Big Stone I (98th Percentile) 

Class I Area 2002 1,2 2006 1,2 2007 1,2

Boundary Waters 0.574 (0.6) 0.790 (0.8) 1.079 (1.1) 

Voyageurs 0.623 (0.6) 0.574 (0.6) 0.724 (0.7) 

Wind Cave 0.305 (0.3) 0.120 (0.1) 0.325 (0.3) 

Theodore Roosevelt 0.215 (0.2) 0.459 (0.5) 0.322 (0.3) 

Lostwood 0.232 (0.2) 0.385 (0.4) 0.409 (0.4) 

Badlands 0.452 (0.5) 0.481 (0.5) 0.471 (0.5) 

Isle Royale 0.629 (0.6) 0.506 (0.5) 0.665 (0.7) 

1

 – The modeling was conducted using the meteorological data for calendar years 2002, 2006, and 

2007; and 

2

 – The results are represented in deciviews. Otter Tail Power Company identified the deciview 

valued identified in the model to three decimal places which is consistent with how WRAP reported 

the visibility impacts in Table 6-3. The value in parentheses represents the value that is used to 

compare to the proposed contribution threshold of 0.5. 

Based on the modeling results, Otter Tail Power Company’s Big Stone I facility contributes to 

visibility impairment at Boundary Waters, Voyageurs, Theodore Roosevelt, Badlands, and Isle 

Royale because they have a deciview impact of 0.5 or greater. 
94 

Otter Tail Power Company conducted visibility modeling for 10 different control option 

scenarios and each scenario for three calendar years worth of meteorological data. The 10 

different control option scenarios simultaneously considered the emissions of nitrogen oxide, 

sulfur dioxide, and particulate matter. Table 6-13 identifies the emission rates used in the 

modeling for each different control option. 

Table 6-13 – Emission Rates for Each Control Option 

Option Control Equipment SO2 11 NOx 12 PM10 13

#1 OFA and Dry FGD #1 1

 841.4 3645.9 84.1 

#2 OFA and Wet FGD #1 2

 841.4 3645.9 84.1 

#3 OFA and Dry FGD #2 3

 504.8 3645.9 84.1 

#4 OFA and Wet FGD #2 4

 241.2 3645.9 84.1 

#5 SOFA and Dry FGD #1 5

 841.4 2804.5 84.1 

#5a SOFA and Dry FGD #2 6

 504.8 2804.5 84.1 

#5b SOFA and Wet FGD #2 7

 241.2 2804.5 84.1 

#6 SNCR, SOFA, and Dry FGD #1 8

 841.4 1963.2 84.1 

#7 RRI, SNCR, SOFA, and Dry FGD #1 9

 841.4 1121.8 84.1 

#8 SCR, SOFA, and Dry FGD #1 10 841.4 560.9 84.1 

1

 – OFA and Dry FGD #1 refers to over-fire air and semi-dry flue gas desulfurization system meeting 

an emission rate of 0.15 pounds per million British thermal units; 

2

 – OFA and Wet FGD #1 refers to over-fire air and wet flue gas desulfurization system meeting an 

emission rate of 0.15 pounds per million British thermal units; 

3

 – OFA and Dry FGD #2 refers to over-fire air and semi-dry flue gas desulfurization system meeting 

an emission rate of 0.09 pounds per million British thermal units; 

4

 – OFA and Wet FGD #2 refers to over-fire air and wet flue gas desulfurization system meeting an 

emission rate of 0.043 pounds per million British thermal units; 

5

 – SOFA and Dry FGD #1 refers to separated over-fire air and semi-dry flue gas desulfurization 

system meeting an emission rate of 0.15 pounds per million British thermal units; 

6

 – SOFA and Dry FGD #2 refers to separated over-fire air and semi-dry flue gas desulfurization 

system meeting an emission rate of 0.09 pounds per million British thermal units; 

7

 – SOFA and Wet FGD #2 refers to separated over-fire air and wet flue gas desulfurization system 

meeting an emission rate of 0.043 pounds per million British thermal units; 

8

 – SNCR, SOFA, and Dry FGD #1 refers to selective non-catalytic reduction, separated over-fire air, 

and semi-dry flue gas desulfurization system meeting an emission rate of 0.15 pounds per million 

British thermal units; 

9

 – RRI, SNCR, SOFA, and Dry FGD #1 refers to rich reagent injection, selective non-catalytic 

reduction, separated over-fire air, and semi-dry flue gas desulfurization system meeting an emission 

rate of 0.15 pounds per million British thermal units; 

10 – SCR, SOFA, and Dry FGD #1 refers to selective catalytic reduction, separated over-fire air, and 

semi-dry flue gas desulfurization system meeting an emission rate of 0.15 pounds per million British 

thermal units; 

11 – SO2 represents the sulfur dioxide emission rate in pounds per hour; 

12 – NOx represents the nitrogen oxide emission rate in pounds per hour; and 

13 – PM10 represents the particulate matter less than 10 microns emission rate in pounds per hour. 

Table 6-14 provides the results of the modeling (98th percentile) using the different control 

options and emissions rates in Table 6-13. Again, Otter Tail Power Company identified the 
95 

deciview valued identified in the model to three decimal places which is consistent with how 

WRAP reported the visibility impacts in Table 6-3. The value in parentheses represents the 

value that DENR used to compare to the proposed contribution threshold of 0.5. 

Table 6-14 – Modeling Results for Each Control Option (98th Percentile – Deciviews) 

Option Control Equipment Class I Area 2002 2006 2007 

#1 OFA and Dry FGD #1 1

 Boundary Waters 0.330 (0.3) 0.548 (0.5) 0.657 (0.7) 

 Voyageurs 0.329 (0.3) 0.399 (0.4) 0.460 (0.5) 

 Isle Royale 0.377 (0.4) 0.296 (0.3) 0.339 (0.3) 

 Badlands 0.223 (0.2) 0.176 (0.2) 0.241 (0.2) 

 Theodore Roosevelt 0.092 (0.1) 0.247 (0.2) 0.190 (0.2) 

#2 OFA and Wet FGD #1 2

 Boundary Waters 0.360 (0.4) 0.546 (0.5) 0.667 (0.7) 

 Voyageurs 0.349 (0.3) 0.494 (0.5) 0.521 (0.5) 

 Isle Royale 0.367 (0.4) 0.273 (0.3) 0.323 (0.3) 

 Badlands 0.234 (0.2) 0.199 (0.2) 0.254 (0.3) 

 Theodore Roosevelt 0.099 (0.1) 0.244 (0.2) 0.161 (0.2) 

#3 OFA and Dry FGD #2 3

 Boundary Waters 0.319 (0.3) 0.534 (0.5) 0.620 (0.6) 

 Voyageurs 0.307 (0.3) 0.391 (0.4) 0.450 (0.5) 

 Isle Royale 0.363 (0.4) 0.287 (0.3) 0.323 (0.3) 

 Badlands 0.219 (0.2) 0.172 (0.2) 0.230 (0.2) 

 Theodore Roosevelt 0.087 (0.1) 0.234 (0.2) 0.173 (0.2) 

#4 OFA and Wet FGD #2 4

 Boundary Waters 0.350 (0.4) 0.521 (0.5) 0.611 (0.6) 

 Voyageurs 0.312 (0.3) 0.464 (0.5) 0.502 (0.5) 

 Isle Royale 0.351 (0.4) 0.250 (0.3) 0.290 (0.3) 

 Badlands 0.225 (0.2) 0.191 (0.2) 0.234 (0.2) 

 Theodore Roosevelt 0.084 (0.1) 0.230 (0.2) 0.138 (0.1) 

#5 SOFA and Dry FGD #1 5

 Boundary Waters 0.264 (0.3) 0.433 (0.4) 0.524 (0.5) 

 Voyageurs 0.263 (0.3) 0.314 (0.3) 0.364 (0.4) 

 Isle Royale 0.298 (0.3) 0.235 (0.2) 0.272 (0.3) 

 Badlands 0.169 (0.2) 0.137 (0.1) 0.191 (0.2) 

 Theodore Roosevelt 0.076 (0.1) 0.199 (0.2) 0.156 (0.2) 

#5a SOFA and Dry FGD #2 6

 Boundary Waters 0.250 (0.3) 0.419 (0.4) 0.493 (0.5) 

 Voyageurs 0.249 (0.2) 0.306 (0.3) 0.354 (0.4) 

 Isle Royale 0.285 (0.3) 0.226 (0.2) 0.256 (0.3) 

 Badlands 0.165 (0.2) 0.133 (0.1) 0.180 (0.2) 

 Theodore Roosevelt 0.069 (0.1) 0.186 (0.2) 0.141 (0.1) 

#5b SOFA and Wet FGD #2 7

 Boundary Waters 0.274 (0.3 0.407 (0.4) 0.478 (0.5) 

 Voyageurs 0.244 (0.2) 0.365 (0.4) 0.393 (0.4) 

 Isle Royale 0.274 (0.3) 0.195 (0.2) 0.227 (0.2) 

 Badlands 0.174 (0.2) 0.147 (0.1) 0.182 (0.2) 

 Theodore Roosevelt 0.066 (0.1) 0.180 (0.2) 0.108 (0.1) 

#6 SNCR, SOFA, Boundary Waters 0.200 (0.2) 0.318 (0.3) 0.388 (0.4) 

 and Dry FGD #1 8 Voyageurs 0.196 (0.2) 0.228 (0.2) 0.267 (0.3) 

 Isle Royale 0.221 (0.2) 0.174 (0.2) 0.199 (0.2) 

 Badlands 0.120 (0.1) 0.098 (0.1) 0.143 (0.1) 
96 

Option Control Equipment Class I Area 2002 2006 2007 

 Theodore Roosevelt 0.063 (0.1) 0.150 (0.2) 0.121 (0.1) 

#7 RRI, SNCR, SOFA, Boundary Waters 0.137 (0.1) 0.202 (0.2) 0.256 (0.3) 

 and Dry FGD #1 9 Voyageurs 0.130 (0.1) 0.157 (0.2) 0.176 (0.2) 

 Isle Royale 0.142 (0.1) 0.115 (0.1) 0.134 (0.1) 

 Badlands 0.090 (0.1) 0.066 (0.1) 0.099 (0.1) 

 Theodore Roosevelt 0.050 (0.1) 0.101 (0.1) 0.080 (0.1) 

#8 SCR, SOFA, Boundary Waters 0.097 (0.1) 0.136 (0.1) 0.170 (0.2) 

 and Dry FGD #1 10 Voyageurs 0.086 (0.1) 0.107 (0.1) 0.123 (0.1) 

 Isle Royale 0.092 (0.1) 0.077 (0.1) 0.098 (0.1) 

 Badlands 0.079 (0.1) 0.060 (0.1) 0.070 (0.1) 

 Theodore Roosevelt 0.036 (0.0) 0.070 (0.1) 0.064 (0.1) 

1

 – OFA and Dry FGD #1 refers to over-fire air and semi-dry flue gas desulfurization system meeting 

an emission rate of 0.15 pounds per million British thermal units; 

2

- OFA and Wet FGD #1 refers to over-fire air and wet flue gas desulfurization system meeting an 

emission rate of 0.15 pounds per million British thermal units; 

3

 - OFA and Dry FGD #2 refers to over-fire air and semi-dry flue gas desulfurization system meeting 

an emission rate of 0.09 pounds per million British thermal units; 

4

 - OFA and Wet FGD #2 refers to over-fire air and wet flue gas desulfurization system meeting an 

emission rate of 0.043 pounds per million British thermal units; 

5

 – SOFA and Dry FGD #1 refers to separated over-fire air and semi-dry flue gas desulfurization 

system meeting an emission rate of 0.15 pounds per million British thermal units; 

6

 – SOFA and Dry FGD #2 refers to separated over-fire air and semi-dry flue gas desulfurization 

system meeting an emission rate of 0.09 pounds per million British thermal units; 

7

 – SOFA and Wet FGD #2 refers to separated over-fire air and wet flue gas desulfurization system 

meeting an emission rate of 0.043 pounds per million British thermal units; 

8

 – SNCR, SOFA, and Dry FGD #1 refers to selective non-catalytic reduction, separated over-fire air, 

and semi-dry flue gas desulfurization system meeting an emission rate of 0.15 pounds per million 

British thermal units; 

9

 - RRI, SNCR, SOFA, and Dry FGD #1 refers to rich reagent injection, selective non-catalytic 

reduction, separated over-fire air, and semi-dry flue gas desulfurization system meeting an emission 

rate of 0.15 pounds per million British thermal units; and 

10 - SCR, SOFA, and Dry FGD #1 refers to selective catalytic reduction, separated over-fire air, and 

semi-dry flue gas desulfurization system meeting an emission rate of 0.15 pounds per million British 

thermal units. 

Based on the modeling results in Table 6-14, Otter Tail Power Company would have to use 

Option #6, #7, or #8 to not reasonably contribute to visibility impairment in the Boundary 

Waters, Voyageurs, Isle Royale, Badlands, and Theodore Roosevelt National Parks.

Otter Tail Power Company did not provide a cost per deciview reduction for each of the 

proposed control options. DENR calculated a cost per deciview reduction by summing the 

annualized cost of each of the control alternatives associated with the control options and 

dividing by the visibility reduction identified by the modeling from the baseline condition. Table 

6-15 provides a cost per deciview comparison. 
97 

Table 6-15 – Cost per Deciview Comparison ($/deciview) 

Option 

Control 

Equipment Class I Area 2002 2006 2007 

#1 OFA and Boundary Waters $ 96,188,525 $ 96,983,471 $ 55,616,114 

Dry FGD #1 1

 Voyageurs $ 79,829,932 $ 134,114,286 $ 88,901,515 

 Isle Royale $ 93,134,921 $ 111,761,905 $ 71,993,865 

 Badlands $ 102,489,083 $ 79,950,820 $ 102,043,478

 Theodore Roosevelt $ 190,813,008 $ 110,707,547 $ 177,803,030

Cumulative $ 15,998,637 $ 16,108,442 $ 13,542,989

#2 OFA and Boundary Waters $ 135,700,935 $ 119,016,393 $ 70,485,437 

Wet FGD #1 2

 Voyageurs $ 105,985,401 $ 363,000,000 $ 143,054,187 

 Isle Royale $ 110,839,695 $ 124,635,193 $ 84,912,281 

 Badlands $ 133,211,009 $ 102,978,723 $ 133,824,885

 Theodore Roosevelt $ 250,344,828 $ 135,069,767 $ 180,372,671

Cumulative $ 20,625,000 $ 21,337,252 $ 17,224,199

#3 OFA and Boundary Waters $ 92,980,392 $ 92,617,188 $ 51,655,773 

Dry FGD #2 3 Voyageurs $ 75,031,646 $ 129,562,842 $ 86,532,847 

 Isle Royale $ 89,135,338 $ 108,264,840 $ 69,327,485 

 Badlands $ 101,759,657 $ 76,731,392 $ 159,127,517

 Theodore Roosevelt $ 185,234,375 $ 105,377,778 $ 98,381,743

Cumulative $ 15,466,406 $ 15,588,429 $ 12,795,467

#4 OFA and Boundary Waters $ 130,312,500 $ 108,513,011 $ 62,371,795 

Wet FGD #2 4

 Voyageurs $ 93,858,521 $ 265,363,636 $ 131,486,486 

 Isle Royale $ 105,000,000 $ 114,023,438 $ 77,840,000 

 Badlands $ 128,590,308 $ 100,655,172 $ 123,164,557

 Theodore Roosevelt $ 222,824,427 $ 127,467,249 $ 158,641,304

Cumulative $ 19,140,984 $ 19,590,604 $ 15,617,978

#5 SOFA and Boundary Waters $ 77,354,839 $ 67,170,868 $ 43,207,207 

Dry FGD #1 5 Voyageurs $ 66,611,111 $ 92,230,769 $ 66,611,111 

 Isle Royale $ 72,447,130 $ 88,487,085 $ 61,017,812 

 Badlands $ 84,734,392 $ 69,709,302 $ 85,642,857

 Theodore Roosevelt $ 172,517,986 $ 92,230,769 $ 144,457,831

Cumulative $ 13,411,633 $ 13,018,458 $ 11,045,601

#5a SOFA and Boundary Waters $ 74,753,086 $ 65,283,019 $ 41,331,058 

Dry FGD #2 6

 Voyageurs $ 64,759,358 $ 90,373,134 $ 65,459,459 

 Isle Royale $ 70,406,977 $ 86,500,000 $ 59,217,604 

 Badlands $ 84,390,244 $ 69,597,701 $ 83,230,241

 Theodore Roosevelt $ 165,890,411 $ 88,717,949 $ 133,812,155

Cumulative $ 13,070,696 $ 12,727,273 $ 10,544,188

#5b SOFA and Boundary Waters $ 99,000,000 $ 77,545,692 $ 49,417,637 

Wet FGD #2 7

 Voyageurs $ 78,364,116 $ 142,105,263 $ 89,728,097 

 Isle Royale $ 83,661,972 $ 95,498,392 $ 67,808,219 

 Badlands $ 106,834,532 $ 88,922,156 $ 102,768,166

 Theodore Roosevelt $ 199,328,589 $ 106,451,613 $ 138,785,047
98 

Option 

Control 

Equipment Class I Area 2002 2006 2007 

Cumulative $ 16,019,417 $ 15,730,932 $ 12,724,936

#6 SNCR, SOFA, Boundary Waters $ 73,048,128 $ 57,881,356 $ 39,536,903 

and Voyageurs $ 63,981,265 $ 78,959,538 $ 59,781,182 

Dry FGD #1 8 Isle Royale $ 66,960,784 $ 82,289,157 $ 58,626,609 

 Badlands $ 82,289,157 $ 71,331,593 $ 83,292,683

 Theodore Roosevelt $ 179,736,842 $ 88,414,239 $ 135,920,398

Cumulative $ 13,115,699 $ 12,262,118 $ 10,368,121

#7 RRI, SNCR, Boundary Waters $ 79,450,801 $ 59,047,619 $ 42,187,120 

SOFA, and Voyageurs $ 70,425,963 $ 83,261,391 $ 63,357,664 

Dry FGD #1 9 Isle Royale $ 71,293,634 $ 88,797,954 $ 65,386,064 

 Badlands $ 95,911,602 $ 83,662,651 $ 93,333,333

 Theodore Roosevelt $ 210,424,242 $ 96,983,240 $ 143,471,074

Cumulative $ 14,711,864 $ 13,467,804 $ 11,280,052

#8 SCR, SOFA, Boundary Waters $ 76,603,774 $ 55,871,560 $ 40,198,020 

and Voyageurs $ 68,044,693 $ 78,244,111 $ 60,798,669 

Dry FGD #1 10 Isle Royale $ 68,044,693 $ 85,174,825 $ 64,444,444 

 Badlands $ 97,962,466 $ 86,793,349 $ 91,122,195

 Theodore Roosevelt $ 204,134,078 $ 93,933,162 $ 141,627,907

Cumulative $ 14,329,412 $ 13,101,470 $ 10,900,955 

1

 – OFA and Dry FGD #1 refers to over-fire air and semi-dry flue gas desulfurization system meeting 

an emission rate of 0.15 pounds per million British thermal units; 

2

- OFA and Wet FGD #1 refers to over-fire air and wet flue gas desulfurization system meeting an 

emission rate of 0.15 pounds per million British thermal units; 

3

 - OFA and Dry FGD #2 refers to over-fire air and semi-dry flue gas desulfurization system meeting 

an emission rate of 0.09 pounds per million British thermal units; 

4

 - OFA and Wet FGD #2 refers to over-fire air and wet flue gas desulfurization system meeting an 

emission rate of 0.043 pounds per million British thermal units; 

5

 – SOFA and Dry FGD #1 refers to separated over-fire air and semi-dry flue gas desulfurization 

system meeting an emission rate of 0.15 pounds per million British thermal units; 

6

 – SOFA and Dry FGD #2 refers to separated over-fire air and semi-dry flue gas desulfurization 

system meeting an emission rate of 0.09 pounds per million British thermal units; 

7

 – SOFA and Wet FGD #2 refers to separated over-fire air and wet flue gas desulfurization system 

meeting an emission rate of 0.043 pounds per million British thermal units; 

8

 – SNCR, SOFA, and Dry FGD #1 refers to selective non-catalytic reduction, separated over-fire air, 

and semi-dry flue gas desulfurization system meeting an emission rate of 0.15 pounds per million 

British thermal units; 

9

 - RRI, SNCR, SOFA, and Dry FGD #1 refers to rich reagent injection, selective non-catalytic 

reduction, separated over-fire air, and semi-dry flue gas desulfurization system meeting an emission 

rate of 0.15 pounds per million British thermal units; and 

10 - SCR, SOFA, and Dry FGD #1 refers to selective catalytic reduction, separated over-fire air, and 

semi-dry flue gas desulfurization system meeting an emission rate of 0.15 pounds per million British 

thermal units. 
99 

Based on the cost per deciview reduction numbers in Table 6-15, the most cost effective controls 

options are #5A, #6 and #8. The cost effective control costs are generally within 10 percent of 

each other. 

6.3.5 BART Emissions Limits for Big Stone I 

EPA identifies in 40 CFR Part 51, Appendix Y that in determining the “best” available retrofit 

technology, the state has discretion to determine the order in which the state should evaluate 

control options for BART. The state should provide a justification for adopting the technology 

that is selected as the ‘‘best’’ level of control, including an explanation of the Clean Air Act 

factors that led the state to choose that option over other control levels. 

To complete the BART process, the state should establish enforceable emission limits that reflect 

the BART requirements and require compliance within a given period of time. In particular, the 

state should establish an enforceable emission limit for each subject emission unit at the source 

and for each pollutant subject to review that is emitted from the source. In addition, the state 

should require compliance with the BART emission limitations no later than five years after EPA 

approves South Dakota’s State Implementation Plan for regional haze. If technological or 

economic limitations in the application of a measurement methodology to a particular emission 

unit make a conventional emissions limit infeasible, the state may instead prescribe a design, 

equipment, work practice, operation standard, or combination of these types of standards. 

6.3.5.1 Particulate Matter BART Recommendation 

Otter Tail Power Company already installed and is operating a baghouse, which is the top 

particulate control technology. Therefore, there is no additional compliance cost, energy 

impacts, etc. that Otter Tail Power Company would have to endure. As such, DENR considers 

the continual use of the baghouse as BART for particulate matter. 

Otter Tail Power Company proposes an emission limit of 84.1 pounds per hour which they based 

on an emission rate of 0.015 pounds per million Btu and a maximum fuel heat input of 5,609 

million Btus per hour. Otter Tail Power Company proposes to comply with the pounds per hour 

limit using a 30-day rolling average. Each day, Otter Tail Power Company will multiply the 

emission rate, in pounds per million Btus as determined by the most recent annual performance 

test, by the heat input to the boiler, as determined by a continuous emission monitoring system, 

and dividing by the number of hours the boiler operated that day. 

In the December 11, 2006, application, Otter Tail Power Company proposed to replace the 

advanced hybrid particulate collector control system with the current day baghouse. In that 

application, Otter Tail Power Company noted that the baghouse would have a maximum 

filterable particulate matter emission rate of 0.012 pounds per million Btu of fuel heat input. The 

emission rate equates to 67.3 pounds per hour at 5,609 million Btus per hour heat input In May 

2009, Otter Tail Power Company conducted a performance test on the baghouse. The test results 

noted an average filterable particulate matter emission rate of 0.011 pounds per million Btus and 

57.6 pounds per hour. 
100 

DENR considers the emission limit representing BART as 67.3 pounds per hour. The hourly 

emission limit includes periods of startup and shutdown. DENR is also establishing a BART 

emission limit of 0.012 pounds per million Btus, which includes periods of startup and 

shutdown. Compliance with both emission limits shall be based on an annual stack performance 

test using the average of three 1-hour test runs. 

 

6.3.5.2 Sulfur Dioxide BART Recommendation 

Otter Tail Power Company is proposing the second ranked control option (semi-dry flue gas 

desulfurization system) to control sulfur dioxide emissions. Since control options #6, #7, and #8, 

which were the only three options that reduced the visibility less than the contribution level of 

0.5 deciviews, did not include the top ranked sulfur dioxide control alternative an analysis of the 

visibility impacts of the other control alternatives was considered. Even though the top ranked 

control option (wet flue gas desulfurization system) reduces the sulfur dioxide emissions more 

than the second ranked control option, neither of the two control options is considered a better 

control option when considering the visibility impacts. For example, Table 6-16 displays the 

comparison of the visibility impacts for control option #3 to control option #4 and control option 

#5a to control option #5b. These options were chosen because the emission rates for nitrogen 

oxide and particulate matter were constant, while the sulfur dioxide emissions varied as noted by 

the two different control alternatives. 

 

Table 6-16 – Visibility Comparison between Wet and Dry Scrubbers 

Control Option Class I Area 2002 2006 2007 

#3 OFA and Dry FGD #2 1

 Boundary Waters 0.319 0.534 0.620 

 Voyageurs 0.307 0.391 0.450 

 Isle Royale 0.363 0.287 0.323 

 Badlands 0.219 0.172 0.230 

 Theodore Roosevelt 0.087 0.234 0.173 

#4 OFA and Wet FGD #2 2

 Boundary Waters 0.350 0.521 0.611 

 Voyageurs 0.312 0.464 0.502 

 Isle Royale 0.351 0.250 0.290 

 Badlands 0.225 0.191 0.234 

 Theodore Roosevelt 0.084 0.230 0.138 

Comparison Review Boundary Waters ↑ ↓ ↓

 Voyageurs ↑ ↑ ↑

 Isle Royale ↓ ↓ ↓

 Badlands ↑ ↑ ↑

 Theodore Roosevelt ↓ ↓ ↓

#5a SOFA and Dry FGD #2 3

 Boundary Waters 0.250 0.419 0.493 

 Voyageurs 0.249 0.306 0.354 

 Isle Royale 0.285 0.226 0.256 

 Badlands 0.165 0.133 0.180 

 Theodore Roosevelt 0.069 0.186 0.141 

#5b SOFA and Wet FGD #2 4

 Boundary Waters 0.274 0.407 0.478 

 Voyageurs 0.244 0.365 0.393 
101 

Control Option Class I Area 2002 2006 2007 

 Isle Royale 0.274 0.195 0.227 

 Badlands 0.174 0.147 0.182 

 Theodore Roosevelt 0.066 0.180 0.108 

Comparison Review Boundary Waters ↑ ↓ ↓

 Voyageurs ↓ ↑ ↑

 Isle Royale ↓ ↓ ↓

 Badlands ↑ ↑ ↑

 Theodore Roosevelt ↓ ↓ ↓

1

 - OFA and Dry FGD #2 refers to over-fire air and semi-dry flue gas desulfurization system meeting 

an emission rate of 0.09 pounds per million British thermal units; 

2

 - OFA and Wet FGD #2 refers to over-fire air and wet flue gas desulfurization system meeting an 

emission rate of 0.043 pounds per million British thermal units; 

3

 – SOFA and Dry FGD #2 refers to separated over-fire air and semi-dry flue gas desulfurization 

system meeting an emission rate of 0.09 pounds per million British thermal units; and 

4

 – SOFA and Wet FGD #2 refers to separated over-fire air and wet flue gas desulfurization system 

meeting an emission rate of 0.043 pounds per million British thermal units. 

As noted in the table, approximately 40 percent of the modeling, the top ranked control option 

generated a higher visibility impact than the second ranked control option. Whereas, 

approximately 60 percent of the modeling, the second ranked control option generated a higher 

visibility impact than the top ranked control option. Therefore, based on the visibility modeling 

there is no discernable difference between these two control options. As such, DENR considers 

that the semi-dry flue gas desulfurization system is considered BART. 

Otter Tail Power Company proposes an emission limit of 505 pounds per hour based upon a 30-

day rolling average, which is based on the emission rate of 0.09 pounds per million Btu of fuel 

heat input at 5,609 million Btus per hour heat input. 

The presumptive emission limit established by EPA for scrubber systems is 0.15 pounds per 

million Btus of fuel heat input. The limit proposed by Otter Tail Power Company is more 

stringent than the presumptive limit identified by EPA. DENR considers the emission limit 

representing BART should be 505 pounds per hour and 0.09 pounds per million Btus, which 

would include periods of startup, shutdown and malfunction. Compliance with these emission 

limits shall be based on the continuous emission monitoring system and on a 30-day rolling 

average. 

 

6.3.5.3 Nitrogen Oxide BART Recommendation 

Otter Tail Power Company is proposing the fourth ranked control option (separated over-fire air) 

to control nitrogen oxide emissions. In reviewing the higher ranked control options, each option 

reduces the amount of nitrogen oxide emissions and the visibility impacts more than the fourth 

ranked control option (separated over-fire air). However, each of these higher ranking control 

options comes with a higher financial cost. 
102 

In establishing the nitrogen oxide presumptive BART requirements, EPA identified that $1,500 

per ton of nitrogen oxide removed was considered cost effective. (Federal Register Volume 70 

Number 128 on pages 39134 and 39135). EPA considers this threshold cost effective for a coal 

fired unit greater than 200 megawatts existing at a facility with a combined capacity greater than 

750 megawatts. 

Otter Tail Power Company’s Big Stone I facility does not have a capacity greater than 750 

megawatts and is not applicable to the established nitrogen oxide presumptive BART 

requirements. However, Otter Tail Power Company’s Big Stone I’s coal fired unit is greater 

than the 200 megawatt. As noted in Table 6-10, the cost of the control options on a $ per ton 

basis are all less than $900 per ton. As such DENR considers all the identified control options as 

cost effective on a $ per ton basis. 

As noted in Table 6-15, the cost on a $ per deciview basis indicates that control options #5a, #6 

and #8 are the most cost effective. Options #5a, #6 and #8 consider the operation of separated 

over-fire air, selective non catalytic reduction and selective catalytic reduction. It should be 

noted that the $ per deciview includes the cost for both sulfur dioxide and nitrogen oxide. 

As noted in Table 6-14, control options #6, #7, #8, were the only options that resulted in 

modeling less than 0.5 deciviews of visibility impairment. Again, it should be noted the 

modeling results includes the emissions of particulate matter, sulfur dioxide, and nitrogen oxide. 

None of the nitrogen oxide control alternatives have identified energy, non-air environmental, or 

have issues with the current life expectancy of the Big Stone I coal fire unit to preclude the use 

of any of the control options. As such DENR considers all the identified control options as being 

acceptable options based on impacts to energy, non-air environmental and life expectancy. 

Based on the visibility modeling, the first ranked control option (selective catalytic reduction) 

reduces the visibility more than any other control option. The selective catalytic reduction 

system also reduces the visibility an additional 34 percent over the second ranked control option 

and an additional 65 percent over the fourth ranked control option. The selective catalytic 

reduction is also considered cost effective on a $ per ton basis, is represented as part of the 

control option #8 that is one of the most cost effective options on a $ per deciview reduction 

basis and one of the options that modeling demonstrates less than 0.5 deciviews of visibility 

impairment. DENR considers selective catalytic reduction and separate over-fire air system as 

BART. 

The presumptive emission limit established by EPA for a selective catalytic reduction system 

installed on a cyclone coal fired unit is 0.10 pounds per million Btus of fuel heat input (Federal 

Register Volume 70 Number 128 on page 39172). DENR considers the emission limit 

representing BART should be 561 pounds per hour and 0.10 pounds per million Btus, which 

would include periods of startup, shutdown and malfunction. Compliance with the emission 

limits shall be based on the continuous emission monitoring system and on a 30-day rolling 

average. 
103 

6.4 BART Requirements 

Otter Tail Power Company’s Big Stone I reasonably contributes to visibility impairment at Class 

I areas and is considered a BART-eligible source subject to BART. Therefore, DENR is 

adopting BART requirements in its Administrative Rules of South Dakota under Chapter 

74:36:21 – Regional Haze Program. 

These requirements will be part of South Dakota’s Regional Haze State Implementation Plan and 

will be enforceable because they will establish emission limits representing BART; in 

accordance with 40 CFR § 51.308(e)(1)(v), the BART control equipment will be required to be 

properly operated and maintained; and testing, monitoring, recordkeeping, and reporting 

requirements will be established to ensure compliance with BART. One method of determining 

if control equipment is being properly operated and maintained is through monitoring the 

emissions from the unit. In Otter Tail Power Company’s case, continuous emission monitoring 

sulfur dioxide and nitrogen oxide is already required in their existing permit. The minimum 

requirements for the operation, maintenance, and monitoring requirements will be established in 

ARSD 74:36:21:07. In accordance with 40 CFR § 51.308(e)(1)(iv), DENR will require BART 

to be installed and operating as expeditiously as practicable, but no later than 5 years from EPA’s 

approval of South Dakota’s Regional Haze Program. The deadline for installing BART will be 

established in ARSD 74:36:21:06. 

In accordance with 40 CFR § 51.308(e)(5), once the requirements of BART are achieved, Otter 

Tail Power Company will be subject to the requirements of South Dakota’s State Implementation 

Plan in the same manner as other sources. 

7.0 Reasonable Progress 

In accordance with 40 CFR § 51.308(d)(1), for each mandatory Class I area located within the 

state, the state must establish goals, expressed in deciviews, that provide reasonable progress 

towards achieving natural visibility conditions by 2064. The reasonable progress goals must 

provide improvement in visibility for the 20% most impaired days over the period of the 

implementation plan and ensure no degradation in visibility for the 20% least impaired days over 

the same period. In accordance with 40 CFR § 51.308(d)(1)(v), the reasonable progress goals 

established by the state are not directly enforceable but will be considered in the evaluation of 

the adequacy of the measures a state would implement to achieve natural conditions by 2064. In 

accordance with 40 CFR § 51.308(d)(1)(vi), the state may not adopt a reasonable progress goal 

that represents less visibility improvement than is expected to result from implementation of 

other requirements of the federal Clean Air Act during the applicable planning period. 

The EPA published the Guidance for Setting Reasonable Progress Goals under the Regional 

Haze Rule, 2007, for setting reasonable progress goals. The basic steps include: 

1. Establish baseline and natural visibility conditions; 

2. Determine the glide path or uniform rate of progress; 

3. Identify and analyze the measures aimed at achieving the uniform rate of progress using 

the following approaches: 
104 

a. Identify the key pollutants, sources and/or source categories that are contributing to 

visibility impairment at each Class I area. The sources of impairment for the most 

impaired and least impaired days may differ; 

b. Identify the control measures and associated emission reductions that are expected to 

result from compliance with existing rules and other available measurements for the 

sources and source categories that contribute significantly to visibility impairment; 

c. Determine what additional control measures would be reasonable based on the 

statutory factors and other relevant factors for the sources and/or source categories 

you have identified; 

d. Estimate through the use of air quality models the improvement in visibility that 

would result from implementation of the control measures you have found to be 

reasonable and compare this to the uniform rate of progress; and 

4. Establish the reasonable progress goals. 

DENR determined natural visibility conditions (see Table 3-7) and the uniform slope of 

reduction for each Class I area (see Figure 3-5). 

7.1 State and Federal Rules 

South Dakota’s current air quality rules under Administrative Rules of South Dakota (ARSD) 

article 74:36 – Air Pollution Control Program, currently protects and improves visibility in Class 

I areas. Examples of existing rules that protect and improve visibility in Class I areas are listed 

below: 

1. ARSD § 74:36:01:05 – Applicable requirements of Clean Air Act defined: Subsection 

(12) states “Any national ambient air quality standard or increment or visibility 

requirement under Part C of Title I of the Clean Air Act, but only as it would apply to 

temporary sources permitted pursuant to § 504(e) of the Clean Air Act”; 

2. ARSD § 74:36:01:10 – Modification defined: Subsection (3) states “The change requires 

or changes a case-by-case determination of an emission limit or other standard, a 

source-specific determination for temporary sources of ambient impacts, or a visibility or 

increment analysis”; 

3. ARSD § 74:36:02:01 – Air quality goals: Subsection (3) states one of the goals is 

“optimization of visibility”; 

4. ARSD § 74:36:04 – Operating permits for minor sources and § 74:36:05 – Operating 

permits for Part 70 sources: The permits issued under these chapters require sources to 

meet all applicable emission limits, demonstrate compliance, monitoring, recordkeeping 

and reporting requirements to ensure compliance with all applicable requirements of the 

Clean Air Act; 

5. ARSD §§ 74:36:06 – Regulated Air Pollutant Emissions; 74:36:07 – New Source 

Performance Standards; 74:36:08 – National Emission Standards for Hazardous Air 

Pollutants, and ARSD § 74:36:12 – Control of Visible Emissions: These chapters restrict 

air emissions from regulated entities that contribute to visibility impairment and prohibits 

certain open burning practices such as open burning waste oil, rubber, waste tires, asphalt 

shingles, railroad ties, etc.; 
105 

6. ARSD § 74:36:09 – Prevention of Significant Deterioration: This chapter requires a 

visibility analysis to prevent sources subject to these requirements from contributing to 

visibility impairment in Class I Areas; 

7. ARSD § 74:36:10 – New Source Review: This chapter requires a visibility analysis to 

prevent sources subject to these requirements from contributing to visibility impairment 

in Class I Areas; and 

8. ARSD § 74:36:18 – Regulations for State Facilities in the Rapid City Area: This chapter 

restricts visible emissions from fugitive sources. 

The chapters and sections listed above are included in South Dakota’s State Implementation 

Plan. 

DENR adopted rules that will establish BART emission limits, recordkeeping requirements, 

monitoring requirements, and reporting requirements for BART-eligible sources that will reduce 

their impacts on Class I areas. In addition, DENR adopted rules that will require new major 

sources and a modification to an existing major source that are not subject to New Source 

Review to conduct a visibility impact analysis to ensure the proposal will not contribute to 

adverse impact on visibility in an mandatory Class I area. 

On the federal side, gains in visibility should have already occurred from the implementation of 

the Acid Rain Program and future gains will occur from the implementation of federal emission 

standards established for mobile sources and federal fuel standards.

7.2 2018 Projected Visibility Conditions 

The reasonable progress goals are interim goals that represent incremental improvement in 

visibility over time and are compared to the uniform rate of progress for achieving natural 

visibility by 2064. The first year in determining if states are meeting their reasonable progress 

goals is 2018. WRAP gathered the reductions that will occur through this timeframe from states 

and federal regulations and modeled the results to project where states will be at in 2018. 

The information WRAP gathered was entered into a CMAQ model for the Class I areas in the 

WRAP region to project visibility improvements. The CMAQ model was used to estimate 2018 

visibility conditions in South Dakota and all Western Class I areas. DENR relied on the results 

of the CMAQ modeling in determining the reasonable progress achieved by South Dakota, 

surrounding states, and federal regulations in South Dakota’s Class I areas. DENR originally 

used the modeling results from “Plan02d” to calculate its reasonable progress for the 20% most 

impaired days and to show no degradation on the 20% least impaired days. WRAP discovered an 

error in the modeling runs for some of the Class I area, including the Badlands National Park 

which resulted in a “Plan02d_rev” modeling run. The corrected version, “Plan02d_rev” was used 

in the final results in Table 7-1 and Figure 7-1. 

Table 7-1 provides a summary of WRAP’s modeling results and compares the results to the 

deciview level needed to achieve the 2018 uniform rate of progress for the 20% most impaired 

days and determine if there is any degradation in the 20% least impaired days in South Dakota’s 

Class I areas. The modeling results indicate the 2018 uniform rate of progress goal for the 20% 
106 

most impaired days will not be achieved; but there will be no degradation of the 20% least 

impaired days. 

Table 7-1– 2018 Reasonable Progress Summary for South Dakota’s Class I Areas 

(a) 20% Most Impaired Days 

Class I Uniform Reasonable Uniform Progress 

Area Baseline 1 Progress 2 Progress 3 Achieved 

Badlands 17.14 deciview 15.02 deciview 16.30 deciview 38% 

Wind Cave 15.84 deciview 13.94 deciview 15.28 deciview 33% 

(b) 20% Least Impaired Days 

Class I 

Area Baseline 1 Reasonable Progress 3 Degradation? 

Badlands 6.91 deciview 6.64 deciview No 

Wind Cave 5.16 deciview 5.02 deciview No 

1

 – Baseline values derived from Table 3-7; 

2

 – Uniform progress derived from Figure 3-5; and 

3

 – Reasonable progress derived from WRAP’s modeling results. 

7.3 Key Pollutants Contributing to Visibility Impairment 

As indicated by the 2018 visibility projections using CMAQ modeling, the Class I areas in South 

Dakota are projected to not meet the uniform rate of progress goal for 2018 for the 20% most 

impaired days. The CMAQ modeling is conservative in several respects. The CMAQ modeling 

does not include the BART emissions limits for Otter Tail Power Company’s Big Stone I 

facility. In addition, the CMAQ modeling includes Big Stone II and NextGen emissions, which 

are two new coal-fired power plants. The Big Stone II facility will no longer be constructed and 

the NextGen facility is on hold. 

In order to determine if there are other contributors to not meeting the reasonable progress goals, 

it is necessary to break down these results to identify individual pollutants. Figures 7-1 provides 

a breakdown of individual pollutant contribution (measured by extinction) by showing the glide 

slope of each pollutant in South Dakota’s Class I area from the baseline to 2018, and 2064, for 

the 20% most impaired days. Below each figure is a table that shows the 2018 projections for 

each pollutant, and whether the projection is under the 2018 uniform rate of progress goal and 

the percent improvement toward the 2018 uniform rate of progress goal. 

 

The glide path for the Badlands National Park indicates the air pollutants not achieving the 

necessary levels for the 2018 uniform progress goal to be achieved are organic carbon mass, 

ammonia sulfate, ammonia nitrate, and coarse mass. However, ammonia nitrate and coarse mass 

are very close to the 2018 goal. Organic carbon mass and ammonia sulfate appear to be the 

pollutants of most concern in reaching the 2018 goal. 

The glide path for the Wind Cave National Park indicates the air pollutants not achieving the 

necessary levels for the 2018 uniform progress goal to be achieved are organic carbon mass, 
107 

ammonia sulfate, and ammonia nitrates. At the Wind Cave National Park, it appears organic 

carbon mass and ammonia sulfate are the greatest concern since the extinction value for both are 

the furthest from where they need to be to achieve the uniform rate of progress goal for 2018. 

Next, DENR reviewed WRAP’s attribution analysis to determine the major contributors of 

ammonia sulfate, organic carbon mass, and ammonia nitrate in South Dakota’s two Class I areas. 

For the Badlands and Wind Cave National Parks, the major contributors of ammonia sulfate are 

from sources not in South Dakota. South Dakota’s ammonia sulfate contribution for 2002 and 

2018 is minimal at both national parks at approximately 0.04 micrograms per cubic meter. South 

Dakota’s contribution represents 3% of the ammonia sulfate concentrations for 2018 at both 

national parks. Of the 3%, approximately 1.5% is generated from point sources and 1.5% is 

generated from mobile and other sources. 

The major contributor of organic carbon mass in both national parks is natural fires with point 

source contributions being minimal. Organic carbon mass emissions from natural and prescribed 

fires will be evaluated as part of a smoke management plan which is part of DENR’s long term 

strategy. 
108 

Figure 7-1 – Glide Slope by Pollutant for 20% Worst Visibility Days (Extinction) 1

(a) Badlands National Park 

(WRAP TSS – http://vista.cira.colostate.edu/tss/) 

 (b) Wind Cave National Park 

(WRAP TSS – http://vista.cira.colostate.edu/tss/)

1

 – “NO3” means nitrates, “SO4” means sulfates, “OMC” means organic mass carbon, “EC” means 

elemental carbon, and “CM” means coarse mass. 
109 

Ammonia nitrate was only a concern for the Wind Cave National Park since it was on the glide 

path at the Badlands National Park. The major contributors to ammonia nitrate at the Wind Cave 

National Park are Canada followed by Wyoming, Outside the Domain, and South Dakota. South 

Dakota’s ammonia nitrate contribution for 2002 and 2018 is approximately 0.135 and 0.105 

micrograms per cubic meter, respectively. South Dakota’s contribution represents 10% of the 

ammonia nitrate concentration for 2018 at the Wind Cave National Park. Of the 10%, 

approximately 4% is generated from point sources and 6% is generated from mobile and other 

sources. 

South Dakota’s contribution of ammonia sulfate, organic carbon mass, and ammonia nitrate 

concentrations is approximately 1.5% for ammonia sulfate, minimal for organic carbon mass, 

and 4% for ammonia nitrate. Therefore, minimal gain would be encountered from reduction in 

sulfur dioxide, organic carbon mass, and nitrogen oxide emissions from point sources within 

South Dakota. 

7.4 Four Factor Analysis 

In accordance with 40 CFR § 51.308(d)(1)(ii), if the state establishes a reasonable progress goal 

that provides for a slower rate of improvement in visibility than the rate that would be needed to 

attain natural conditions by 2064, the state must demonstrate based on the four factor analysis 

that the rate of progress for the state’s implementation plan to attain natural conditions by 2064 is 

not reasonable; and the progress goal adopted by the state is reasonable. DENR looked at the air 

pollutants being emitted from point sources that were not meeting the glide path for each 

national park. Based on Figure 7-1(a), the air pollutant not meeting the glide path at the Badlands 

National Park is ammonia sulfate and organic carbon mass. Based on Figure 7-1(b), the air 

pollutant not meeting the glide path at the Wind Cave National Park is ammonia sulfate, organic 

carbon mass, and ammonia nitrate. 

In accordance with 40 CFR § 51.308(d)(1)(i)(A), in establishing the reasonable progress goals 

for each mandatory Class I federal area within the state the state must consider the costs of 

compliance, the time necessary for compliance, the energy and non-air quality environmental 

impacts of compliance, and the remaining useful life of any potential affected sources. This 

consideration is also known as the four factor analysis. The four factor analysis must also 

include a demonstration showing how these factors were taken into consideration in selecting the 

goal. 

There are three facilities in the Rapid City area which EPA indicates require a four factor 

analysis and they are: 1) GCC Dacotah; 2) Black Hills Corporation (Ben French); and 3) Pete 

Lien and Sons, Inc. The four factor analysis will be conducted for sulfur dioxide and nitrogen 

oxide. 
110 

7.4.1 Four Factor Analysis – GCC Dacotah 

WRAP conducted a four factor analysis for GCC Dacotah’s two wet kilns at DENR’s request 

and finalized the document on May 9, 2009 (see Appendix F). After reviewing the calculations 

in Table 4-2 of the document, DENR determined some of the cost effectiveness values for GCC 

Dacotah are incorrect. Table 7-2 provides a corrected version of the cost effectiveness of the 

feasible control options using the emission reduction listed in the document. 

WRAP’s analysis did not include the analysis of a selective non-catalytic reduction (SNCR) 

system because at the time, SNCR were not a proven technology for wet kilns at Portland cement 

plants. EPA commented after the analysis was completed that the review should include a SNCR 

because the SNCR is being used a wet kilns in Europe and at the Ash Grove Cement plant in 

Midlothian, Texas. Although DENR does not agree that one plant in the Nation operating a 

SNCR on a wet kiln for several months constitute the system is capable of using a SNCR, DENR 

agreed to conduct a four factor analysis for SNCRs. DENR used EPA’s November 2007 

“Alternative Control Techniques Document Update – NOx Emissions from New Cement Kilns”, 

EPA-453/R-07-006 to estimate the cost of a SNCR system even though this document was 

developed for the review of dry kilns and not wet kiln. 

The “Capital Cost ($1,000)” column represents the capital investment for purchasing the control 

equipment. The “Annual Cost ($1,000)” is the amortized cost of the capital investment plus the 

annual cost to operate the control equipment. WRAP based the amortized cost of the capital 

investment on the control device and/or wet kiln operating 30 years and a 7% interest rate. 

EPA’s cost numbers for a SNCR system was based on 2005 dollars. WRAP’s cost numbers 

were based on 2007 dollars. Therefore, EPA’s 2005 cost numbers were updated to 2007 cost 

numbers by using a 3% annual inflationary rate. The “Cost per Ton” column is based on the 

“Annual Cost” divided by the “Reductions”.
111 

Table 7-2– Four Factor Analysis for GCC Dacotah 

Control Capital Annual Cost per Ton 

Control 2002 Efficiency Reductions Cost Cost Range 

Pollutant Option tpy % % tpy tpy ($1000) ($1000) $/ton $/ton 

Wet Kiln #4 

NOx LNB 

(indirect) 

707 30 40 212 283 $526 $129 $608 $456 

 LNB 

(direct) 

707 - 40 283 $1873 $331 - $1,170 

 Biosolids 

Injection 

707 - 23 163 - - 1 1

 CemStar 707 20 60 141 424 $1,599 $299 $2,121 $705 

 Mid-Kiln 707 20 50 141 354 $2,748 -$315 22

LoTOx TM 707 80 90 566 636 - - 1 1

 SCR 707 80 566 $14,813 $4,137 $7,309 

 SNCR 707 30 40 212 283 - $878 3

 $4,142 $3,102 

SO2 Wet FGD 26 90 99 23 26 $9,133 $1,370 $59,565 $52,692 

Wet Kiln #5 

NOx LNB 

(indirect) 

388 30 40 116 155 $526 $129 $1,112 $832 

 LNB 

(direct) 

388 40 - 155 $1873 $331 - $2,135 

 Biosolids 

Injection 

388 23 - 89 - - 1 1

 CemStar 388 20 60 78 233 1599 299 $3,833 $1,283 

 Mid-Kiln 388 20 50 78 194 $2,748 -$315 22

LoTOx TM 388 80 90 310 349 - - 1 1

 SNCR 388 30 40 116 155 - $878 3

 $7,569 $5,665 

 SCR 388 80 310 $14,813 $4,137 $13,345 

SO2 Wet FGD 431 90 99 388 427 $9,133 $1,370 $3,531 $3,208 

1

 – The document did not list a cost per ton because they did not identify any capital or annual costs; 

2

 – DENR did not list a cost per ton because the annual cost was a negative number; and 

3

 – EPA’s November 2007 update indicates the average annualized cost of an SNCR to an SCR is 

approximately 1/5 the cost. (Average annualized cost of facility numbers 1, 2, 3, 4, 5, 6, 18, 19, 20, 

and 31, divided by average annualized cost of facility numbers 36, 37, 40, 43, and 46). Using this 

ratio, WRAP’s estimated annualized cost of $4,137,000, and the inflationary rate, the annualized cost 

is estimated to be $878,000 ($4,137,000 x 0.2 x 1.0609 = $878,000). 

Based on the cost per ton estimates, DENR determined a wet flue gas desulfurization unit for 

controlling sulfur dioxide emissions from Wet Kiln #4 and a selective catalytic reduction system 

for controlling nitrogen oxide emissions from Wet Kiln #5 is not cost effective. DENR looked at 

a biosolids injection system and determined a cheap supply of biosolids was not available in 

Rapid City and shipping biosolids to GCC Dacotah would make this option economically 

infeasible especially when looking at only a 23 percent reduction in nitrogen oxide emissions. 

Based on DENR’s research, the CemStar and LoTOx TM options have not been demonstrated to 
112 

work for wet cement kilns and the low-NOx burners will not work since the wet kilns are direct 

fired. Therefore, DENR does not believe these options are a viable option. That leaves the MidKiln and SNCR as a viable option for controlling nitrogen oxide emissions from both wet kilns, a 

selective catalytic reduction system for controlling nitrogen oxide emissions from Wet Kiln #4, 

no viable options for controlling sulfur dioxide emissions from Wet Kiln #4, and a wet flue gas 

desulfurization system for controlling sulfur dioxide emissions from Wet Kiln #5. 

The cost per ton analysis is based on calendar year 2002 air emissions for the two wet kilns 

which operated on average approximately 8,282 hours per year. In the last five years, the two 

wet kiln have operated an average of 4,160 hours per year with the last two years not operating. 

To determine if these control options are still cost effective if the two wet kilns are only operated 

4,160 hours per year, DENR calculated the cost per ton for those controls that are viable for each 

wet kiln and pollutant. The results may be viewed in Table 7-3. 

Table 7-3– Four Factor Analysis for GCC Dacotah at 4,160 Hours per Year 

Control Capital Annual Cost per Ton 

Control Annual Efficiency Reductions Cost Cost Range 

Pollutant Option tpy % % tpy tpy ($1000) ($1000) $/ton $/ton 

Wet Kiln #4 

SO2 Wet FGD 14 90 99 13 14 $9,133 $1,370 $105,385 $97,857

NOx SCR 370 - 80 - 296 $14,813 $4,137 - $13,976

 SNCR 370 30 40 111 148 - $878 7,910 5,932 

Wet Kiln #5 

SO2 Wet FGD 208 90 99 187 206 $9,133 $1,370 $7,326 $6,650 

NOx SCR 187 - 80 - 150 $14,813 $4,137 - $27,580

 SNCR 208 30 40 62 83 - $878 14,161 10,578 

Based on operating approximately 50% of the time the wet kilns operated in 2002, the wet flue 

gas desulfurization system for Wet Kiln #5 and the SNCR for Wet Kiln #4 are on the border of 

being a viable option. 

DENR modeled GCC Dacotah’s two wet kilns to determine if the emissions reasonably 

contribute to visibility impairment in the Badlands and Wind Cave national Park. The modeling 

analysis is based on 2002 actual emissions. The modeling report is located in Appendix G and a 

summary of the modeling results is displayed in Table 7-4. The modeling results represent the 8th

highest reading (deciviews) per year. 

Table 7-4– Visibility Impacts from GCC Dacotah (8th Highest) 

Year Badlands Wind Cave 

2002 0.32 deciviews 0.36 deciviews 

2006 0.32 deciviews 0.36 deciviews 

2007 0.31 deciviews 0.46 deciviews 

Based on the modeling results, the current air emissions from GCC Dacotah’s wet kilns do not 

reasonably contribute to visibility impairment in the Badlands and Wind Cave National Parks. 
113 

DENR believes the cost of reductions is not reasonable for either wet kiln when considering 

GCC Dacotah’s visibility impact and the remaining useful life used in the analysis is suspect 

when considering GCC Dacotah has not operated the two wet kilns in the last two years. In 

addition, EPA promulgated new standards on September 9, 2010, for Portland Cement 

Manufacturing (Federal Register Volume 75, #174, page 54970) and DENR is unsure what 

impacts that will have on the useful life of the wet kiln(s). 

7.4.2 Four Factor Analysis – Black Hills Corporation (Ben French) 

WRAP conducted a four factor analysis for the 25 megawatt subbituminous coal-fired electric 

power plant at Black Hills Corporation’s Ben French facility and finalized the document on May 

9, 2009 (see Appendix F). After reviewing the calculations in Table 4-2 of the document, DENR 

determined that some of the cost effectiveness values for Black Hills Corporation are incorrect. 

Table 7-5 provides a corrected version of the cost effectiveness of the feasible control options 

using the emission reduction listed in the document. 

The “Capital Cost ($1,000)” column represents the capital investment for purchasing the control 

equipment. The “Annual Cost ($1,000)” is the amortized cost of the capital investment plus the 

annual cost to operate the control equipment. WRAP based the amortized cost of the capital 

investment on the control device and/or the coal fired electric power plant operating 30 years and 

a 7% interest rate. The “Cost per Ton” column is based on the “Annual Cost” divided by the 

“Reductions”. 

Table 7-1– Four Factor Analysis for Black Hills Corporation Based on 30 Year Life 

Control Capital Annual Cost per Ton 

Control 2002 Efficiency Reductions Cost Cost Range 

Pollutant Option tpy % % tpy tpy ($1000) ($1000) $/ton $/ton 

NOx LNB 907 30 75 272 680 $1,250 $195 $717 $287 

 LNB 

w/OFA 

907 50 65 454 590 $1,780 $298 $656 $505 

 SNCR 907 30 75 272 680 $1,290 $770 $2,831 $1,132 

 SCR 907 40 90 363 816 $3,000 $754 $2,077 $924 

 $4,250 $1,068 $2,942 $1,309 

SO2 Dry 

Sorbent 

Injection 

785 10 40 79 314 $4,300 $1,700 $21,519 $5,414 

 Spray 

Dryer 

Absorber 

785 90 707 $11,600 $2,670 $3,777 

 Wet FGD 785 90 707 $14,600 $2,760 $3,904 

It appears the WRAP analysis is usable in a general sense. However, Black Hills Corporation 

identified the WRAP report as highly generalized without consideration of physical site 

constraints and expected life of the plant. According to Black Hills Corporation, the expected life 
114 

of the Ben French facility is 10 years with current regulations. This may change as EPA’s 

regulations change. 

DENR conducted a cost per ton analysis based on operating for 10 years instead of 30 years as 

assumed by WRAP. DENR assumed the difference between the amortized cost of the capital 

investment and the annual cost is the annual operation and maintenance cost. Table 7-6 provides 

the results for this analysis. 

Table 7-2– Four Factor Analysis for Black Hills Corporation Based on 10 Year Life 

Control Capital Annual Cost per Ton 

Control 2002 Efficiency Reductions Cost Cost Range 

Pollutant Option tpy % % tpy tpy ($1000) ($1000) $/ton $/ton 

NOx LNB 907 30 75 272 680 $1,250 $272 $1,000 $400 

 LNB 

w/OFA 

907 50 65 454 590 $1,780 $408 $899 $692 

 SNCR 907 30 75 272 680 $1,290 $850 $3,125 $1,250 

 SCR 907 40 90 363 816 $3,000 $939 $2,587 $1,151 

 $4,250 $1,331 $3,667 $1,631 

SO2 Dry 

Sorbent 

Injection 

785 10 40 79 314 $4,300 $1,966 $24,886 $6,261 

 Spray 

Dryer 

Absorber 

785 90 707 $11,600 $3,387 $4,791 

 Wet FGD 785 90 707 $14,600 $3,662 $5,180 

The 10 year evaluation does not change the outcome of the analysis. It appears from both 

evaluations the control equipment would be economical to install based on a cost per ton basis, 

except for the dry sorbent injection system if the anticipated sulfur dioxide emission reductions 

are at the lower level (e.g., 10% efficiency). 

DENR modeled Black Hills Corporation’s coal-fired electric power plant to determine if the 

emissions reasonably contribute to visibility impairment in the Badlands and Wind Cave national 

Park. The modeling analysis is based on 2002 actual emissions. The modeling report is located 

in Appendix H and a summary of the modeling results is displayed in Table 7-7. The modeling 

results represent the 8th highest reading (deciviews) per year. 

Table 7-3– Visibility Impacts from Black Hills Corporation (8th Highest) 

Year Badlands Wind Cave 

2002 0.21 deciviews 0.22 deciviews 

2006 0.23 deciviews 0.23 deciviews 

2007 0.20 deciviews 0.30 deciviews 
115 

Based on the modeling results, the current air emissions from Black Hills Corporation’s coalfired electric power plant does not reasonably contribute to visibility impairment in the Badlands 

and Wind Cave National Parks. 

7.4.3 Four Factor Analysis – Pete Lien and Sons 

 

WRAP did not conduct a four factor analysis on Pete Lien and Sons operations. Pete Lien and 

Sons’ sulfur dioxide emissions are less than one ton per year and will have no impact on 

visibility in any Class I area. In 2002, nitrogen oxide emissions were approximately 272 tons per 

year which has not changed much over the years based on the 2009 nitrogen oxide emissions at 

approximately 287 tons per year. 

On May 12, 2008, Pete Lien and Sons submitted a PSD application for a new preheater-type 

rotary lime kiln and ancillary equipment for its facility in Rapid City. A Best Available Control 

Technology (BACT) analysis for nitrogen oxide was included in the application which indicated 

that post control options such as non-selective catalytic reduction and selective catalytic 

reduction systems were found to be technically infeasible because of temperatures, location of 

injection nozzles, etc. The PSD application also looked at low-NOx burners and determined they 

were also not technically feasible since the rotary kiln is a direct-fired lime kiln. DENR reviewed 

the application at the time and agreed with the conclusion that BACT for a lime rotary kiln was 

good combustion practices. 

DENR reviewed EPA’s RACT/BACT/LAER Clearinghouse (RBLC) to determine if any new 

rotary lime kilns had been permitted since Pete Lien and Sons’ PSD application had been 

submitted. There were three entries. One occurred in Texas, Ohio, and Wisconsin. The one for 

Texas only involved carbon monoxide. In Ohio and Wisconsin, the BACT analysis for nitrogen 

oxide determined that no control technologies were cost effective and good combustion practices 

were considered BACT. 

DENR conducted a modeling analysis to determine if the emissions from Pete Lien and Sons’ 

lime kiln contribute to visibility impairment at the Badlands and Wind Cave National Parks. The 

impact is based on 2002 actual emissions. The modeling report is located in Appendix I and a 

summary of the modeling results is displayed in Table 7-8. The modeling results represent the 8th

highest reading (deciviews) per year. 

Table 7-4– Visibility Impacts from Pete Lien and Sons (8th Highest) 

Year Badlands Wind Cave 

2002 0.05 deciviews 0.06 deciviews 

2006 0.06 deciviews 0.05 deciviews 

2007 0.07 deciviews 0.05 deciviews 

Based on the modeling results, the air emissions from Pete Lien and Sons’s lime kiln does not 

reasonably contribute to visibility impairment in the Badlands and Wind Cave National Parks. 
116 

7.4.4 Four Factor Analysis – Summary 

DENR conducted a four factor analysis on GCC Dacotah’s two wet kilns, Black Hills 

Corporation’s coal-fired electric power plant, and Pete Lien and Sons’ lime kiln. As part of the 

analysis, DENR modeled the actual emissions from these units at each facility to determine if 

they reasonably contribute to visibility impairment in the Badlands and Wind Cave National 

Parks. 

DENR does not plan on requiring controls on these three facilities at this time because the 

visibility modeling indicates the units at these facilities do not reasonably contribute to visibility 

impairment in the national parks. The results of the visibility modeling is substantiated by the 

results of WRAP’s attribution analysis which concluded South Dakota’s contribution to 

ammonia sulfate and ammonia nitrate is minimal. 

DENR will continue to review these three facilities and others facilities as the goal of achieving 

natural visibility conditions in our national parks by 2064 is evaluated on a periodic basis. 

8.0 Long Term Strategy 

In accordance with 40 CFR § 51.308(d)(3), each state must submit a long term strategy to 

address regional haze visibility impairments for each Class I area within the state and for each 

Class I area outside the state which may be affected by emissions from the state. The long term 

strategy must include enforceable emission limitations, compliance schedules, and other 

measures as necessary to achieve the reasonable progress goals established by the state for each 

Class I area. 

The long term strategy must meet the following requirements: 

1. Where the state has emissions that are reasonably anticipated to contribute to visibility 

impairment in any Class I area located in another state or states, the state must consult 

with the other state(s) in order to develop coordinated emission management strategies. 

The state must also consult with any other state having emissions that are reasonably 

anticipated to contribute to visibility impairment in any mandatory Class I area within the 

state; 

2. Where other states cause or contribute to impairment in a Class I area, the state must 

demonstrate that it has included in its implementation plan all measures necessary to 

obtain its share of the emission reductions needed to meet the progress goal for the area. 

If the state has participated in a regional planning process, the state must ensure it has 

included all measures needed to achieve its apportionment of emission reduction 

obligations agreed upon through that process; 

3. The state must document the technical basis, including modeling, monitoring and 

emissions information, on which the state is relying to determine its apportionment of 

emission reduction obligations necessary for achieving reasonable progress in each 

mandatory Class I area it affects. The state may meet this requirement by relying on 

technical analyses developed by the regional planning organization and approved by all 

state participants. The state must identify the baseline emissions inventory on which its 
117 

strategies are based. The baseline emissions inventory year is presumed to be the most 

recent year of the consolidate periodic emissions inventory; 

4. The state must identify all anthropogenic sources of visibility impairment considered by 

the state in developing its long term strategy. The state should consider major and minor 

stationary sources, mobile sources, and area sources; and 

5. The state must consider, at a minimum, the following factors in developing its long term 

strategy: 

a. Emission reductions due to ongoing air pollution control programs, including 

measures to address reasonably attributable visibility impairment; 

b. Measures to mitigate the impacts of construction activities; 

c. Emissions limitations and schedules for compliance to achieve the reasonable 

progress goal; 

d. Source retirement and replacement schedules; 

e. Smoke management techniques for agricultural and forestry management purposes 

including plans as currently exist within the state for these purposes; 

f. Enforceability of emissions limitations and control measures; and 

g. The anticipated net effect on visibility due to projected changes in point, area, and 

mobile source emissions over the period addressed by the long-term strategy. 

8.1 Class I Areas in Other States Impacted by South Dakota 

In accordance with 40 CFR § 51.308(d)(3)(i), the long term strategy for each state that causes or 

contributes to impairment in a Class I area is required to demonstrate that it has included in its 

State Implementation Plan all measures necessary to obtain its share of the emission reductions 

needed to meet the progress goals for the Class I area. If the state has participated in a regional 

planning process, the state must ensure it has included all measures needed to achieve its 

apportionment of emission reduction obligations agreed upon through that process. 

DENR participated in WRAP and worked with other states that are not members of WRAP in 

developing its State Implementation Plan. Otter Tail Power Company’s Big Stone I facility is 

the only source in South Dakota that is reasonable anticipated to contribute to visibility 

impairment at the Badlands National Park in South Dakota; Theodore National Park in North 

Dakota; Boundary Waters and Voyageurs Class I areas in northern Minnesota and the Isle 

Royale federal Class I area in Michigan. Otter Tail Power Company developed a case-by-case 

BART analysis which DENR reviewed to establish the BART emission limits for Big Stone I. 

The case-by-case BART analysis and DENR’s review was submitted to the appropriate states for 

their comments. 

DENR will establish the BART procedures in the Administrative Rules of South Dakota that are 

equivalent to federal regulation in 40 CFR Part 51, adopt the BART emission limits applicable to 

BART-eligible coal fired power plants (which includes Big Stone I) in the rule, and adopt the 

BART emission limits in an air quality construction permit and eventually in Otter Tail Power 

Company’s Title V air quality operating permit for the Big Stone I facility. DENR believes the 

BART requirements represents South Dakota’s emission reductions for those Class I areas 

impacted by Big Stone I. 
118 

8.2 States Impacting South Dakota’s Class I Areas 

In accordance with 40 CFR § 51.308(d)(3)(ii), the long term strategy for each state that causes or 

contributes to impairment in a Class I area is required to demonstrate that it has included in its 

State Implementation Plan all measures necessary to obtain its share of the emission reductions 

needed to meet the progress goals for the Class I area. If the state has participated in a regional 

planning process, the state must ensure it has included all measures needed to achieve its 

apportionment of emission reduction obligations agreed upon through that process. 

DENR has worked with states contributing to visibility impairment in South Dakota’s Class I 

areas through WRAP and also with those states that are not part of WRAP. DENR believes at 

this time that the controls they are adopting under their BART analysis, State Implementation 

Plan, and other measures states are taking will minimize their impacts on South Dakota’s Class I 

areas. Based on WRAP’s emission inventory for 2002 and 2018, these control measures will 

reduce sulfur dioxide emissions by 26%, nitrogen oxide emissions by 29%, organic carbon mass 

by 6% and elemental carbon by 31% (derived from Table 5-6 and 5-7). 

8.3 Technical Basis for Modeling, Monitoring and Emissions Information 

In accordance with 40 CFR § 51.308(d)(3)(iii), as part of the long term strategy, each state is 

required to document the technical basis, including modeling, monitoring and emissions 

information, on which the state is relying to determine its apportionment of emission reduction 

obligations necessary for achieving reasonable progress in each mandatory Class I area it affects. 

The state may meet this requirement by relying on technical analyses developed by the regional 

planning organization and approved by all state participants. The state must identify the baseline 

emissions inventory on which its strategies are based. The baseline emissions inventory year is 

presumed to be the most recent year of the consolidated periodic emissions inventory. 

South Dakota is a member of WRAP and relied on the modeling, monitoring and emissions 

information and technical analyses developed by WRAP to accomplish this requirement. DENR 

relied on the use of CALPUFF for single source BART screening modeling and WRAP’s 

CMAQ and Particulate Matter Source Apportionment Technology modeling in its cumulative 

impact analyses. The BART modeling conformed to the requirements of the BART guidelines. 

The WRAP CMAQ and Particulate Matter Source Apportionment Technology modeling 

conformed with EPA’s modeling guidelines. On the monitoring side, DENR used the 

IMPROVE monitoring data available on the IMPROVE website for its Class I areas. 

DENR used WRAP’s Plan02d emissions inventory for the baseline emissions year 2002 which 

reflects a composite interpretation of emissions for the base 2000-2004 period; and WRAP’s 

CMAQ PRP18b (Preliminary Reasonable Progress 2018 Scenario A) emissions inventory which 

reflects projected year 2018 emissions. The projected year 2018 emissions represents base 

period emissions projected to 2018, accounting for estimates of the effect of BART controls and 

assuming other growth and control factors. 

Currently, WRAP is maintaining this documentation at the following website: 
119 

http://vista.cira.colostate.edu/TSS/Results/HazePlanning.aspx 

DENR will continue to work with WRAP in its effort to update emission inventories and run 

models to determine if South Dakota is meeting its reasonable progress and long term strategy 

goals. 

8.4 Identification of Anthropogenic Sources of Visibility Impairment 

In accordance with 40 CFR § 51.308(d)(3)(iv), as part of the long term strategy, each state must 

identify all anthropogenic sources of visibility impairment considered by the state in developing 

its long term strategy. The state should consider major and minor stationary sources, mobile 

sources and area sources. 

DENR worked through WRAP and through a BART analysis to identify major and minor 

stationary sources. WRAP was also used to consider mobile and area source emissions. One 

item that does appear to be the greatest contributor is activities contributing to organic mass 

carbon emissions such as wild fires and prescribed fires. 

8.5 Factors in Developing Long Term Strategy 

In accordance with 40 CFR § 51.308(d)(3)(v), states must consider, at a minimum, the following 

factors in developing its long term strategy: 

1. Emission reductions due to ongoing air pollution control programs, including measures to 

address reasonably attributable visibility impairment; 

2. Measures to mitigate the impacts of construction activities; 

3. Emissions limitations and schedules for compliance to achieve the reasonable progress 

goal; 

4. Source retirement and replacement schedules; 

5. Smoke management techniques for agriculture and forestry management purposes 

including plans as currently exist within the state for these purposes; 

6. Enforceability of emissions limitations and control measures; and 

7. The anticipated net effect on visibility due to projected changes in point, area, and mobile 

source emissions over the period addressed by the long-term strategy. 

It is expected that for some areas of the country, such as parts of the eastern United States, 

emission reductions achieved for the acid rain program and for meeting the PM2.5 NAAQS, will 

lead to substantial improvements in visibility as well. Subsection 1 in this section makes clear 

that states must take these other emission reductions into account in developing their long-term 

strategies for regional haze. 

8.5.1 Emission Reductions from Ongoing Air Pollution Control Programs 

In accordance with 40 CFR § 51.308(d)(3)(v)(A), an assessment of emission reductions due to 

ongoing air pollution control programs is required. Existing air pollution control programs in 
120 

place which assist in reducing air emissions and help achieve reasonable progress toward the 

national visibility goal include the following South Dakota air quality rules under ARSD § 74:36 

– Air Pollution Control Program are listed below: 

1. ARSD § 74:36:01:05 – Applicable requirements of Clean Air Act defined: Subsection 

(12) states “Any national ambient air quality standard or increment or visibility 

requirement under Part C of Title I of the Clean Air Act, but only as it would apply to 

temporary sources permitted pursuant to § 504(e) of the Clean Air Act”; 

2. ARSD § 74:36:01:10 – Modification defined: Subsection (3) states “The change requires 

or changes a case-by-case determination of an emission limit or other standard, a 

source-specific determination for temporary sources of ambient impacts, or a visibility or 

increment analysis”; 

3. ARSD § 74:36:02:01 – Air quality goals: Subsection (3) states one of the goals is 

“optimization of visibility”; 

4. ARSD § 74:36:04 – Operating permits for minor sources and § 74:36:05 – Operating 

permits for Part 70 sources: The permits issued under these chapters require sources to 

meet all applicable emission limits, demonstrate compliance, monitoring, recordkeeping 

and reporting requirements; 

5. ARSD §§ 74:36:06 – Regulated Air Pollutant Emissions; 74:36:07 – New Source 

Performance Standards; 74:36:08 – National Emission Standards for Hazardous Air 

Pollutants, and ARSD § 74:36:12 – Control of Visible Emissions: These chapter restricts 

air emissions from regulated entities that cause visibility impairment and prohibits certain 

open burning practices such as open burning waste oil, rubber, waste tires, asphalt 

shingles, railroad ties, etc.; 

6. ARSD § 74:36:09 – Prevention of Significant Deterioration: This chapter requires a 

visibility analysis to prevent sources subject to these requirements from contributing to 

visibility impairment in Class I Areas; 

7. ARSD § 74:36:10 – New Source Review: This chapter requires a visibility analysis to 

prevent sources subject to these requirements from contributing to visibility impairment 

in Class I Areas; and 

8. ARSD § 74:36:18 – Regulations for State Facilities in the Rapid City Area: This chapter 

restricts visible emissions from fugitive sources. 

The chapters and sections listed above are included in South Dakota’s State Implementation 

Plan. 

In addition, EPA implemented a reasonably attributable visibility impact (RAVI) protection 

program in 1987 with a Federal Implementation Plan (FIP) for South Dakota to meet the general 

visibility plan requirements and long-term strategies of 40 CFR §§ 51.302 and 51.306, 

respectively. The existing federal RAVI program is compatible with the regional haze program 

and no revisions are needed at this time. DENR will coordinate with EPA to conduct joint 

periodic reviews and revisions of the long-term RAVI strategy as required by 40 CFR § 

51.306(c). DENR may consider incorporation of the RAVI program into South Dakota’s State 

Implementation Plan in the future. 
121 

8.5.2 Measures to Mitigate Impacts of Construction Activities 

In accordance with 40 CFR § 51.308(d)(3)(v)(B), states are required to consider measures to 

mitigate the impacts of construction activities. States, for example, should include these 

activities in emission inventories used for long-term strategy development. South Dakota 

regulates fugitive emissions by rule in ARSD § 74:36:18 – Regulations for State Facilities in the 

Rapid City Area. This chapter restricts visible emissions from fugitive sources in the Rapid City 

area. 

In addition, as part of South Dakota’s State Implementation Plan, DENR is proposing rules that 

will require new major sources and modifications to major sources to conduct a visibility 

analysis. A new major source or modification to a major source will have to determine what 

controls will be necessary to maintain emissions at a level that will not cause visible emission 

equal to or greater than 0.5 deciviews at a Class I area. The new major source or modification to 

a major source will be required to install the control equipment, establish emission limits, 

recordkeeping requirements, and reporting requirements. 

8.5.3 Emission Limitations and Schedules to Achieve Reasonable Progress Goals 

In accordance with 40 CFR § 51.308(d)(3)(v)(C), states are required to consider air emissions 

limitations and schedules for compliance to achieve the reasonable progress goal in developing 

its long terms strategy. This requirement impacts South Dakota’s only BART-eligible source 

(Otter Tail Power Company’s Big Stone I). The BART requirements, BART emission limits, 

and compliance deadlines for Otter Tail Power Company’s Big Stone I facility will be 

established in South Dakota’s rules. The evaluation of non-BART sources as part of the long 

term strategy will be reviewed in the next planning period since WRAP’s attribution analysis 

indicates South Dakota’s sources have minimal impact on our Class I areas. 

8.5.4 Retirement and Replacement Schedules 

In accordance with 40 CFR § 51.308(d)(3)(v)(D), states are required to consider any source 

retirement and replacement schedules in developing its long term strategy, particularly, where 

these schedules would have a significant impact on regional emission loadings and on a state’s 

ability to achieve reasonable progress. 

DENR is not aware of any anticipated major source retirements or replacements that would have 

a significant impact on regional emissions loadings and on a state’s ability to achieve reasonable 

progress. The replacement of existing units at facilities will be managed in conformance with 

the state’s existing State Implementation Plan. 

The 2018 modeling conducted by WRAP included two new coal-fired electric power plants and 

one oil refinery to be located in South Dakota. Although the PSD permit has been issued for one 

of the new coal-fired electric power plants, the applicant notified DENR that it is no longer going 

to build the plant. The second coal-fired power electric power plant requested that DENR put its 

application on hold until further notice. Therefore, the next modeling exercise for determining 
122 

visibility in 2018 will need to be adjusted to reflect this development and the current modeling 

results for 2018 are probably conservative. 

8.5.5 Smoke Management 

In accordance with 40 CFR § 51.308(d)(3)(v)(E), states are required to consider smoke 

management techniques for agriculture and forestry management purposes including plans as 

currently exist within the state for these purposes in developing its long term strategy. As part of 

the long term strategy, DENR will investigate the impacts a smoke management plan for wild 

fires and prescribed burns will have on the 20% most impaired days within the first planning 

period of 2013. 

Currently very little agricultural burning takes place in South Dakota and the majority of 

agricultural land lies in the eastern two-thirds of the state, while both Class I areas are in the 

western third. In addition, DENR did not observe any of the 20% most impaired days that were 

attributed to agricultural burning in the eastern half of South Dakota. Therefore, agricultural 

burning does not appear to have much of an impact at our Class I areas. However, there is some 

burning of grass in and around the Class I areas which will be investigated to determine if this 

practice warrants being covered under a smoke management plan. 

Over the years the National Park Service and U.S. Forest Service have conducted planned 

prescribed burns on federal lands at both Class I areas, which have affected the air quality in both 

parks. The last prescribed burn at the Wind Cave National Park is one example in which the 

smoke from the fire had a negative impact on DENR’s air monitoring equipment. DENR is 

currently waiting to review the IMPROVE data for those days to see what kind of impact the fire 

had on the organic carbon mass concentration and to some extent the ammonia sulfide and 

ammonia nitrate levels. In addition, DENR has observed there is evidence that large fires 

contribute to the 20% most impaired days during the baseline period. 

DENR has taken the initial steps in developing a smoke management plan by contacting those 

groups that DENR believes would need to be involved, including the South Dakota Department 

of Agriculture, National Park Service and U.S. Forest Service, among others. The response from 

these agencies has been positive and all have offered to assist in developing a smoke 

management plan for South Dakota. More recently, DENR has been in contact with the South 

Dakota Division of Wildland Fire Suppression, which maintains a prescribed fire database of 

fires throughout South Dakota and along our borders in neighboring states. DENR will use this 

database to track fires and compare the fire data (e.g., size of fire, material being burned, 

distance from the Class I areas, dates) to the IMPROVE data from our Class I areas to see what 

the impacts are to the visibility. 

It is DENR’s intention to investigate these prescribed burns as well as other wildfires and 

planned prescribed burns to determine at what level (e.g., size of burn, distance from the Class I 

areas, combustible material) should a wildfire or prescribed fire be included in the smoke 

management plan and what best management practices can be used to minimize their impacts on 

the 20% most impaired days in the Class I areas. The results of this analysis will be adopted in 

the Regional Haze State Implementation Plan as part of our long term strategy. DENR will work 
123 

with the federal land managers, other state agencies, and local governments during the 

development and implementation of the smoke management plan. 

8.5.6 Enforceable Emission Limits and Control Measures 

In accordance with 40 CFR § 51.308(d)(3)(v)(F), states are required to consider the 

enforceability of emission limits and control measures in developing its long term strategy. In 

developing enforceable emissions limits and control measures, the state should ensure they are 

written in a way that EPA and citizens may enforce them as a practical matter. 

The BART requirements, including the BART emission limits for Big Stone I, will be 

established in South Dakota’s rules and adopted into South Dakota’s State Implementation Plan. 

This will allow states, the public, and any interested party to comment on the rules to ensure the 

BART requirements are enforceable in a practical matter. In addition, the BART emission limits 

and specific control measures that will be established in Otter Tail Power Company’s Big Stone I 

air quality permit will be open to states, the public, and any interested party for comment and 

ensure the BART permit requirements are enforceable in a practical matter. 

Currently, DENR developed a Title V air quality permit program which is required prior to 

construction for new sources and modifications to existing sources. DENR established a 

construction permit program that separates the construction permit from the Title V air quality 

permit program. The construction permit program was submitted to EPA to be included in South 

Dakota’s State Implementation Plan. The BART emission limits and control measures will be 

included in a construction permit and eventually in the Title V air quality permit. 

 

DENR is also establishing requirements under the Regional Haze Program to require new major 

sources and modifications to major sources to demonstrate through a visibility analysis that the 

new major source or modification to a major source will not contribute to visibility impairment 

in any mandatory Class I area. Contribute to visibility impairment is defined by a change in 

visibility impairment in a mandatory Class I area of 0.5 deciviews or more, based on a 24-hour 

average, above the average natural visibility baseline. A source exceeds the threshold with the 

98th percentile (eighth highest value) of the modeling results based on one year of the three years 

of meteorological data modeled exceeds the 0.5 deciviews. The emission limits and control 

measures used in the visibility analysis are required to be included in the sources permit which 

will include an opportunity for states, the public, and any interested party to comment on to 

ensure the requirements are enforceable in a practical matter. The rules will assist DENR in 

ensuring the sources in South Dakota will not contribute to visibility impairment in any Class I 

area. 

8.5.7 Anticipated Net Effect on Visibility Due to Projected Changes 

In accordance with 40 CFR § 51.308(d)(3)(v)(G), when developing its long term strategy states 

are required to consider the anticipated net effect on visibility due to projected changes in point, 

area, and mobile source emissions over the period addressed by the long term strategy. WRAP 

projected the net effect on visibility from emission reductions and increases by point, area and 

mobile sources throughout the WRAP region through 2018. The first emission projection 
124 

inventory was compiled in 2006. The inventory was revised in 2007 to make preliminary 

evaluations of reasonable progress towards Class I areas visibility goals. The 2007 inventory 

focused on the most significant point and area sources of visibility impairing pollution. This 

effort included updating projections of electric generating units and incorporating known and 

presumed BART emission levels. 

During the spring of 2009, the WRAP once again updated emission inventory projections for 

point and area sources in the WRAP region to give the most current assessment of reasonable 

progress towards visibility goals. Again, the updated projection inventory reflected new 

information about BART determinations and projection of future fossil fuel plants needed to 

achieve 2018 federal electrical generation demands. 

The results of the CMAQ modeling which has already been discussed shows anthropogenic 

emissions sources generally declining across the West through 2018. However, natural sources 

such as wildfires and dust, international sources in Mexico and Canada, global transport of 

emissions and off shore shipping in the Pacific Ocean all appear to offset improvements in 

visibility from controls on manmade sources. In spite of the large number of growing 

uncontrollable sources in the WRAP region, however, South Dakota does see a net visibility 

improvement at the South Dakota Class I areas through 2018. The net effect of all of the 

reductions in the WRAP region, known at the time of the most recent model run is demonstrated 

in the WRAP Class I Summary Tables shown below for each of the Class I areas in South 

Dakota. Table 8-1 provides a summary of the results for each Class I area for the 20% most 

impaired days. 

Table 8-1– CMAQ Modeling Visibility Summary for 20% Most Impaired Days 

(a) Badlands National Park 

RRF Calculations Method: Specific Days (EPA) 

Emissions Scenarios: 2000-04 Baseline (plan02d_rev) and 2018 PRPb (prp18b) 

Monitored Estimated Projected 

Baseline to 

Baseline to 2018 

2018 Baseline to 2018 Change In 

Uniform 2018 Change In Anthropogenic

2000-04 2064 Rate of 2018 Change In Upwind Upwind 

Baseline Natural Progress Visibility Statewide Weighted Weighted 

ConditionsConditions Target Conditions Emissions Emissions 4 Emissions 4

(Mm-1) 1 (Mm-1) 2 (Mm-1) 3 (Mm-1) (tons/%) (%) (%) 

Sulfate 18.85 1.19 13.13 15.61 -8,115 

-36% -30% -30% 

Nitrate 5.85 0.86 4.51 5.23 -26,347 

-18% -27% -37% 

Organic 

Carbon 11.78 4.10 9.68 11.73 -555 -6% -3% -7% 

Elemental 2.59 0.34 2.02 2.13 -2,404 -30% -45% 
125 

RRF Calculations Method: Specific Days (EPA) 

Emissions Scenarios: 2000-04 Baseline (plan02d_rev) and 2018 PRPb (prp18b) 

Monitored Estimated Projected 

Baseline to 

Baseline to 2018 

2018 Baseline to 2018 Change In 

Uniform 2018 Change In Anthropogenic

2000-04 2064 Rate of 2018 Change In Upwind Upwind 

Baseline Natural Progress Visibility Statewide Weighted Weighted 

ConditionsConditions Target Conditions Emissions Emissions 4 Emissions 4

(Mm-1) 1 (Mm-1) 2 (Mm-1) 3 (Mm-1) (tons/%) (%) (%) 

Carbon -51% 

Fine Soil 0.98 0.95 0.97 0.94 1,837 

6% 3% 9% 

Coarse 

Material 5.94 4.04 5.48 Not 

Applicable 5

25,873 

16% 2% 8% 

Sea Salt 0.19 0.19 0.19 Not 

Applicable 5

Not 

Applicable

Not 

Applicable Not Applicable

Total 

Light 

Extinction 

57.18 22.67 45.98 52.73 Not 

Applicable

Not 

Applicable Not Applicable

Deciview 17.14 8.06 15.02 16.32 Not 

Applicable

Not 

Applicable Not Applicable

1

 – Baseline values derived from Table 4.3(b), except for the deciview values. The deciview value 

was derived from Table 3-7; 

2

 – Deciview value derived from Table 3-7; 

3

 – 2018 Uniform Rate of Progress Target for Best 20% Days is not defined. The Deciview value was 

derived from Figure 3-5(a); 

4

 – Results based on Weighted Emissions Potential analysis using the 2000-04 Baseline (plan02d_rev) 

& 2018 PRPb (prp18b) emissions scenarios; and 

5

 – Visibility projections not available due to model performance issues. 
126 

(b) Wind Cave National Park 

RRF Calculations Method: Specific Days (EPA) 

Emissions Scenarios: 2000-04 Baseline (plan02d) and 2018 PRPb (prp18b) 

Monitored Estimated Projected 

Baseline to 

Baseline to 2018 

2018 Baseline to 2018 Change In 

Uniform 2018 Change In Anthropogenic

2000-04 2064 Rate of 2018 Change In Upwind Upwind 

Baseline Natural Progress Visibility Statewide Weighted Weighted 

ConditionsConditions Target Conditions Emissions Emissions 4 Emissions 4

(Mm-1) 1 (Mm-1) 2 (Mm-1) 3 (Mm-1) (tons/%) (%) (%) 

Sulfate 13.32 1.09 9.53 11.33 -8,115 

-36% -21% -22% 

Nitrate 7.07 1.21 5.41 6.12 -26,347 

-18% -24% -30% 

Organic 

Carbon 13.39 4.4 10.77 12.93 -555 -6% -1% -5% 

Elemental 

Carbon 2.96 0.4 2.28 2.32 -2,404 -51% -21% -41% 

Fine Soil 0.86 0.97 0.88 0.93 1,837 

6% 8% 16% 

Coarse 

Material 3.53 3.8 3.59 Not Applicable 5

25,873 

16% 5% 13% 

Sea Salt 0.00 0.03 0.03 Not 

Applicable 5

Not 

Applicable

Not 

Applicable

Not Applicable

Total 

Light 

Extinction 

51.18 21.90 41.71 47.19 

Not 

Applicable

Not 

Applicable

Not Applicable

Deciview 15.84 7.41 13.94 15.12 Not 

Applicable

Not 

Applicable

Not Applicable

1

 – Baseline values derived from Table 4.4(b), except for Deciview. The Deciview value was derived 

from Table 3-7; 

2

 – Deciview value derived from Table 3-7; 

3

 – 2018 Uniform Rate of Progress Target for Best 20% Days is not defined. The Deciview value was 

derived from Figure 3-5(b); 

4

 – Results based on Weighted Emissions Potential analysis using the 2000-04 Baseline (plan02d) & 

2018 PRPb (prp18b) emissions scenarios; and 

5

 – Visibility projections not available due to model performance issues. 

9.0 Monitoring Strategy 

In accordance with 40 CFR § 51.308(d)(4), the State Implementation Plan for the Regional Haze 

Program is required to include a monitoring strategy for measuring, characterizing and reporting 

of regional haze visibility impairment that is representative of all Class I areas within the state. 
127 

The monitoring strategy must be coordinated with the monitoring strategy required in 40 CFR § 

51.305. In accordance with 40 CFR § 51.305, the monitoring strategy must take into account 

current and anticipated visibility monitoring research, the availability of appropriate monitoring 

techniques, and such guidance as provided by EPA. In addition, the monitoring strategy must 

provide for the consideration of available visibility data and must provide a mechanism for its 

use in decisions making. Compliance with this requirement may be met through the 

participation in the IMPROVE network. 

DENR has been and will continue to participate in the IMPROVE network for both of its Class I 

areas. The IMPROVE network currently collects and reports aerosol monitoring data which will 

be used to track long term reasonable progress. Because the long term tracking program with an 

implementation period nominally set for 60 years, the state expects that the IMPROVE network 

will provide data based on the following goals: 

1. Maintain a stable configuration of the individual monitors and sampling sites and stability 

in network operations for the purpose of continuity in tracking reasonable progress 

trends; 

2. Assure sufficient data capture at each site of all visibility-impairing species; 

3. Comply with EPA quality control and assurance requirements; and 

4. Prepare and disseminate periodic reports on IMPROVE network operations. 

DENR is relying on the IMPROVE network to meet these monitoring operation and data 

collection goals, with the fundamental assumption that network data collection operations will 

not change, or if changed, will remain directly comparable to those operated by the IMPROVE 

network during the 2000 to 2004 baseline period. Technical analyses and reasonable progress 

goals in this implementation plan are based on data from these sites. As such, DENR will work 

with EPA and the Federal Land Managers to ensure these monitors continue to operate and any 

changes to the IMPROVE network will not jeopardize the use of the data in the monitoring 

strategy. 

The state of South Dakota depends on the following IMPROVE program-operated monitors at 

the following sites listed in Table 9-1 for tracking reasonable progress: 

Table 9-1– IMPROVE Monitoring Sites at Class I areas in South Dakota 

IMPROVE Monitoring Sites Class I Area 

BAD1 Badlands National Park 

WICA1 Wind Cave National Park 

In accordance with 40 CFR § 51.308(d)(4)(i), DENR will also operate additional non-IMPROVE 

monitors that may be used in assessing if reasonable progress goals in South Dakota’s Class I 

areas are being met. These may include PM2.5 speciation or Federal Reference Methods, and/or 

more portable monitoring systems than operated at an IMPROVE site. This data is collected 

throughout the state but the ambient air quality monitoring sites of particular interest are the ones 

located next to the IMPROVE sites in the Class I areas in South Dakota. The data collected by 

these sites, along with data from the others sites throughout the state are reported to EPA’s AIRS 
128 

database. Table 9-2 provides a summary of what DENR is currently monitoring next to the 

IMPROVE sites in the Class I area in South Dakota. 

Table 9-2– Ambient Air Monitoring Site Parameters Next to IMPROVE Sites 

Monitoring Site Parameter 

Sampling &Analysis 

Method 

Operating 

Schedule 

Badlands National Park 

AQS# 

Sulfur Dioxide Instrumental pulsed 

florescent 

Continuous 

Nitrogen Dioxide Instrumental 

chemiluminescence 

Continuous 

Ozone Instrumental ultra violet Continuous 

PM2.5 Met One BAM – 1020 

Very Sharp Cut Cyclone 

Gravimetric 

Continuous 

PM10 Thermal Anderson Series 

FH62 C14 BETA 

Gravimetric 

Continuous 

Wind Speed Electronic signal Continuous 

Wind Direction Electronic signal Continuous 

Ambient 

Temperature 

Electronic signal Continuous 

Delta 

Temperature 

Electronic signal Continuous 

Ambient Pressure Barometric pressure 

transducer 

Continuous 

Solar Radiation Pyranometer Continuous 

Relative 

Humidity 

Hygroscopic Plastic Film Continuous 

Wind Cave National Park 

AQS# 

Sulfur 

 Dioxide 

Instrumental Pulsed 

Florescent 

Continuous 

Nitrogen Dioxide Instrumental 

Chemiluminescence 

Continuous 

Ozone Instrumental Ultra Violet Continuous 

PM2.5 Met One BAM – 1020 

Very Sharp Cut Cyclone 

Gravimetric 

Continuous 

PM10 Thermal Anderson Series 

FH62 C14 BETA 

Gravimetric 

Continuous 

Wind Speed Electronic signal Continuous 

Wind Direction Electronic signal Continuous

Ambient 

Temperature 

Electronic signal Continuous

Ambient Pressure Barometric Pressure Continuous
129 

Monitoring Site Parameter 

Sampling &Analysis 

Method 

Operating 

Schedule 

Transducer 

Relative 

Humidity 

Hygroscopic Plastic Film Continuous

In accordance with 40 CFR § 51.308(d)(4)(ii), DENR will use data reported by the IMPROVE 

program as part of the regional technical support analysis tools found at the Visibility 

Information Exchange Web System (VIEWS), as well as other analysis tools that are available. 

DENR will participate in the ongoing regional analysis activities to collectively assess and verify 

the progress toward reasonable progress goals, also supporting interstate consultation as the 

regional haze rules are implemented and collaborate with EPA, states, tribes, and federal land 

managers to ensure the continued operation of these technical support analysis tools and systems 

. 

In accordance with 40 CFR § 51.308(d)(4)(iv), DENR will depend on the routine timely 

reporting of haze monitoring data by the IMPROVE program for the reasonable progress 

tracking sites to the EPA air quality data system and VIEWS. DENR will collaborate with EPA, 

states, tribes, and federal land managers to ensure the continued operation of these technical 

support analysis tools and systems. 

In accordance with 40 CFR § 51.308(d)(4)(vi), DENR will track data related to the regional haze 

plan implementation for sources for which the state has regulatory authority and will depend on 

the IMPROVE program and working with states and other organizations to collect and analyze 

efforts and data support systems for monitoring and emissions inventory data, respectively. To 

ensure the availability of data and analyses to report on visibility conditions and progress toward 

Class I area visibility goals, the state of South Dakota will collaborate with EPA, states, tribes, 

and FLMs to ensure the continued operation of the IMPROVE program.

10.0 Consultation Requirements 

10.1 Federal Land Manager Consultation 

In accordance with 40 CFR § 51.308(i)(1), a state is required to provide written notification to 

the federal land managers the title of the official to which the federal land managers of any Class 

I area can submit any recommendations on the implementation of the state’s Regional Haze 

Program. DENR provided the state’s contact to the federal land managers through its 

involvement with WRAP. 

WRAP represents a conglomeration of stakeholders representing federal land managers, 

industry, states, tribes, environmental groups and the general public. Through participation in 

this process, a significant portion of the consultation process with federal land managers and 

other states has been met. In the WRAP process these stakeholders participated in various 

forums to help develop a coordinated emissions inventory and analysis of the impacts sources 

have on regional haze in the west. Coordination and evaluation of monitoring data and modeling 

processes were also overseen by WRAP participants. Through these coordinated technical 

evaluations, a regional haze oriented evaluation of South Dakota's Class I areas was constructed. 
130 

South Dakota has been a participating member of the WRAP since its inception. The WRAP 

completed a long-term strategic plan in 2003. The Strategic Plan provides the overall schedule 

and objectives of the annual work plans and may be revised as appropriate. Among other things, 

the Strategic Plan (1) identifies major products and milestones; (2) serves as an instrument of 

coordination; (3) provides the direction and transparency needed to foster stakeholder 

participation and consensus-based decision making, which are key features of the WRAP 

process; and (4) provides guidance to the individual plans of WRAP forums and committees. 

Much of the WRAP’s effort is focused on regional technical analysis that serves as the basis for 

developing strategies to meet the regional haze rule requirements to demonstrate reasonable 

progress towards natural visibility conditions in Class I areas. This includes the compilation of 

emission inventories, air quality modeling, and ambient monitoring and data analysis. The 

WRAP is committed to using the most recent and scientifically acceptable data and methods. 

The WRAP does not sponsor basic research, but WRAP committees and forums interact with the 

research community to refine and incorporate the best available tools and information pertaining 

to western haze. 

In accordance with 40 CFR § 51.308(i)(2), a state is required to provide the federal land 

managers with an opportunity for consultation, in person and at least 60 days prior to holding 

any public hearing on the state’s regional haze program or revisions to the program. The 

consultation shall include an opportunity to discuss the following: 

1. Assessment of impairment of visibility in any mandatory Class I area; and 

2. Recommendations on the development of the reasonable progress goal and on the 

development and implementation of strategies to address visibility impairment. 

DENR is committed to providing the federal land managers opportunities to provide input as 

South Dakota’ State Implementation Plan for the regional haze program is developed and 

implemented. This includes providing the federal land managers with at least 60 days prior 

notice to any public hearing. On January 15, 2010, DENR fulfilled this obligation and submitted 

South Dakota’s draft Regional Haze Program to the following Federal Land Managers: 

1. Tim Allen, U.S. Fish & Wildlife Service, Lakewood, Colorado; 

2. Trent Wickman, USDA Forest Service, Great Lakes National Forests – Eastern Region; 

3. John Bunyak, National Park Service, Air Resources Division, Lakewood, Colorado; 

4. John Notar, National Park Service, Air Resources Division, Lakewood, Colorado; 

5. Brian Kenner, National Park Service, Badlands National Park; and 

6. Ken Hyde, National Park Service, Wind Cave National Park. 

In addition, DENR took this opportunity to solicit comments from the following: 

1. Laurel Dygowski, EPA Region VIII; 

2. Amy Platt, EPA Region VIII; 

3. Monica Morales, EPA Region VIII; 

4. Catherine Nueschler and Anne Jackson, State of Minnesota; 
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5. Teresa Cooper and Asad Khan, State of Michigan; 

6. Shelley Schneider and Katryna Schaf, State of Nebraska; 

7. Dana Mount and Tom Bachman, State of North Dakota; 

8. Curtis Taipale, State of Colorado; 

9. Dave Klemp, State of Montana; 

10. Tina Anderson, State of Wyoming; 

11. Jim Strain, South Dakota Department of Agriculture; 

12. Gene Nelson, GCC Dacotah, Rapid City, SD; 

13. Tim Rogers, Black Hills Corporation, Rapid City, SD; 

14. Danielle Weibers, Pete Lien and Sons, Rapid City, SD; 

15. Clint Allen, Hills Materials Company, Rapid City, SD; and 

16. Terry Graumann, Otter Tail Power Company, Big Stone I. 

DENR requested comments by March 16, 2010. DENR received comments from the United 

States Department of Agriculture – Forest Service, United States Department of Interior –

National Park Service, Otter Tail Power Company, and the United States Environmental 

Protection Agency (EPA) – Region 8. 

10.1.1 Addressing Federal Land Manager Recommendations 

In accordance with 40 CFR § 51.308(i)(3), in developing any implementation plan or revision, 

the state must include a description of how it addressed any comments provided by federal land 

managers. The comments from the federal land managers, Otter Tail Power Company, and EPA 

and DENR response to those comments may be reviewed in Appendix D. 

 

10.1.2 Continued Consultation with Federal Land Managers 

In accordance with 40 CFR § 51.308(i)(4), DENR must provide procedures for continuing 

consultation between the state and federal land managers on the implementation of the visibility 

protection program including the development and review of implementation plan revisions and 

5-year progress reports and on the implementation of other programs having the potential to 

contribute to impairment of visibility in a Class I area. DENR is committed to working with the 

federal land managers to protect the Class I areas in South Dakota and in neighboring states. 

This will be accomplished with our continued involvement in regional organizations and through 

our contacts with the federal land managers. 

DENR has already involved the federal land managers on other programs that may impact 

visibility in a Class I area through our PSD air quality permit program. Again, DENR has an 

open door policy in which the federal land managers can submit recommendations in an ongoing 

basis. 

10.2 Consultation with Other States 

In accordance with 40 CFR § 51.308(d)(1)(iv), in developing reasonable progress goals the state 

must consult with those states which may reasonably be anticipated to cause or contribute to 

visibility impairment in a Class I area within the state. In accordance with 40 CFR § 
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51.308(d)(3)(i), where a state’s emissions are reasonably anticipated to cause or contribute to 

impairment in a Class I area located in another state or states, that state must consult with the 

other state or states in order to develop coordinated emission management strategies. DENR 

accomplished these requirements through WRAP and by contacting and working with states that 

are not part of WRAP. 

As noted previously, DENR has been a participant in WRAP since its inception and considers its 

involvement as fulfilling part of the requirements for consultation. Within WRAP, the 

Implementation Work Group (IWG) was formed to address states’ issues regarding Regional 

Haze and conducted numerous face-to-face meetings and monthly calls. All western states, 

EPA, Tribes and Federal Land Managers participated in the WRAP activities and were involved 

throughout the process. 

DENR accomplished the requirement of working with states impacting Class I areas in South 

Dakota through WRAP and by contacting and working with states that are not part of WRAP to 

develop emission reductions. WRAP gathered information from what states were doing to 

reduce air emissions that contribute to visibility impairment and provided that information to 

other states. The same information was used by WRAP in the 2018 projection models to 

determine the impacts those reductions will have on each Class I area. 

Beyond WRAP, South Dakota was involved with the Northern Class I Areas workgroup which 

had monthly conference calls and included Minnesota, Michigan, Iowa, along with other 

Midwestern states. In addition, South Dakota consulted with Minnesota directly starting in 

August of 2007 through emails and phone calls, which continued through December of 2009 

when Minnesota submitted its Regional Haze State Implementation Plan to EPA. DENR also 

consulted directly with the State of Nebraska over the past few years through email and phone 

calls, mostly in regards to impacts the Gerald Gentleman Power Plant has on visibility 

impairment in Class I areas in South Dakota and their plans to control emissions from the Gerald 

Gentlemen Power Plant. As noted in a Public Notice dated May 28, 2009, the Nebraska 

Department of Environmental Quality determined BART shall be the replacement of the existing 

burner equipment system on Unit 2, a coal-fired electric generating unit, with a new Low NOx 

burner equipment system including overfire air ports. 

Otter Tail Power Company’s Big Stone I facility is the only source in South Dakota that is 

reasonably anticipated to contribute to visibility impairment of a Class I area in another state. 

Otter Tail Power Company’s BART analysis for Big Stone I demonstrated that its air emissions 

were reasonably anticipated to contribute to impairment at the Badlands National Park in South 

Dakota; Theodore National Park in North Dakota; Boundary Waters and Voyageurs Class I areas 

in northern Minnesota and the Isle Royale federal Class I area in Michigan. DENR notified 

these states and submitted Otter Tail Power Company’s case-by-case BART analysis and 

DENR’s review of the BART analysis for their comments. DENR did not receive any comments 

from Minnesota or Michigan. 

DENR reviewed the BART analysis and determined the proper air emission limits for the 

regulated air pollutants that are reasonably anticipated to contribute to impairment in the Class I 

areas. DENR will established the BART procedures in the Administrative Rules of South 
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Dakota that are equivalent to federal regulation in 40 CFR Part 51 and will adopt the BART 

emission limits in an air quality construction permit and eventually in Otter Tail Power 

Company’s Title V air quality operating permit for the Big Stone I facility. DENR believes the 

BART requirements for Big Stone I meets South Dakota’s obligation for emission reductions for 

those Class I areas impacted by Big Stone I. 

As stated above, DENR also sent South Dakota’s draft Regional Haze State Implementation Plan 

to the following states on January 15, 2010: 

1. Catherine Nueschler and Anne Jackson, State of Minnesota; 

2. Teresa Cooper and Asad Khan, State of Michigan; 

3. Shelley Schneider and Katryna Schaf, State of Nebraska; 

4. Dana Mount and Tom Bachman, State of North Dakota; 

5. Curtis Taipale, State of Colorado; 

6. Dave Klemp, State of Montana; and 

7. Tina Anderson, State of Wyoming. 

DENR did not receive any comments from these states. 

DENR did not experience any situation in which we disagreed with another state on a reasonable 

progress goal. DENR will continue to work with states to ensure South Dakota’s Class I areas 

achieve natural conditions by 2064 and air emissions from within South Dakota do not impair 

other state’s progress in achieving natural condition in their Class I areas by 2064. 

10.3 Public Input 

In accordance with 40 CFR § 51.308(d)(1)(ii), if the state establishes a reasonable progress goal 

that provides a slower rate of improvement in visibility than the rate that would be needed to 

attain natural condition by 2064, the state must provide the public an opportunity to review as 

part of the implementation plan an assessment of the number of years it would take to attain 

natural conditions if visibility improvement continues at the rate of progress selected by the state 

as reasonable. 

Based on the modeling analysis WRAP conducted on visibility improvement in 2018, the 

reasonable progress goal will not be met for organic carbon mass, ammonia nitrates, ammonia 

sulfates, and coarse particulates. The major contributor of ammonia sulfates and ammonia 

nitrates emissions at the two national parks is transported in from out of state. DENR has 

worked with other states through WRAP or individually to ensure their contribution in South 

Dakota is minimized. However, until all of the states implement their approved regional haze 

rules it is hard to determine if the modeling assumptions used by WRAP in the analysis are

correct. For instance, the WRAP analysis does not reflect the BART emission limits that will be 

implemented by Big Stone I or the BART emission limits other states are still developing for 

their BART sources. DENR believes as states start implementing the Regional Haze Programs, 

the ammonia sulfate and ammonia nitrate concentrations will be reduced to meet the glide path 

sometime between now and 2018. Therefore, DENR believes that South Dakota can still meet its 
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reasonable progress goals and achieve natural conditions by 2064. DENR will evaluate the 

progress on a periodic basis. 

Although DENR believes it will still achieve natural conditions by 2064, EPA states DENR must 

include a projection of when WRAP’s modeling projects natural conditions will be achieved. 

Based on WRAP’s modeling results, which as stated above does not represent the final 

reductions in each state’s regional haze program, natural conditions in South Dakota may not be 

achieved in the Badlands and Wind Cave National Parks until 2265 and 2236, respectively. 

DENR believes this is unrealistic and will continue to evaluate the projection as states begin 

implementing their Regional Haze State Implementation Plans. 

DENR has also committed through this document to develop and implement a Smoke 

Management Plan by 2013. DENR will use the time from now until then to evaluate wildfires 

and prescribed fires to determine which size, distance, fuel material, etc. needs to be included in 

the Smoke Management Plan and the Best Management Practices for minimizing the impacts of 

wildfires and prescribed fires on South Dakota’s two Class I areas. 

 

DENR is also required to provide public input when adopting rules. DENR will provide the 

public an opportunity to comment on the proposed regional haze program and provide testimony 

at a public hearing that will be held in front of the Board of Minerals and Environment. The 

comments from the public and others and DENR response to those comments may be reviewed 

in Appendix E. 

11.0 Periodic Review 

11.1 Evaluation and Reassess Every 10 Years 

In accordance with 40 CFR § 51.308(f), DENR will review, revise, and submit revisions to 

South Dakota’s State Implementation Plan by July 31, 2018, and every ten years thereafter. The 

review shall consist of DENR evaluating and reassessing all of the elements required in 40 CFR 

§ 51.308(d), taking into account improvements in monitoring data collection and analysis 

techniques, control technologies, and other relevant factors. The evaluation and reassessing shall 

address at least the following: 

1. In accordance with 40 CFR § 51.308(d)(2)(iv)(B), current visibility conditions for the 

20% most impaired and 20% least impaired days, and actual progress made towards 

natural conditions during the previous implementation period. The period for calculating 

current visibility conditions is the most recent five year period preceding the required 

date of the implementation plan submittal for which data are available. Current visibility 

conditions must be calculated based on the annual average level of visibility impairment 

for the most and least impaired days for each of these five years. Current visibility 

conditions are the average of these annual values; 

2. The effectiveness of the long-term strategy for achieving reasonable progress goals over 

the prior implementation period(s); and 

3. Affirmation of, or revision to, the reasonable progress goal in accordance with the 

procedures set forth in 40 CFR § 51.308(d)(1). If DENR established a reasonable 
135 

progress goal for the prior period which provided a slower rate of progress than that 

needed to attain natural conditions by the year 2064, DENR must evaluate and determine 

the reasonableness, based on the factors in 40 CFR § 51.308(d)(1)(i)(A), of additional 

measures that could be adopted to achieve the degree of visibility improvement projected 

by the analysis contained in the first implementation plan described in 40 CFR § 

51.308(d)(1)(i)(B). 

DENR will also coordinate with EPA to conduct these reviews jointly to satisfy the requirements 

of 40 CFR § 51.306(c). 

11.2 Report Every 5 Years 

In accordance with 40 CFR § 51.308(g), DENR will evaluate and report its progress towards the 

reasonable progress goal for each mandatory Class I federal area located within South Dakota 

and in each mandatory Class I federal area located outside the state which may be affected by 

emissions from within the state. The first progress report is due 5 years from submittal of 

DENR’s initial implementation plan for South Dakota’s Regional Haze Program and every 5 

years thereafter. The progress reports will be in the form of an implementation plan revision that 

complies with the procedural requirements of 40 CFR §§ 51.102 and 51.103. The periodic 

progress reports shall contain at a minimum the following elements: 

1. A description of the status of implementation of all measures included in the 

implementation plan for achieving reasonable progress goals for mandatory Class I 

federal areas both within and outside South Dakota; 

2. A summary of the emissions reductions achieved throughout South Dakota through 

implementation of the measures described in 40 CFR § 51.308(g)(1); 

3. For each mandatory Class I federal area within South Dakota, DENR will assess the 

following visibility conditions and changes with values for most impaired and least 

impaired days expressed in terms of 5-year averages of these annual values: 

a. The current visibility conditions for the most impaired and least impaired days; 

b. The difference between current visibility conditions for the most impaired and least 

impaired days and baseline visibility conditions; 

c. The change in visibility impairment for the most impaired and least impaired days 

over the past 5 years; 

4. An analysis tracking the change over the past 5 years in emissions of pollutants 

contributing to visibility impairment from all sources and activities within South Dakota. 

Emissions changes should be identified by type of source or activity. The analysis must 

be based on the most recent updated emissions inventory, with estimates projected 

forward as necessary and appropriate, to account for emissions changes during the 

applicable 5-year period; 

5. An assessment of any significant changes in anthropogenic emissions within or outside 

South Dakota that have occurred over the past 5 years that have limited or impeded 

progress in reducing pollutant emissions and improving visibility; 

6. An assessment of whether the current implementation plan elements and strategies are 

sufficient to enable South Dakota, or other states with mandatory Class I federal areas 
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affected by emissions from South Dakota, to meet all established reasonable progress 

goals. 

7. A review of DENR's visibility monitoring strategy and any modifications to the strategy 

as necessary. 

DENR will coordinate with EPA as it develops its long term strategy for reasonably attributable 

visibility impairment under 40 CFR § 51.306(c). 

11.3 Determination of Adequacy 

In accordance with 40 CFR § 51.308(h), at the same time that DENR is required to submit any 5-

year progress report to EPA in accordance with 40 CFR § 51.308(g), DENR will also take one of 

the following actions based upon the information presented in the progress report: 

1. If DENR determines the existing implementation plan requires no further substantive 

revision at this time in order to achieve established goals for visibility improvement and 

emissions reductions, DENR must provide EPA with a negative declaration that further 

revision of the existing implementation plan is not needed at this time; 

2. If DENR determines that the implementation plan is or may be inadequate to ensure 

reasonable progress due to emissions from sources in another state(s) which participated in a 

regional planning process, DENR must provide notification to EPA and to the other state(s) 

which participated in the regional planning process with DENR. DENR must also collaborate 

with the other state(s) through the regional planning process for the purpose of developing 

additional strategies to address the plan's deficiencies; 

3. Where DENR determines that the implementation plan is or may be inadequate to ensure 

reasonable progress due to emissions from sources in another country, DENR shall provide 

notification, along with available information, to EPA; and 

4. Where DENR determines that the implementation plan is or may be inadequate to ensure 

reasonable progress due to emissions from sources within South Dakota, DENR shall revise 

its implementation plan to address the plan's deficiencies within one year from the date the 

progress report is due. 
Appendix A 

Otter Tail Power Company’s 

BART Modeling Protocol 

and 

Approval Letter 
Appendix B 

Otter Tail Power Company’s 

Visibility Impact Analysis 
Appendix C 

Otter Tail Power Company’s 

Case-by-Case BART Analysis 
Appendix D 

Federal Land Managers’ Comments 

and 

DENR’s Response 
Appendix E 

Public Notice Comments 

and 

DENR’s Response 
APPENDIX F 

WRAP’s FOUR FACTOR ANALYSIS 

FOR 

GCC DACOTAH 

AND 

BLACK HILLS CORPORATION (BEN FRENCH) 
APPENDIX G 

VISIBILITY MODELING RESULTS FOR 

GCC DACOTAH
APPENDIX H 

VISIBILITY MODELING RESULTS FOR 

BLACK HILLS CORPORATION 

BEN FRENCH
APPENDIX I 

VISIBILITY MODELING RESULTS FOR 

PETE LIEN AND SONS, INC