Source: https://www.federalregister.gov/documents/2011/12/08/2011-31406/approval-and-promulgation-of-implementation-plans-south-dakota-regional-haze-state-implementation
Timestamp: 2018-09-25 01:09:07
Document Index: 412836615

Matched Legal Cases: ['§\u2009169', 'art 51', '§\u2009110', 'art 51', 'art 75', 'ART.\n2002', 'art 51', 'art 75']

76646-76673 (28 pages)
https://www.federalregister.gov/d/2011-31406 https://www.federalregister.gov/d/2011-31406
B. Determination of Baseline, Natural and Current Visibility Conditions Start Printed Page 76647
Regional haze is visibility impairment that is produced by a multitude of sources and activities which are located across a broad geographic area and emit particulate matter with a diameter less than 2.5 microns (PM2.5) (e.g., sulfates, nitrates, organic carbon (OC), elemental carbon (EC) and soil dust) and its precursors (e.g., sulfur dioxide (SO2), nitrogen oxides (NOX), and in some cases, ammonia (NH3) and volatile organic compounds (VOCs)). These precursors react in the atmosphere to form PM2.5. PM2.5 impairs visibility by scattering and absorbing light. Visibility impairment reduces the clarity, color and visible distance that one can see. PM2.5 also can cause serious health effects and mortality in humans and contributes to environmental effects such as acid deposition and eutrophication.
Data from the “Interagency Monitoring of Protected Visual Environments” (IMPROVE) monitoring network show that visibility impairment caused by air pollution occurs virtually all the time at most national park and wilderness areas. The average visual range [1] in many Class I areas (i.e., national parks, memorial parks, wilderness areas and international parks meeting certain size criteria) in the western United States is 100-150 kilometers, or about one-half to two-thirds of the visual range that would exist without anthropogenic air pollution. 64 FR 35714, 35715 (July 1, 1999). In most of the eastern Class I areas of the United States, the average visual range is less than 30 kilometers, or about one-fifth of the visual range that would exist under estimated natural conditions. Id.
In section 169A of the 1977 Amendments to the CAA, Congress created a program for protecting visibility in the nation's national parks and wilderness areas. This section of the CAA establishes as a national goal the “prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I federal areas [2] which impairment results from man-made air pollution.” CAA § 169A(a)(1). The terms “impairment of visibility” and “visibility impairment” are defined in the Act to include a reduction in visual range and atmospheric discoloration. Id. section 169A(g)(6). In 1980, we promulgated regulations to address visibility impairment in Class I areas that is “reasonably attributable” to a single source or small group of sources, i.e., “RAVI.” 45 FR 80084 (December 2, 1980). These regulations represented the first phase in addressing visibility impairment. We deferred action on regional haze that emanates from a variety of sources until monitoring, modeling and scientific knowledge about the relationships between pollutants and visibility impairment had improved.
Congress added section 169B to the CAA in 1990 to address regional haze issues, and we promulgated regulations addressing regional haze in 1999. 64 FR 35714 (July 1, 1999), codified at 40 CFR part 51, subpart P. The Regional Haze Rule revised the existing visibility regulations to integrate into them provisions addressing regional haze impairment and establish a comprehensive visibility protection program for Class I areas. The requirements for regional haze, found at 40 CFR 51.308 and 51.309, are included in our visibility protection regulations at 40 CFR 51.300-309. Some of the main regional haze requirements are summarized in section II of this action. The requirement to submit a Regional Haze SIP applies to all 50 states, the District of Columbia and the Virgin Islands. States were required to submit a SIP addressing regional haze visibility impairment no later than December 17, 2007.[3] 40 CFR 51.308(b).
Few states submitted a Regional Haze SIP prior to the December 17, 2007 deadline, and on January 15, 2009, EPA found that 37 states, including South Dakota and the District of Columbia, and the Virgin Islands, had failed to submit SIPs addressing the regional Start Printed Page 76648haze requirements. 74 FR 2392. Once EPA has found that a state has failed to make a required submission, EPA is required to promulgate a FIP within two years unless the state submits a SIP and the Agency approves it within the two year period. CAA § 110(c)(1).
The Regional Haze Rule establishes the deciview (dv) as the principal metric for measuring visibility. See 70 FR 39104, 39118. This visibility metric expresses uniform changes in the degree of haze in terms of common increments across the entire range of visibility conditions, from pristine to extremely hazy conditions. Visibility is sometimes expressed in terms of the visual range, which is the greatest distance in kilometers or miles at which a dark object can just be distinguished against the sky. The deciview is a useful measure for tracking progress in improving visibility, because each deciview change is an equal incremental change in visibility perceived by the human eye. Most people can detect a change in visibility of one deciview.[4]
To track changes in visibility over time at each of the 156 Class I areas covered by the visibility program (40 CFR 81.401-437), and as part of the process for determining reasonable progress, states must calculate the degree of existing visibility impairment at each Class I area at the time of each Regional Haze SIP submittal and periodically review progress every five years midway through each 10-year implementation period. To do this, the Regional Haze Rule requires states to determine the degree of impairment (in deciviews) for the average of the 20 percent least impaired (“best”) and the average of the 20 percent most impaired (“worst”) visibility days over a specified time period at each of their Class I areas. In addition, states must also develop an estimate of natural visibility conditions for the purpose of comparing progress toward the national goal. Natural visibility is determined by estimating the natural concentrations of pollutants that cause visibility impairment and then calculating total light extinction based on those estimates. We have provided guidance to states regarding how to calculate baseline, natural and current visibility conditions.[5]
For the first Regional Haze SIPs that were due by December 17, 2007, “baseline visibility conditions” were the starting points for assessing “current” visibility impairment. Baseline visibility conditions represent the degree of visibility impairment for the 20 percent least impaired days and 20 percent most impaired days for each calendar year from 2000 to 2004. Using monitoring data for 2000 through 2004, states are required to calculate the average degree of visibility impairment for each Class I area, based on the average of annual values over the five-year period. The comparison of initial baseline visibility conditions to natural visibility conditions indicates the amount of improvement necessary to attain natural visibility, while the future comparison of baseline conditions to the then current conditions will indicate the amount of progress made. In general, the 2000-2004 baseline period is considered the time from which improvement in visibility is measured. Start Printed Page 76649
The vehicle for ensuring continuing progress towards achieving the natural visibility goal is the submission of a series of Regional Haze SIPs from the states that establish two reasonable progress goals (i.e., two distinct goals, one for the “best” and one for the “worst” days) for every Class I area for each (approximately) 10-year implementation period. See 40 CFR 51.308(d), (f). The Regional Haze Rule does not mandate specific milestones or rates of progress, but instead calls for states to establish goals that provide for “reasonable progress” toward achieving natural (i.e., “background”) visibility conditions. In setting reasonable progress goals, states must provide for an improvement in visibility for the most impaired days over the (approximately) 10-year period of the SIP, and ensure no degradation in visibility for the least impaired days over the same period. Id.
In establishing reasonable progress goals, states are required to consider the following factors established in section 169A of the CAA and in our Regional Haze Rule at 40 CFR 51.308(d)(1)(i)(A): (1) The costs of compliance; (2) the time necessary for compliance; (3) the energy and non-air quality environmental impacts of compliance; and (4) the remaining useful life of any potentially affected sources. States must demonstrate in their SIPs how these factors are considered when selecting the reasonable progress goals for the best and worst days for each applicable Class I area. In setting the reasonable progress goals, states must also consider the rate of progress needed to reach natural visibility conditions by 2064 (referred to as the “uniform rate of progress” or “glidepath”) and the emission reduction measures needed to achieve that rate of progress over the 10-year period of the SIP. Uniform progress towards achievement of natural conditions by the year 2064 represents a rate of progress, which states are to use for analytical comparison to the amount of progress they expect to achieve. If a 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 reasonable progress factors, that the rate of progress for the implementation plan to attain natural conditions by 2064 is not reasonable, and that the progress goal adopted by the state is reasonable. In setting reasonable progress goals, each state with one or more Class I areas (“Class I state”) must also consult with potentially “contributing states,” i.e., other nearby states with emission sources that may be affecting visibility impairment at the state's Class I areas. 40 CFR 51.308(d)(1)(iv). In determining whether a state's goals for visibility improvement provide for reasonable progress toward natural visibility conditions, EPA is required to evaluate the demonstrations developed by the state pursuant to paragraphs 40 CFR 51.308(d)(1)(i) and (d)(1)(ii). 40 CFR 51.308(d)(1)(iii).
Section 169A of the CAA directs states to evaluate the use of retrofit controls at certain larger, often uncontrolled, older stationary sources with the potential to emit 250 tons or more per year of any pollutant in order to address visibility impacts from these sources. Specifically, section 169A(b)(2)(A) of the Act requires states to revise their SIPs to contain such measures as may be necessary to make reasonable progress towards the natural visibility goal, including a requirement that certain categories of existing major stationary sources [6] built between 1962 and 1977 procure, install and operate BART as determined by the state or by EPA in the case of a plan promulgated under section 110(c) of the CAA. Under the Regional Haze Rule, states are directed to conduct BART determinations for such “BART-eligible” sources that may be anticipated to cause or contribute to any visibility impairment in a Class I area. Rather than requiring source-specific BART controls, states also have the flexibility to adopt an emissions trading program or other alternative program as long as the alternative provides greater reasonable progress towards improving visibility than BART.
The process of establishing BART emission limitations can be logically broken down into three steps: First, states identify those sources which meet the definition of “BART-eligible source” set forth in 40 CFR 51.301 [7] ; second, states determine which of such sources “emits any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in any such area” (a source which fits this description is “subject to BART”); and third, for each source subject to BART, states then identify the best available type and level of control for reducing emissions.
States must address all visibility-impairing pollutants emitted by a source in the BART determination process. The most significant visibility-impairing pollutants are SO2, NOX and PM. We have stated that states should use their best judgment in determining whether VOC or NH3 compounds impair visibility in Class I areas.
In their SIPs, states must identify “BART-eligible sources” and “subject-to-BART sources” and document their Start Printed Page 76650BART control determination analyses. The term “BART-eligible source” used in the BART Guidelines means the collection of individual emission units at a facility that together comprises the BART-eligible source. In making BART determinations, section 169A(g)(2) of the CAA requires that states consider the following factors: (1) The costs 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 improvement in visibility which may reasonably be anticipated to result from the use of such technology. See also 40 CFR 51.308(e)(1)(ii)(A).
The Regional Haze Rule requires control strategies to cover an initial implementation period extending to the Start Printed Page 76651year 2018, with a comprehensive reassessment and revision of those strategies, as appropriate, every 10 years thereafter. Periodic SIP revisions must meet the core requirements of section 51.308(d), with the exception of BART. The requirement to evaluate sources for BART applies only to the first Regional Haze SIP. Facilities subject to BART must continue to comply with the BART provisions of section 51.308(e). Periodic SIP revisions will assure that the statutory requirement of reasonable progress will continue to be met.
The State of South Dakota submitted a revision to its SIP to address the requirements for regional haze on January 21, 2011. On September 19, 2011, South Dakota submitted an amendment to the Regional Haze SIP revision for approval into the South Dakota SIP. The amendment incorporated changes made by the State to ensure approvability of the SIP revision. The changes incorporated detailed monitoring, recordkeeping, and reporting requirements for BART sources into state regulation, Administrative Rules of South Dakota (ARSD) Chapter 74:36:21, including specifying that BART limits apply at all times and clarified compliance test methods for particulate matter and continuous emission monitoring system requirements for SO2 and NOX. In addition, South Dakota revised the reasonable progress analysis for the GCC Dacotah cement plant. The following is a discussion of our evaluation of the revision.
As required by section 51.308(d)(2)(i) of the Regional Haze Rule and in accordance with our 2003 Natural Visibility Guidance, South Dakota calculated baseline/current and natural visibility conditions for its Class I areas, Badlands and Wind Cave, on the most impaired and least impaired days, as summarized below. The natural visibility conditions, baseline visibility conditions and visibility impact reductions needed to achieve the uniform rate of progress in 2018 for both South Dakota Class I areas are presented in Table 1 and further explained in this section. More detail is available in Section 3 of the South Dakota SIP.[8]
2018 URP Goal (dv)
2018 Reduction needed (delta dv)
Badlands National Park 17.14 15.02 2.12 8.06 6.89 2.86
Wind Cave National Park 15.84 13.94 1.90 7.71 5.14 1.88
Natural background visibility as defined in our 2003 Natural Visibility Guidance is estimated by calculating the expected light extinction using default estimates of natural concentrations of fine particle components adjusted by site-specific estimates of humidity. This calculation uses the IMPROVE equation, which is a formula for estimating light extinction from the estimated natural concentrations of fine particle components (or from components measured by the IMPROVE monitors). Start Printed Page 76652As documented in our 2003 Natural Visibility Guidance, EPA allows states to use “refined” or alternative approaches to this guidance to estimate the values that characterize the natural visibility conditions of Class I areas. One alternative approach is to develop and justify the use of alternative estimates of natural concentrations of fine particle components. Another alternative is to use the “new IMPROVE equation” that was adopted for use by the IMPROVE Steering Committee in December 2005.[9] The purpose of this refinement to the “old IMPROVE equation” is to provide more accurate estimates of the various factors that affect the calculation of light extinction.
For Badlands and Wind Cave, South Dakota opted to use the revised IMPROVE equation to calculate natural background conditions. This is an acceptable approach under our 2003 Natural Visibility Guidance. EPA has found the use of the revised IMPROVE equation appropriate for WRAP states.[10] For Badlands, the natural visibility background for the 20 percent worst days is 8.06 deciviews and for the 20 percent best days is 2.86 deciviews. For Wind Cave, the natural visibility result for the 20 percent worst days is 7.71 deciviews and for the 20 percent best days is 1.88 deciviews. We have reviewed South Dakota's estimates of the natural visibility conditions and as the approach used by the State was consistent with our 2003 Natural Visibility Guidance we are proposing to find them acceptable.
As required by section 51.308(d)(2)(i) of the Regional Haze Rule, South Dakota calculated baseline visibility conditions for Badlands and Wind Cave. The baseline condition calculation begins with the calculation of light extinction using the IMPROVE equation. The IMPROVE equation sums the light extinction [11] resulting from individual pollutants, such as sulfates and nitrates. As with the natural visibility conditions calculation, South Dakota chose to use the revised IMPROVE equation.
Using a baseline visibility value at Wind Cave of 15.84 deciviews and a “refined” natural visibility value of 7.71 deciviews for the 20 percent worst days, South Dakota calculated the uniform rate of progress to be approximately 0.136 deciviews per year. This results in a total reduction of 8.13 deciviews to reach the natural visibility condition of 7.71 deciviews in 2064. The uniform rate of progress results in a visibility improvement of 1.89 deciviews needed for the period covered by this SIP revision submittal (up to and including 2018).Start Printed Page 76653
Baseline Conditions 17.14 dv 15.84 dv
Natural Visibility 8.06 dv 7.71 dv
Total Improvement by 2064 9.08 dv 8.13 dv
Needed Improvement for this SIP by 2018 2.18 dv 1.89 dv
URP 0.151 dv/year 0.136 dv/year
The BART Guidelines direct states to address SO2, NOX and direct PM (including both coarse (PM10) and fine (PM2.5) particulate matter emissions as visibility-impairing pollutants and to exercise their “best judgment to determine whether VOC or NH3 emissions from a source are likely to have an impact on visibility in an area.” See 70 FR 39162. The available inventory information indicates VOCs in South Dakota overwhelmingly come from biogenic sources, and NH3 in South Dakota is primarily due to area sources, such as livestock and fertilizer application. Because these are not point sources, they are not subject to BART. We have reviewed this information and propose to find South Dakota's focus on SO2, NOX, and PM acceptable.
1. Northern States Power Company (Units 1, 2, and 3) Sioux Falls, South Dakota SC 1—fossil fuel steam electric plants >250 MMBtu/hr heat input N/A.1
2. Otter Tail Power Company, Big Stone I (Unit 1) Near Big Stone City, South Dakota SC 1—fossil fuel steam electric plants >250 MMBtu/hr heat input Boundary Waters 431 km.
3. Pete Lien and Sons, Inc. Rapid City, South Dakota SC 12—lime plants Wind Cave 52 km.
1 South Dakota did not analyze the three units at Northern States Power for distance to Class I areas as they have been decommissioned.
The BART Guidelines provide that states may use the CALPUFF [12] modeling system or another appropriate model to predict the visibility impacts from a single source on a Class I area and to, therefore, determine whether an individual source is anticipated to cause or contribute to impairment of visibility in Class I areas, i.e., “is subject to BART.” The BART Guidelines state that we find CALPUFF is the best regulatory modeling application currently available for predicting a single source's contribution to visibility impairment (70 FR 39162).
The BART Guidelines also recommend that states develop a modeling protocol for making individual source attributions, and suggest that states may want to consult with us and their RPO to address any issues prior to modeling. South Dakota relied on WRAP's CALPUFF modeling for South Dakota BART sources as Start Printed Page 76654recommended by the BART Guidelines.[13] 40 CFR part 51, appendix Y, section III.A.3.
For states using modeling to determine the applicability of BART to single sources, the BART Guidelines note that the first step is to set a contribution threshold to assess whether the impact of a single source is sufficient to cause or contribute to visibility impairment at a Class I area. The BART Guidelines state that, “[a] single source that is responsible for a 1.0 deciview change or more should be considered to `cause' visibility impairment.” 70 FR 39104, 39161. The BART Guidelines also state that “the appropriate threshold for determining whether a source contributes to visibility impairment may reasonably differ across states,” but, “[a]s a general matter, any threshold that you use for determining whether a source `contributes' to visibility impairment should not be higher than 0.5 deciviews.” Id. Further, in setting a contribution threshold, states should “consider the number of emissions sources affecting the Class I areas at issue and the magnitude of the individual sources' impacts.” The Guidelines affirm that states are free to use a lower threshold if they conclude that the location of a large number of BART-eligible sources in proximity to a Class I area justifies this approach.
The WRAP modeling results demonstrated that Pete Lien and Sons, Inc. did not cause or contribute to visibility impairment at any Class I area. After reviewing the modeling inputs, South Dakota determined that the vertical kiln should be modeled again due to several errors. However, before additional modeling could be done, Pete Lien and Sons, Inc. shut down and dismantled the kiln in 2009 per its Title V permit.[14]
98th percentile visibility impact (dv)1
Badlands SD 470 0.683
Boundary Waters MN 431 1.034
Bridger WY 1,041 0.001
Fitzpatrick WY 1,050 0.001
Grand Teton WY 1,112 0.001
Lostwood ND 585 0.263
Medicine Lake MT 690 0.256
North Absaroka WY 1,013 0.011
Teton WY 1,052 0.004
Theodore Roosevelt ND 555 0.687
UL Bend MT 902 0.089
Voyageurs MN 438 0.729
Washakie WY 1,006 0.007
Wind Cave SD 572 0.263
Yellowstone WY 1,049 0.009
1 Modeling results represent the maximum 98th percentile impact over the modeled 3-year meteorological period 2001-2003.
Badlands 0.5
Boundary Waters 1.1
Lostwood 0.4
Theodore Roosevelt 0.5
Voyageurs 0.7
Wind Cave 0.3
Isle Royale 0.7
1 Modeling results represent the maximum 98th percentile impact over the modeled meteorological years 2002, 2006, and 2007.
South Dakota requested that Otter Tail Power Company complete a BART analysis for Big Stone I and used this analysis as a basis for its BART determination for this source for NOX, SO2 and PM. The Otter Tail BART analysis is included in Appendix C of the SIP. Otter Tail generally followed the five steps contained in the BART Guidelines and evaluated the five BART factors. In some instances, South Dakota identified additional control technologies for evaluation and also added an analysis of average cost effectiveness compared to visibility benefit (dollar per deciview) for the various multi-pollutant control options. We find that South Dakota, through its reliance on Otter Tail's BART analysis, reasonably considered the five BART factors and arrived at a reasonable BART determination for Big Stone I. We propose to approve South Dakota's BART determination summarized below.
Big Stone I is a steam electric generating plant located near Big Stone City, South Dakota with one generating unit burning Powder River Basin coal and a net electrical output of 475 MW. The Otter Tail Power Company is the operating agent for the Big Stone Plant co-owners: NorthWestern Energy, Montana-Dakota Utilities, Co., a division of MDU Resources Group, and Otter Tail Power Company. The generating unit is a Babcock cyclone boiler that started operating in 1975. The State analyzed each pollutant and its effect on the visibility in Class I areas. Since Big Stone I does not have a total generating capacity greater than 750 MW, South Dakota was not required to follow the BART Guidelines in determining BART, but it generally followed the approach for determining BART set out in the Guidelines. A summary of the State's analyses of existing controls and potential BART controls for each pollutant is set forth below. The State's BART determination for Big Stone I is provided in Section 6 of the SIP. The visibility and cost impacts noted in the following assessment are derived from the company's BART analysis provided in Appendix B of the SIP.[15]
SO2BART Review: Unit 1 has no existing SO2 controls. The baseline uncontrolled SO2 emissions that South Dakota reported in the SIP are 18,000 tons per year.
The State identified the following SO2 control options as having potential application to Unit 1: Fuel switching, coal cleaning, coal upgrading (K-Fuel), hydrated lime injection, semi-dry flue gas desulfurization (FGD), wet FGD, Enviroscrub, electro catalytic oxidation and the Airborne process.
The State eliminated the following options as technically infeasible: Coal Start Printed Page 76656cleaning, coal upgrading, hydrated lime injection, Enviroscrub, Electro catalytic oxidation and the Airborne process. Fuel switching is a viable method to reduce sulfur dioxide emissions by switching to a fuel with lower sulfur content. The Big Stone facility's primary fuel source is subbituminous coal obtained from the Powder River Basin in Wyoming. Powder River Basin subbituminous coal has one of the lowest sulfur contents available in the United States. As such, the State concluded that Otter Tail Power Company has already implemented fuel switching.
Table 6—Summary of Big Stone I SO2 BART Analysis Control Technologies for Unit 1 Boiler 1
Emissions reduction (tons/yr)
Wet FGD #1 95 0.043 900 17,100
Wet FGD #2 83 0.15 3,130 14,870
Semi-Dry FGD #1 90 0.09 1,880 16,120
Semi-Dry FGD #2 83 0.15 3,130 14,870
1 South Dakota calculated emissions from a baseline of 18,000 tons per year of SO2. The baseline was derived from the highest average 24-hour average emission rate (4,832 pounds per hour) for calendar years 2001 through 2003 and operations occurring 85% of the time or 7,746 hours per year.
The State relied on Otter Tail's cost analysis for SO2 controls and this is summarized below in Table 7. The State deemed the average cost effectiveness reasonable for the two remaining control options, semi-dry and wet FGD.
Table 7—Summary of Big Stone I SO2 BART Cost Analysis for Unit 1 Boiler
Wet FGD #1 $171.8 $29.05 17,100 $1,699
Wet FGD #2 171.8 28.90 14,870 1,944
Semi-Dry FGD #1 141.3 23.57 16,120 1,462
Semi-Dry FGD #2 141.3 23.33 14,870 1,569
Table 8 presents a comparison of the visibility impacts of the two top control options, wet FGD and semi-dry FGD. The values are derived from modeling conducted by Otter Tail. For the cases presented, Otter Tail held the emission rates for NOX and PM constant but varied the SO2 emissions rates in the model as noted. In some cases, the modeling predicted that the semi-dry FGD would produce a greater visibility benefit than the wet FGD. It is not clear why the model predicted this result; it may relate to stack parameters. Based on the visibility modeling, the State found that there would be no discernible visibility benefit from selecting a wet FGD over a semi-dry FGD.
Table 8—Visibility Impact Comparison Between Wet and Semi-Dry FGD SO2 Controls 1
Class I area 4
#3 OFA and Semi-dry FGD (0.09 lb/MMBtu) 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 (0.043 lb/MMBtu) 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 3 (incremental visibility impact of wet FGD (in Option 3) compared to semi-dry FGD (in Option 4)) Boundary Waters 0.031 ^0.013 ^0.009
Voyageurs 0.005 0.073 0.052
Isle Royale ^0.012 ^0.037 ^0.033
Badlands 0.006 0.019 0.004
Theodore Roosevelt ^0.003 ^0.004 ^0.035
#5a SOFA and Semi-dry FGD (0.09 lb/MMBtu) 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 (0.043 lb/MMBtu) Boundary Waters 0.274 0.407 0.478
Voyageurs 0.244 0.365 0.393
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 3 (incremental visibility impact of wet FGD (in Option 5a) compared to semi-dry FGD (in Option 5b)) Boundary Waters 0.024 ^0.012 ^0.015
Voyageurs ^0.005 0.059 0.039
Isle Royale ^0.011 ^0.031 ^0.029
Badlands 0.009 0.014 0.002
Theodore Roosevelt ^0.003 ^0.006 ^0.033
1 Otter Tail Power Company conducted visibility modeling for both wet and semi-dry FGD options using combined controls with constant emission rates for NOX and PM. Thus, the results shown include the noted SO2 and NOX control options and the existing fabric filter PM control option.
2 An explanation of each of the numbered control options and the corresponding emission rates is included in Section 6 of the SIP, Table 6-13, p. 94.
3 A negative number means the wet FGD had a lower visibility impact than the semi-dry FGD.
4 These are the Class I areas that exceed the 0.5 deciview threshold as listed in Table 5.
South Dakota determined BART to be the second ranked control option, semi-dry FGD at 90 percent control efficiency in Section 6.3.5.2 of the SIP. Even though the top ranked control option, wet FGD at 95 percent control efficiency, reduced the SO2 emissions more than the second ranked option, the State determined that there is no discernible difference between the two options when considering visibility impacts. South Dakota specified BART limits of 505 lb/hour and 0.09 lb/MMBtu (30-day rolling average) that apply at all times including periods of startup, shutdown and malfunction. The estimated cost of the semi-dry FGD system was $1,462 per ton ($/ton) of SO2 removed, and the capital and annualized costs were estimated to be $141,300,000 and $23,570,000 per year ($/year or $/yr), respectively.
We are proposing to approve the State's SO2 BART determination for Big Stone I. The State's assessment of costs and other impacts and its elimination of the wet FGD at 95% control efficiency was reasonable based on the five-factor analysis. While the average cost effectiveness values for both wet FGD and semi-dry FGD are reasonable, the modeling predicted that the use of a wet FGD at 95% efficiency rather than a semi-dry FGD at 90% efficiency would result in minimal, if any, visibility benefit. Thus, it was reasonable for the State to eliminate a wet FGD at 95% efficiency from consideration. The installation of a semi-dry FGD at Big Stone I will result in a reduction in annual SO2 emissions from the plant of approximately 16,120 tons.[16] The visibility benefit for the selected BART controls for all pollutants combined is provided in the summary in Table 12 in section III.C.3.b. below.
NOXBART Review: Big Stone I is already equipped with overfire air (OFA) for NOX control. South Dakota indicates in the SIP that Unit 1 has baseline controlled NOX emissions of 18,000 tons per year with an emission rate of 0.65 lb/MMBtu.
South Dakota identified the following control options as having potential application as BART: Selective catalytic reduction (SCR), oxygen enhanced combustion, catalytic absorption/oxidation, gas reburn, Enviroscrub, electro-catalytic oxidation, NOX Star, Cascade processes, selective non-catalytic reduction (SNCR), rich reagent injection (RRI), flue gas recirculation (FGR), separated over-fire air (SOFA), over-fire air (OFA), and low-NOX burners (LNB).Start Printed Page 76658
The State identified the following control options as technically infeasible: Oxygen enhanced combustion, absorption/oxidation, gas reburn, Enviroscrub, electro-catalytic oxidation, NOX Star, Cascade processes, and LNB. The State noted that flue gas recirculation is not known to reduce nitrogen oxide emissions any further when added with an over-fire air system. Therefore, the State and Otter Tail Power Company did not conduct any further review of flue-gas recirculation.
Table 9—Summary of Big Stone I NOX BART Analysis Control Technologies for Unit 1 Boiler 1
SCR and SOFA 89 0.10 2,000 16,000
RRI, SNCR and SOFA 77 0.20 4,090 13,910
SNCR and SOFA 60 0.35 7,220 10,780
SOFA 42 0.50 10,360 7,640
OFA 25 0.65 13,490 4,510
1 South Dakota calculated emissions from a baseline of 18,000 tons per year of NOX. The baseline was derived from the highest average 24-hour average emission rate (4,855 pounds per hour) for calendar years 2001 through 2003 and operations occurring 85% of the time or 7,746 hours per year.
The State relied on Otter Tail's cost analysis for NOX controls and this is summarized below in Table 10. The State deemed the average cost effectiveness reasonable for all of the remaining control options, SCR, SNCR, RRI, SOFA, and OFA, as provided by Otter Tail.
Table 10—Summary of Big Stone I NOX BART Cost Analysis for Unit 1 Boiler
SCR and SOFA $81.9 $13.21 16,000 $825
RRI, SNCR and SOFA 16.2 11.39 13,910 818
SNCR and SOFA 11.9 3.99 10,780 197
SOFA 4.8 0.65 7,640 85
OFA 0 0.14 4,510 31
South Dakota determined BART to be SCR + SOFA. South Dakota specified BART limits of 561 lb/hour and 0.10 lb/MMBtu (30-day rolling average) that apply at all times including periods of startup, shutdown, and malfunction. The estimated cost of the SCR + SOFA controls was $825 per ton ($/ton) of NOX removed, and the capital and annualized costs were estimated to be $81,800,000, and $13,210,000 per year ($/year or $/yr), respectively.
We are proposing to approve the State's NOX BART determination for Big Stone I. The State's assessment of costs and other impacts was reasonable. The installation of SCR and SOFA at Big Stone I will result in a reduction in annual NOX emissions from the plant of approximately 16,000 tons. Table 12, below, provides the visibility benefit for the selected BART controls for all pollutants combined.
PM BART Review: Big Stone I is already equipped with a pulse jet fabric filter baghouse for PM which is considered the most efficient control technology available. The baseline controlled PM emissions that South Dakota reported in the SIP are 300 tons per year with an emission rate of 0.015 lb/MMBtu. The State identified the following PM control options as having potential application to the Big Stone I boiler: Existing fabric filter baghouse, new fabric filter baghouse, compact hybrid particulate collector (COHPAC), electrostatic precipitator, wet scrubber, Start Printed Page 76659and cyclones/multiclones. The State did not eliminate any of the control technologies as technically infeasible for controlling PM emissions from the boiler.
We have summarized South Dakota's BART determinations in Table 11 below. We have summarized the visibility impacts at the appropriate Class I areas for South Dakota's selected BART controls in Table 12 below. The substantial emissions reductions in SO2 and NOX will result in a significant improvement in visibility at several Class I areas. The visibility improvement from reducing both pollutants at the most impacted area, Boundary Waters, is estimated to be 0.9 deciviews and 54 fewer days above 0.5 deciviews.[17]
As noted previously, to be approvable, the Regional Haze SIP must include monitoring, recordkeeping, and reporting requirements to ensure that the BART limits are enforceable. South Dakota has included these requirements in ARSD Chapter 74:36:21. We have reviewed these requirements and find them to be adequate as they relate to the BART limits we are proposing to approve. In particular, for SO2 and NOX BART limits, the rule requires the use of continuous emission monitoring systems (CEMS) to determine compliance, generally in accordance with 40 CFR part 75. For the filterable PM BART limits, the rule requires stack testing. Adequate recordkeeping and reporting requirements are also specified.
Baseline emissions (tons/yr)1
Baseline level of control (% reduction)
BART level of control (% reduction)
Emissions after controls (tons/yr)
Emission reduction (tons/yr)
SO2 18,000 0 90 Semi-dry FGD 1,880 16,120 505 lb/hr, and 0.09 lb/MMBtu, 30-day rolling average.
NOX 18,000 25 88 SOFA + SCR 2,000 16,000 561 lb/hr, and 0.10 lb/MMBtu, 30-day rolling average.
PM 300 95-99.9 95-99.9 Existing Fabric Filter 67.3 lb/hr, and 0.012 lb/MMBtu, 30-day rolling average.
1 South Dakota calculated baseline emissions for SO2 and NOX by identifying the highest average 24-hour average actual emission rate for the years 2001 through 2003 and adjusted this to 85% operations level or 7,746 hours per year.
SCR, SOFA, and Semi-Dry FGD 1 Boundary Waters 0.097 0.136 0.170
Voyageurs 0.086 0.107 0.123
Isle Royale 0.092 0.077 0.098
Badlands 0.079 0.060 0.070
Theodore Roosevelt 0.036 0.070 0.064
1 The results reflect the visibility impacts after installation of controls with an SCR at a NOX emissions rate of 0.1 lb/MMBtu, a semi-dry FGD at an SO2 emissions rate of 0.15 lb/MMBtu, and the existing pulse jet fabric filter baghouse at a PM emissions rate of 0.015 lb/MMBtu. The selected BART emissions limits for SO2 and PM are lower than the modeled values, therefore, the visibility impacts after BART controls are installed will be lower than those presented in this table. See Table 8 for a comparison of visibility impacts for wet and semi-dry FGD. See Table 5 for baseline visibility impacts.
The primary tool WRAP relied upon for modeling regional haze improvements by 2018, and for estimating South Dakota's Reasonable Progress Goals, was the CMAQ model. The CMAQ model was used to estimate 2018 visibility conditions in South Dakota and all western Class I areas, based on application of anticipated regional haze strategies in the various states' regional haze plans, including assumed controls on BART sources.[18]
As the purpose of the reasonable progress analysis is to evaluate the potential of controlling certain sources or source categories for addressing visibility from manmade sources, the four-factor analysis conducted by South Dakota addresses only anthropogenic sources, on the assumption that the focus should be on sources that can be “controlled.” In its evaluation of potential sources or source categories for reasonable progress, South Dakota primarily considered point sources. South Dakota determined that the key pollutants contributing to visibility impairment at the two Class I areas are SO2, organic carbon and NOX. South Dakota also only considered controls for emissions of SO2 and NOX (i.e., sulfate and nitrate) which are typically associated with anthropogenic sources. South Dakota determined the major source of organic carbon in the two Class I areas is natural fire. By reviewing the WRAP modeling results, South Dakota determined that PM emissions from point sources contribute only a minimal amount to visibility impairment in the South Dakota Class I areas.
During our review of South Dakota's four-factor analysis, we analyzed actual emissions data from EPA's 2002 National Emissions Inventory database. We started with the emissions inventory totals for SO2 and NOX then divided the actual emissions (Q) in tons per year from the sources by their distance (D) in kilometers to the nearest Class I Federal area. A summary list of the largest sources we reviewed in our Q/D analysis is included below in Table 13.Start Printed Page 76661
SO2 + NOX 2000-2004 average (tons)
Distance to nearest Class I area (km)
Q/D to closest Class I area (tons/km)
Black Hills, Ben French Power Plant 1,782 65 27.41
GCC Dacotah 4,465 66 67.66
John Morrell & Company 648 410 1.58
Merillat Industries Inc. 135 58 2.33
Pete Lien and Sons, Inc. 276 59 4.68
Although Pete Lien and Sons, Inc. also had a Q/D of less than 10, the State did consider whether controls should be required for reasonable progress. South Dakota opted, however, not to conduct a full four-factor analysis on Pete Lien and Sons but did a general review of the impacts of this facility. Pete Lien and Sons' SO2 emissions are less than 1 ton/year and so have a de minimus impact on visibility in any Class I area. For NOX, the State has determined that the plant is already required to use what is considered Best Available Control Technology (BACT), and thus no further controls are required. As further explanation, the 2002 NOX emissions for Pete Lien and Sons were 272 tons/year. In May 2008, the company included a BACT analysis for NOX in a PSD application for a new preheater-type rotary lime kiln and ancillary equipment for this facility. The BACT analysis found non-selective catalytic reduction and selective catalytic reduction to be technically infeasible for several reasons including temperatures and the location of injection nozzles. South Dakota reviewed the application at the time and agreed with the conclusion that BACT for a lime rotary kiln was considered good combustion practices. South Dakota conducted a further review of EPA's RACT/BACT/LAER Clearinghouse to determine if any new rotary lime kilns had been permitted since Pete Lien and Sons' PSD application had been submitted with more stringent post-combustion BACT controls. There were three entries. One occurred in each of the states of Texas, Ohio, and Wisconsin. The Texas source only involved carbon monoxide. In Ohio and Wisconsin, the permitting authorities had concluded in the BACT analyses for NOX that no control technologies were cost effective and that good combustion practices were considered BACT. The State concluded there were no new rotary lime kilns that had been required to install post-combustion NOX controls for BACT. As a result, the State concluded that such controls would not constitute BART.
2002 0.05 0.06
2006 0.06 0.05
2007 0.07 0.05
We propose to approve South Dakota's less detailed analysis for Pete Lien and conclusion that no controls are required. A Q/D value of 10 is generally viewed as a conservative threshold for identifying facilities that may have significant source-specific impacts. We consider a Q/D threshold of 10 to be reasonable for this planning period based on the FLM's proposed FLAG Guidance amendments for initial screening criteria, as well as statements in EPA's BART guidelines.[19] For Pete Lien and Sons, the Q/D of 4.68 is well below this threshold; the baseline visibility impacts analysis by South Dakota in Table 14 confirms that Pete Lien and Sons does not have significant source-specific impacts.
SO2 actual average emissions 2002 (tons/yr)
NOX actual average emissions 2002 (tons/yr)
Black Hills, Ben French Power Plant Unit 1 Boiler EGU 25 MWe 785 907
GCC Dacotah Wet Kiln 4 Cement Plant 550 tons clinker/day 26 707
Wet Kiln 5 Cement Plant 550 tons clinker/day 431 388
Wet Kiln 6 1 Cement Plant 2,250 tons clinker/day 885 2,267
1 South Dakota opted not to include Kiln 6 in its four-factor analysis as further described in the State's conclusions in section III.D.3 below.
The control options and costs that South Dakota considered were derived, in part, from the EC/R report. EPA also requested South Dakota consider SNCR at GCC Dacotah which was not included in the EC/R report. For the Black Hills Ben French and GCC Dacotah reasonable progress sources, SO2 and NOX are uncontrolled, although the Black Hills Ben French facility uses low-sulfur coal (0.33 wt%) to minimize formation of SO2 during combustion.
Table 16—Control Option Costs for Reasonable Progress Source Black Hills, Ben French Power Plant 1
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
1 The cost analysis was based on a 30-year equipment life. Black Hills indicated the expected life of the Ben French power plant is 10 years. South Dakota conducted an additional analysis with a 10-year equipment life. The 10-year evaluation resulted in slightly higher average cost effectiveness values but did not change the outcome of the analysis. All controls are cost effective with the exception of the dry sorbent injection at the lowest end of the control efficiency range which would not reflect the true performance capability of the technology; we consider the high end of the range to be most appropriate.
Table 17—Control Option Costs for Reasonable Progress Source GCC Dacotah, Cement Plant 1
NOX LNB (indirect) 707 30 40 212 283 526 129 608 456
LNB (direct) 707 40 283 1,873 331 1,170
Biosolids Injection 707 23 163 2 2
CemStar 707 20 60 141 424 1,599 299 2,121 705
Mid-Kiln 707 20 50 141 354 2,748 −315 3 3
LoTOxTM 707 80 90 566 636 2 2
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
NOX LNB (indirect) 388 30 40 116 155 526 129 1,112 832
LNB (direct) 388 40 155 1,873 331 2,135
Biosolids Injection 388 23 89 2 2
CemStar 388 20 60 78 233 1,599 299 3,833 1,283
Mid-Kiln 388 20 50 78 194 2,748 −315 3 3
LoTOxTM 388 80 90 310 349 2 2
SCR 388 30 40 116 155 878 3 7,569 5,665
SNCR 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 South Dakota also did an analysis based on operating scenario with 50% fewer hours based on last five years of actual operations showing all costs would still be economical.Start Printed Page 76663
2 The EC/R report did not list a cost per ton because it did not identify any capital or annual costs.
3 South Dakota did not list a cost per ton because the annual cost was a negative number.
2002 0.21 0.22
2006 0.23 0.23
2007 0.20 0.30
2002 0.32 0.36
2006 0.32 0.36
2007 0.31 0.46
South Dakota declined to conduct a four-factor analysis for GCC Dacotah Kiln 6. In addressing a concern raised by the National Park Service [20] during the public comment period for the GCC Dacotah Cement Plant, South Dakota provided an explanation in an email to EPA regarding its decision not to include GCC Dacotah's Kiln 6 in its four-factor analysis for the facility and specifically, not to impose SNCR controls on that unit.[21] As the State explained, GCC Dacotah submitted a PSD air quality application for an upgrade to Kiln 6 in November 2001. In issuing the PSD permit in 2003, South Dakota determined NOX BACT for Kiln 6 was the installation of staged combustion with a thermal efficient in-line low-NOX calciner complimented by a LNB with indirect firing in the kiln; South Dakota found that SNCR was not technically feasible for Kiln 6. GCC Dacotah installed the required NOX BACT controls. South Dakota also determined SO2 BACT for Kiln 6 and imposed a corresponding emissions limit.
Based on (1) The results of the WRAP CMAQ modeling; (2) the results of the four-factor analysis of major South Dakota sources; and (3) the emission controls on South Dakota BART sources, South Dakota established reasonable progress goals for the most impaired days for both of South Dakota's Class I areas, as identified in Table 20 below. Also shown in Table 20 is a comparison of the reasonable progress goals to the uniform rate of progress for both Class I areas. The reasonable progress goals for the 20% worst days fall short of the uniform rate of progress by 1.28 and 1.34 deciviews for Badlands and Wind Cave, respectively.Start Printed Page 76664
RPG (WRAP projection)
Badlands National Park 17.14 15.02 16.30 40
Wind Cave National Park 15.84 13.94 15.28 29
Achieved “no degradation” (Y/N)
Badlands National Park 6.89 6.64 Y
Wind Cave National Park 5.14 5.02 Y
The WRAP Implementation Work Group was one of the primary collaboration mechanisms. South Dakota participated in WRAP and worked with other states that are not members of WRAP (including Minnesota and Nebraska) in developing its SIP. 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 with visibility impacts greater than 0.5 deciviews at a Class I area. This facility is predicted to contribute to visibility impairment at the Badlands National Park in South Dakota; Theodore Roosevelt National Park in North Dakota; Boundary Waters Canoe Area Wilderness and Voyageurs National Park in northern Minnesota and the Isle Royale National Park in Michigan. Otter Tail Power Company developed a case-by-case BART analysis that South Dakota reviewed to establish the BART emission limits for Big Stone I. The case-by-case BART analysis and South Dakota's review were submitted to the appropriate states for their comments. South Dakota established BART procedures in the Administrative Rules of South Dakota that are equivalent to Federal regulation in 40 CFR part 51 and adopted the BART emission limits and monitoring recordkeeping and reporting requirements applicable to BART-eligible coal fired power plants (which Start Printed Page 76665includes Big Stone I) in the rule. The requirements will eventually be adopted in Otter Tail Power Company's Title V air quality operating permit for the Big Stone I facility. South Dakota believes the BART requirements represent South Dakota's fair share of emission reductions for Class I areas impacted by emissions from South Dakota sources and other states provided no adverse comments.
c. On the 20 percent most impaired days, sulfate and organic carbon are the two greatest contributors to visibility impairment at both Class I areas. The four-factor analyses performed by the State show the costs for controlling SO2 at these facilities is excessive, given the minimal visibility benefits from such controls. Much of the organic carbon emissions are from natural fires that cannot be controlled.
EPA is proposing to approve the State's conclusion that no additional SO2 controls are warranted for this unit for this planning period. The cost effectiveness values range from $3,777 for a spray dryer absorber to $21,519 per ton for the least efficient dry sorbent injection option. Based on the cost effectiveness values and the minimal visibility benefits from controlling this unit, we find that South Dakota reasonably rejected additional SO2 controls during this planning period.
EPA is proposing to approve the State's conclusion that no additional NOX controls are warranted for this unit for this planning period. The cost effectiveness values range from $287 for LNB to $2,942 per ton for SCR. Some of these costs are reasonable. However, South Dakota also considered the visibility impacts—it modeled visibility impacts of 0.23 deciviews at Badlands and 0.30 deciviews at Wind Cave from all emissions from the source—and any visibility improvement that would result from additional NOX controls alone would be significantly less than these values. When the costs are weighed against visibility improvement, South Dakota's determination that additional controls of NOX are not warranted in this planning period is reasonable, and we are proposing to approve it.
EPA is proposing to approve the State's conclusion that no additional SO2 controls are warranted for Kilns 4 and 5 for this planning period. The cost effectiveness values for a new wet FGD system range from $52,692 to $59,565 per ton on Kiln 4 and from $3,208 to $3,531 per ton on Kiln 5. Based on the cost effectiveness values and South Dakota's modeling of baseline visibility impacts from Kilns 4 and 5, we find that South Dakota reasonably rejected additional SO2 controls during this planning period.
EPA is proposing to approve the State's conclusion that no additional NOX controls for Kilns 4 and 5 are reasonable for this planning period. For Kiln 4, the cost effectiveness values range from $456 per ton for LNB to $7,309 per ton for SCR. For Kiln 5 the cost effectiveness values range from $832 per ton for LNB to $13,345 per ton for SCR. Some of these costs are reasonable. However, South Dakota modeled the baseline visibility impacts from Kilns 4 and 5 combined—0.32 deciviews at Badlands and 0.46 at Wind Cave—and any visibility benefits that would result from additional NOX controls alone would be significantly less than these values. We therefore propose to find that South Dakota reasonably rejected additional NOX controls during this planning period.
EPA is also proposing to approve the State's determination that no additional NOX or SO2 controls are required on Kiln 6. During this planning period, it is reasonable for the State to rely on the relatively recent NOX and SO2 BACT determinations in the 2003 PSD permit for Kiln 6. However, during the next Start Printed Page 76666planning period, the State should reconsider these determinations.
Emissions within South Dakota are both naturally occurring and man-made. Two primary sources of naturally occurring emissions include wildfires and windblown dust. In South Dakota, the primary sources of anthropogenic emissions include electric utility steam generating units, energy production and processing sources, agricultural production and processing sources, prescribed burning, and fugitive dust sources. The South Dakota inventory includes emissions of SO2, NOX, PM2.5, PM10, primary organic aerosol, elemental carbon, VOCs, NH3, and CO. See Section 5 of the SIP.
An emissions inventory for each pollutant was developed by WRAP for South Dakota for the baseline year 2002 and for 2018, which is the first reasonable progress milestone.[22] The 2018 emissions inventory was developed by projecting 2002 emissions and applying reductions expected from Federal and state regulations. The emission inventories developed by WRAP were calculated using approved EPA methods.
There are 10 different emission inventory source categories identified in the South Dakota regional haze Plan: point, area, oil and gas, on-road, off-road, all fire, biogenic, road dust, fugitive dust and windblown dust. Tables 22 through 30 show the 2002 baseline emissions, the 2018 projected emissions, and net changes of emissions for SO2, NOX, primary organic aerosol, elemental carbon, PM2.5, PM10, NH3, VOC and carbon monoxide (CO) by source category in South Dakota. The methods that WRAP used to develop these emission inventories are described in more detail in Section 5 of the SIP and in the EPA WRAP Technical Support Document (TSD).
Table 22—South Dakota SO2 Emission Inventory—2002 and 2018 1
South Dakota Statewide SO2 Emissions [Tons/year]
Point 14,037 11,996 −2,041 −15
Big Stone I 2 11,171 3,425 −7,746 −69
All Fire 469 465 −4 −1
Biogenic 0 0 0 0
Area 1,198 1,789 591 49
Oil and Gas 6 0 −6 −100
On-Road Mobile 922 129 −793 −86
Off-Road Mobile 6,066 199 −5,867 −97
Road Dust 4 5 1 25
Fugitive Dust 24 26 2 8
Wind Blown Dust 0 0 0 0
Total 22,726 14,609 −8,117 −36
1 SO2 emissions shown include both gas and particulate.
2 Otter Tail Power Company's Big Stone I emissions are included in the “Point” emissions but separated for comparison.
In 2018, South Dakota's sulfate contribution switched 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. Start Printed Page 76667
Table 23—South Dakota NOX Emission Inventory—2002 and 2018 1
South Dakota Statewide NOX Emissions [Tons/year]
Point 20,699 30,186 9,487 46
Big Stone I 2 14,552 15,323 771 5
All Fire 1,713 1,694 −19 −1
Biogenic 52,852 52,852 0 0
Area 2,903 3,309 406 14
Oil and Gas 361 557 196 54
On-Road Mobile 29,224 8,059 −21,165 −72
Off-Road Mobile 39,039 23,785 −15,254 −39
Road Dust 5 6 1 20
Fugitive Dust 27 27 0 0
Total 146,823 120,475 −26,348 −18
1 NOX emissions shown include both gas and particulate.
2 Otter Tail Power Company's Big Stone I emissions are included in the “Point” emissions row but separated for comparison.
Table 24—South Dakota Primary Organic Aerosol Emission Inventory—2002 and 2018
Point 10 8 −2 −20
Big Stone I 1 0 0 0
All Fire 4,574 4,531 −43 −1
Area 1,792 1,769 −23 −1
On-Road Mobile 278 270 −8 −3
Off-Road Mobile 942 386 −556 −59
Road Dust 255 325 70 27
Fugitive Dust 1,317 1,322 5 0
Total 9,168 8,611 −557 −6
1 Otter Tail Power Company's Big Stone I emissions are included in the “Point” emissions but separated for comparison.
Table 25—South Dakota Elemental Carbon Emission Inventory—2002 and 2018
All Fire 717 715 −2 0
Area 306 314 8 0
Area Oil and Gas 0 0 0 0
On-Road Mobile 339 86 −253 −75
Off-Road Mobile 3,234 1,072 −2,162 −67
Road Dust 18 23 5 28
Fugitive Dust 89 90 1 1
Wind Blown Dust 0 89 89 *
Total 4,703 2,389 −2,314 −49
* Greater than 100.
As detailed in Tables 26 and 27, the primary sources of PM (both PM2.5 and PM10) are road, fugitive and windblown dust (agriculture, construction, and unpaved and paved roads). Start Printed Page 76668
Table 26—South Dakota PM2.5 Emission Inventory—2002 and 2018
South Dakota Statewide PM2.5 Emissions [Tons/year]
Point 216 205 −11 −5
Big Stone I 1 209 0 −209 −100
All Fire 839 821 −18 −2
Area 1,804 1,920 116 6
On-Road Mobile 0 0 0 0
Off-Road Mobile 0 0 0 0
Road Dust 4,061 5,190 1,129 28
Fugitive Dust 25,220 25,840 620 2
Wind Blown Dust 50,274 50,274 0 0
Total 82,414 84,250 −11 −5
Table 27—South Dakota PM10 Emission Inventory—2002 and 2018
South Dakota Statewide PM10 Emissions [Tons/year]
Point 727 9,847 9,120 *
Big Stone I 1 209 318 109 52
All Fire 754 751 −3 0
Area 156 190 34 22
On-Road Mobile 169 188 19 0
Road Dust 38,164 48,773 10,609 28
Fugitive Dust 122,914 129,009 6,095 5
Wind Blown Dust 452,470 452,470 0 0
Total 615,354 641,228 25,874 4
Table 28—South Dakota NH3 Emission Inventory—2002 and 2018
South Dakota Statewide NH3 Emissions [Tons/year]
Point 100 102 2 2
Big Stone I 1 29 0 −29 −100
All Fire 562 553 −9 −2
Area 118,877 118,992 115 0
On-Road Mobile 842 1,075 233 0
Off-Road Mobile 25 36 11 0
Road Dust 0 0 0 0
Fugitive Dust 0 0 0 0
Total 120,406 120,758 352 0
Point 2,542 4,510 1,968 77
Big Stone I 1 107 112 5 5
All Fire 3,853 3,808 −45 −1
Biogenic 445,241 445,241 0 0
Area 40,511 49,659 9,148 23
Area Oil and Gas 33,721 562 −33,159 0
On-Road Mobile 13,741 5,101 −8,640 0
Off-Road Mobile 12,764 7,686 −5,078 0
Total 552,373 516,567 −35,806 −6
Point 4,700 16,632 11,932 *
Big Stone I 1 490 509 19 4
All Fire 64,326 63,843 −483 −1
Biogenic 103,402 103,402 0 0
Area 23,029 23,773 744 3
Area Oil and Gas 11 16 5 0
On-Road Mobile 221,726 120,041 −101,685 0
Off-Road Mobile 92,508 95,276 2,768 0
Total 509,702 422,983 −86,719 −17
In order to determine the significant sources contributing to haze in South Dakota's Class I areas, South Dakota relied upon two source apportionment analysis techniques developed by the WRAP. The first technique was regional modeling using the Comprehensive Air Quality Model (CAMx) and the PM Source Apportionment Technology (PSAT) tool, used for the attribution of sulfate and nitrate sources only. The second technique was the Weighted Emissions Potential (WEP) tool, used for attribution of sources of organic carbon, elemental carbon, PM2.5 and PM10. The WEP tool is based on emissions and residence time, not modeling.
PSAT uses the CAMx air quality model to show nitrate-sulfate-ammonia chemistry and apply this chemistry to a system of tracers or “tags” to track the chemical transformations, transport, and removal of NOX and SO2. These two pollutants are important because they tend to originate from anthropogenic 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.
WEP is a screening tool that helps to identify source regions that have the potential to contribute to haze formation at specific Class I areas. Unlike PSAT, this method does not account for chemistry or deposition. The WEP combines emissions inventories, wind patterns and residence times of air masses over each area where emissions occur, to estimate the percent contribution of different pollutants. Like PSAT, the WEP tool compares baseline values (2000-2004) to 2018 values, to show the improvement expected by 2018, for sulfate, nitrate, organic carbon, elemental carbon, PM2.5 and PM10. More information on the WRAP modeling methodologies is available in the EPA WRAP TSD.
The Regional Modeling Center (RMC) at the University of California Riverside, under the oversight of the WRAP Modeling Forum, performed modeling for the regional haze LTS for the WRAP member states, including South Dakota. The modeling analysis is a complex technical evaluation that began with selection of the modeling system. The RMC primarily used the CMAQ Start Printed Page 76670photochemical grid model to estimate 2018 visibility conditions in South Dakota and all western Class I areas, based on application of the regional haze strategies in the various state plans, including assumed controls on BART sources.
The RMC developed air quality modeling inputs, including annual meteorology and emissions inventories for: (1) A 2002 actual emissions base case; (2) a planning case to represent the 2000-2004 regional haze baseline period using averages for key emissions categories; and (3) a 2018 base case of projected emissions determined using factors known at the end of 2005. All emission inventories were spatially and temporally allocated using the 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 WRAP states' modeling was developed in accordance with our guidance.[23] A more detailed description of the CMAQ modeling performed for the WRAP can be found in Section 5 of the SIP and in the EPA WRAP TSD.
40 CFR 51.308(d)(3)(i) requires that South Dakota consult with another state if its emissions are reasonably anticipated to contribute to visibility impairment in that state's Class I area(s), and that South Dakota consult with other states if those other states' emissions are reasonably anticipated to contribute to visibility impairment at Badlands or Wind Cave. South Dakota's consultations with other states are described in section III.D.5 above. After evaluating whether emissions from South Dakota sources contribute to visibility impairment in other states' Class I areas, South Dakota concluded that Otter Tail Power Company's Big Stone I facility was the only source in South Dakota that is reasonably anticipated to contribute to visibility impairment of a Class I are in another state. South Dakota's evaluation relied upon NOX and SO2 BART and reasonable progress reductions as described in the SIP. South Dakota did consult with other states and tribes, largely through the WRAP process, in order to meet the regulatory requirements. South Dakota also worked with states that are not members of WRAP including Minnesota and Nebraska.
The two primary regulatory tools for addressing visibility impairment from industrial sources are BART and the PSD New Source Review rules. The PSD rules protect visibility in Class I areas from new industrial sources and major changes to existing sources. South Dakota's Air Pollution Control Rules (ARSD Chapter 74:36) contain requirements for visibility impact assessment and mitigation associated with emissions from new and modified major stationary sources. A primary responsibility of South Dakota under these rules is visibility protection. Chapter 74:36:09 and 74:36:10 describes mechanisms for visibility impact assessment and review by South Dakota, as well as impact modeling methods and requirements. Typically, this modeling is conducted for sources Start Printed Page 76671within 300 kilometers of a Class I area. South Dakota will not issue an air quality permit to any new major source or major modification within this distance that is found through modeling to cause significant visibility impairment, unless the impact is mitigated.
Mobile source annual emissions show a major decrease in NOX in South Dakota from 2002 to 2018. See Table 23 above. This reduction will result from numerous “on the books” Federal mobile source regulations. This trend is expected to provide significant visibility benefits. Beginning in 2006, EPA mandated new standards for on-road (highway) diesel fuel, known as ultra-low sulfur diesel. This regulation dropped the sulfur content of diesel fuel from 500 parts per million (ppm) to 15 ppm. Ultra-low sulfur diesel fuel enables the use of cleaner technology diesel engines and vehicles with advanced emissions control devices, resulting in significantly lower emissions.
40 CFR 51.308(d)(3)(v)(F) of the Regional Haze Rule requires states to ensure that emission limitations and control measures used to meet reasonable progress goals are enforceable. In addition to what is required by the Regional Haze Rule, general SIP requirements mandate that the SIP must also include adequate monitoring, recordkeeping, and reporting requirements for the regional haze emission limits and requirements. See CAA section 110(a). As noted, the SIP specifies BART emission limits and compliance schedules, and South Dakota has included such limits and compliance schedules in the state regional haze rule, ARSD 74:36:21, included in the regional haze SIP we are proposing to approve. These emission limits apply at all times, including periods of startup, shutdown, and Start Printed Page 76672malfunction.[24] In addition to specifying the limits and compliance schedules, the state rule specifies monitoring, recordkeeping and reporting requirements. South Dakota worked closely with EPA in developing these requirements. For SO2 and NOX limits, South Dakota has required the use of CEMS that must be operated and maintained in accordance with relevant EPA regulations, in particular, 40 CFR part 75. For PM limits, the SIP requires testing in accordance with EPA-approved test methods. The SIP requires that relevant records be kept for five years, and that sources report excess emissions on a quarterly basis.
Under 40 CFR 51.308(i)(2), South Dakota was obligated to provide National Park Service with an opportunity for consultation, in person and at least 60 days prior to holding a public hearing on the Regional Haze SIP. South Dakota sent a draft of its Regional Haze SIP to the National Park Service and other FLMs on January 15, 2010. South Dakota held a public hearing in front of the Board of Minerals and Environment on September 15, 2010. In July 2011, South Dakota provided the FLMs and others a draft of proposed amendments to the Regional Haze SIP. The FLMs provided comments to South Dakota's amended Start Printed Page 76673submittal. The State held another public hearing on August 18, 2011.
5. Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule, September 2003, EPA-454/B-03-005, available at http://www.epa.gov/​ttncaaa1/​t1/​memoranda/​RegionalHaze _envcurhr_gd.pdf, (hereinafter referred to as “our 2003 Natural Visibility Guidance”); and Guidance for Tracking Progress Under the Regional Haze Rule, (September 2003, EPA-454/B-03-004, available at http://www.epa.gov/​ttncaaa1/​t1/​memoranda/​rh_​tpurhr_​gd.pdf, (hereinafter referred to as our “2003 Tracking Progress Guidance”).
10. The science behind the revised IMPROVE equation is summarized in a document entitled, Technical Support Document for Technical Products Prepared by the Western Regional Air Partnership (WRAP) in Support of Western Regional Haze Plans, February 28, 2011, (hereinafter referred to as EPA WRAP Technical Support Document and available in the docket) and in numerous published papers. See for example: Hand, J.L., and Malm, W.C., 2006, Review of the IMPROVE Equation for Estimating Ambient Light Extinction Coefficients—Final Report. March 2006. Prepared for IMPROVE, Colorado State University, Cooperative Institute for Research in the Atmosphere, Fort Collins, Colorado, available at http://vista.cira.colostate.edu/​improve/​publications/​GrayLit/​016_​IMPROVEeqReview/​IMPROVEeqReview.htmand Pitchford, Marc., 2006, Natural Haze Levels II: Application of the New IMPROVE Algorithm to Natural Species Concentrations Estimates. Final Report of the Natural Haze Levels II Committee to the RPO Monitoring/Data Analysis Workgroup. September 2006, available at http://vista.cira.colostate.edu/​improve/​Publications/​GrayLit/​029_​NaturalCondII/​naturalhazelevelsIIreport.ppt.
11. The amount of light lost as it travels over one million meters. The haze index, in units of dv, is calculated directly from the total light extinction, bext expressed in inverse megameters (Mm−1), as follows: HI = 10 ln(bext/10).
12. Note that our reference to CALPUFF encompasses the entire CALPUFF modeling system, which includes the CALMET, CALPUFF, and CALPOST models and other pre and post processors. The different versions of CALPUFF have corresponding versions of CALMET, CALPOST, etc. which may not be compatible with previous versions (e.g., the output from a newer version of CALMET may not be compatible with an older version of CALPUFF). The different versions of the CALPUFF modeling system are available from the model developer at http://www.src.com/​verio/​download/​download.htm.
13. The WRAP modeling protocol is available at http://pah.cert.ucr.edu/​aqm/​308/​bart/​WRAP_​RMC_​BART_​Protocol_​Aug15_​2006.pdf.
16. The selected SO2 emission limit of 0.09 lb/MMBtu (30-day rolling average) also happens to be well below the presumptive limit for EGU's without existing controls and over the 750 MW generating capacity threshold described in the BART Guidelines.
19. The relevant language in our BART Guidelines reads, “Based on our analyses, we believe that a state that has established 0.5 dv as a contribution threshold could reasonably exempt from the BART review process sources that emit less than 500 tons per year of NOX or SO2 (or combined NOX and SO2), as long as these sources are located more than 50 kilometers from any Class I area; and sources that emit less than 1000 tons per year of NOX or SO2 (or combined NOX and SO2) that are located more than 100 kilometers from any Class I area.” (See 40 CFR 51, appendix Y, section III, How to Identify Sources “Subject to BART.”) The values described equate to a Q/D of 10.
22. These inventories, in addition to being available in Section 5 of the SIP, are also available at http://vista.cira.colostate.edu/​TSS/​Results/​HazePlanning.aspx.
23. Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, and Regional Haze, (EPA-454/B-07-002), April 2007, located at http://www.epa.gov/​scram001/​guidance/​guide/​final-03-p.m.-rh-guidance.pdf Emissions Inventory Guidance for Implementation of Ozone and Particulate Matter National Ambient Air Quality Standards (NAAQS) and Regional Haze Regulations, August 2005, updated November 2005 (“our Modeling Guidance”), located at http://www.epa.gov/​ttnchie1/​eidocs/​eiguid/​index.html, EPA-454/R-05-001.