SOUTH DAKOTA’S 

 REGIONAL HAZE 

 STATE IMPLEMENTATION PLAN 

RESPONSE TO COMMENTS 

DURING PUBLIC NOTICE 

South Dakota Department of Environment and Natural Resources

 
Table of Contents 

 Page 

 ii 

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

2.0 EPA’s Comments............................................................................................1

3.0 Sierra Club’s Comments................................................................................7

4.0 Otter Tail Power Company’s Comments ...................................................17
 1 

1.0 Introduction 

DENR public noticed South Dakota’s Regional Haze Program for public comments on or before 

August, 26, 2010. South Dakota’s Regional Haze Program consists of “South Dakota’s Regional 

Haze State Implementation Plan” which addresses the federal requirements in 40 Code of 

Federal Regulations (CFR), Part 51, Section 308 and the proposed rule changes that incorporate 

the Best Available Control Technology requirements. On September 15, 2010, a public hearing 

in front of the Board of Minerals and Environment was held to take testimony on South Dakota’s 

Regional Haze Program. 

DENR received comments from the United States Environmental Protection Agency (EPA) – 

Region 8; the Sierra Club, National Parks Conservation Association and Plains Justice, 

hereinafter referred to as the Sierra Club; and Otter Tail Power Company. The comments 

without attachments may be viewed in Appendix A. 

This document contains a summary of the comment and DENR’s responses to the comments 

received during the public notice period. 

2.0 EPA’s Comments 

1. Additional details are necessary to ensure BART emission limits will be enforceable as a 

practical matter. The BART emission limits, compliance schedule, monitoring, 

recordkeeping, and compliance determining methods for Big Stone I must be specified in the 

text of the Regional Haze State Implementation Plan or in a permit that is incorporated into 

the State Implementation Plan. For example, in your response to our comment on this issue 

(#1 and #39 from Appendix D), you relied heavily on requirements of your Title V program 

(ARSD 74:36:05). As this program is not part of the State Implementation Plan, our 

concerns with reliance on the Title V program in this area remain. EPA provided examples 

from Colorado and Wyoming. 

Response: DENR believes it already satisfied EPA’s concerns involving the enforceability 

of the BART emission limits, compliance schedules, monitoring, recordkeeping, and 

compliance determining methods as outlined in Appendix D of South Dakota’s Regional 

Haze State Implementation Plan. EPA’s initial comments noted BART needed to be 

specified as part of South Dakota’s State Implementation Plan or the BART requirements 

need to be incorporated in a permit that is incorporated in South Dakota’s State 

Implementation Plan. DENR decided to include the BART requirements as part of its State 

Implementation Plan. 

DENR drafted rules in the Administrative Rules of South Dakota (ARSD), Chapter 74:36:21 

and the Board of Minerals and Environment unanimously approved the rules during the 

public hearing on September 15, 2010. The final rules will be submitted to EPA for approval 

in South Dakota’s Regional Haze State Implementation Plan. 
 2 

DENR adopted the BART emission limits in ARSD § 74:36:21:06 – BART determination 

for a BART-eligible coal fired power plant. This section also specifies the method of 

determining compliance for each air pollutant. The section requires an annual performance 

test be conducted to determine compliance with the particulate matter BART emission limit 

based on the average of three 1-hour test runs and a continuous emission monitoring system 

to determine compliance with the sulfur dioxide and nitrogen oxide BART emission limits 

based on a 30-day rolling average. The performance test for particulate matter is based on 

South Dakota’s existing State Implementation Plan which adopts federal performance testing 

requirements by reference in 40 CFR Part 60, Appendix A, 40 CFR Part 63 Appendix A, and 

40 CFR Part 51, Appendix M. South Dakota’s existing State Implementation Plan also 

includes the specific requirements on monitoring and recordkeeping associated with 

continuous emission monitoring systems. These requirements are identified in ARSD 

Chapter 74:36:11 and 74:36:13 and are identified by EPA as being part of South Dakota’s 

State Implementation Plan in 40 CFR § 52.2170. 

In accordance with 40 CFR § 308(1)(e)(1)(iv), DENR identified Otter Tail Power Company 

must install BART on Big Stone I as expeditiously as practicable, but no later than 5 years 

from EPA’s approval of South Dakota’s Regional Haze State Implementation Plan. EPA may 

observe the compliance schedule in ARSD § 74:36:21:07 – Installation of controls based on 

visibility impact analysis or BART determination. This section specifies BART must be 

installed, operated, and complied with as expeditiously as practicable; but no later than five 

years from EPA’s approval of South Dakota’s Regional Haze State Implementation Plan. 

EPA may observe the operation and maintenance requirements for air pollution control 

devices and the monitoring, recordkeeping, and reporting requirements for determining 

compliance with the BART emission limits in ARSD § 74:36:21:08 – Operation and 

maintenance of controls and ARSD § 74:36:21:09 – Monitoring, recordkeeping, and 

reporting. The continuous emission monitoring requirements reference ARSD Chapter 

74:36:13 which is part South Dakota’s State Implementation Plan and the monitoring, 

recordkeeping and reporting requirements reference the appropriate sections in South 

Dakota’s Title V air quality permit program which is approved by EPA. 

Otter Tail Power Company is also required to meet other independent requirements under 

ARSD Chapter 74:36:16 – Acid Rain Program. South Dakota’s continuous emission 

monitoring requirements for the Acid Rain program are the same as EPA’s (40 CFR Part 75). 

40 CFR Part 75 specifies monitoring provisions, operation and maintenance requirements, 

missing data substitution procedures, recordkeeping and reporting requirements for the 

monitored data.

EPA repeats its concern that DENR references South Dakota’s EPA approved Title V air 

quality permit program for implementing the BART requirements. As discussed above, the 

BART limits, recordkeeping, monitoring, compliance schedules, etc. are either already part 

of South Dakota’s State Implementation Plan or will be once EPA approves ARSD Chapter 

74:36:21. The rules are designed to fit within South Dakota’s current established rules and 

regulations. DENR is clarifying and acknowledging the BART requirements are required to 

be incorporated in Otter Tail Power Company’s Title V air quality permit. Some of which are 
 3 

already established in Otter Tail Power Company’s current Title V air quality permit 

#28.0801-29 such as recordkeeping, reporting, and monitoring requirements associated with 

performance tests and continuous emission monitoring systems. 

DENR believes EPA’s concerns are addressed in South Dakota’s Regional Haze State 

Implementation Plan which includes ARSD Chapter 74:36:21 and will be submitted to EPA 

for approval in South Dakota’s State Implementation Plan. 

2. EPA states footnote 5 references a 1999 EPA Technical Bulletin on nitrogen oxide controls 

as justification for the 35% to 90% control efficiency range for the top three options. The 

large range in EPA’s bulletin is due to inclusion of selective catalytic reduction (SCR), 

selective non-catalytic reduction (SNCR), and fuel re-burning for wet-bottom boilers. EPA 

states it is well documented that a SCR achieves the high end of the range. Therefore, the 

proposed BART determination of SCR plus separated over-fire air (SOFA) should be better 

than the 90% control efficiency of SCR alone. In our response to this comment (#31 from 

Appendix D), EPA indicates there was no discussion regarding how the addition of SOFA 

would not contribute to a better than 90% control efficiency. EPA indicated our response to 

this comment (#31 from Appendix D) previously did not discuss how the addition of the 

separated over-fire air would not contribute to a better than 90% efficiency and would like 

this addressed. 

Response: DENR believes it has addressed this issue in its initial response outlined in 

Appendix D of South Dakota’s Regional Haze State Implementation Plan. As discussed 

previously, DENR considers the control efficiency of a control device to be variable and it is 

inappropriate to take an arbitrary emission rate Otter Tail Power Company actually emitted 

and multiply it by an arbitrary control efficiency to establish an air emission limit. This 

concept does not change if one is looking at just the addition of a selective catalytic reduction 

system or a combination of separated over-fire air and a selective catalytic reduction system. 

DENR provided examples by EPA that agree with this concept from technical documents to 

EPA’s regulations. 

Also discussed in Appendix D, none of the documents identified or provided by EPA identify 

under what operating conditions these control efficiencies will occur (e.g., low, mid or high 

loads); the time period for demonstrating compliance (e.g., hourly or 30-day average 

emission rate); or the inlet pollutant loading rate. Therefore, one does not know if these cited 

control efficiencies are based on systems that have or do not have specific combustion 

controls (e.g. low nitrogen oxide burners, over-fire air systems, flue gas recirculation). 

Without knowing this information, the information provided by EPA does not support their 

claim that a selective catalytic reduction system will obtain 90% control efficiency at any 

inlet concentration loading to the selective catalytic reduction system. 

The selective catalytic reduction system is a nitrogen oxide control technology utilizing the 

injection of a nitrogen-based reagent, such as ammonia or urea, in combination with a 

precious metal catalyst to reduce nitrogen to molecular nitrogen. The catalyst provides a 

substrate for reaction and reduces the required reaction temperatures. The selective catalytic 

reduction system is typically operated from 650 to 750°F. Large deviations from this 
 4 

temperature range will significantly impact the nitrogen oxide control efficiency. Ammonia 

injection rates also impacts the nitrogen oxide control efficiency. Increased molar ratio of 

ammonia to nitrogen oxide results in enhanced nitrogen oxide reduction but increased 

ammonia slip from the selective catalytic reduction system. Over-fired air is a nitrogen oxide 

control technology that controls the amount of oxygen and flame temperature in the 

combustion zone reducing the formation of thermal nitrogen oxide. Separated over-fire air 

(SOFA) is an air-staging nitrogen oxide reduction technique that is usually based on 

withholding 15 to 20 percent of the total combustion air conventionally supplied to the firing 

zone. The selective catalytic reduction system must be installed with the constraints of an 

existing coal fired boiler. As such, Otter Tail Power Company may not be able to locate the 

selective catalytic reduction system in the most ideal and optimal location. Combining 

combustion controls (SOFA) and post-combustion controls (SCR) allows the facility to meet 

BART limits within the limit/confines of the identified control options. 

It should be noted that in the October 19, 2010, federal register notice, EPA is proposing to 

require a selective catalytic reduction system be installed on the five units at the Four 

Corners Power Plant located on the Navajo Nation. EPA is proposing the Four Corners 

Power Plant must meet a BART plantwide emission limit of 0.011 pounds per million Btus, 

which EPA notes represents an 80% reduction in nitrogen oxide emissions. Both the 

emission rate and specified efficiency are less stringent than that being required for Otter Tail 

Power Company. EPA acknowledges in its own BART analysis for the Four Corners Power 

Plant that the review needs to be conducted on a case-by-case analysis and the emission rates 

have to be achievable for the facility being reviewed. 

DENR conducted a case-by-case BART analysis of Otter Tail Power Company’s facility and 

determined the nitrogen oxide BART emission limit is 0.10 pounds per million Btu using a 

selective catalytic reduction and separate over-fire air system. 

3. In order for EPA to accept the establishment of separate BART limits for startup and 

shutdown condition versus normal operation, an adequate record showing that the otherwise 

applicable limits are not achievable and separate startup and shutdown limits constitute 

BART is required as justification. EPA indicated that DENR’s previous response to this 

comment did not provide sufficient justification for separate startup and shutdown limits. 

Response: As defined in 40 CFR § 51.301, Best Available Retrofit Technology (BART) 

means 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 non-air 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. DENR disagrees with EPA that the BART 

emission limits must be in pounds per million Btus because the rule does not specify the 

units. The rule simply states the emission limits must be established on a case-by-case basis. 
 5 

When comparing control technology’s and emission limits across or within industrial sectors 

a generalized emission rate is used. The generalized emission rate such as a pound per 

million Btus allows emission rates across boilers of varying sizes to be compared. A pound 

per hour emission rate is difficult to compare from one boiler to the next if the heat input of 

the boilers are not identical. Whereas, the pound per hour emission rate is a case-by-case 

emission limit and is specific to an emission unit. DENR established a pound per hour BART 

emission limit for particulate mater, sulfur dioxide, and nitrogen oxide to represent BART 

since DENR used the hourly limits in the modeling analysis to demonstrate Otter Tail Power 

Company was not causing visibility impairment in a Class I area. The pounds per hour 

BART emission limits cover all normal operations including startup and shutdown. 

At Otter Tail Power Company’s listed maximum capacity the pounds per hour and pounds 

per million Btus BART emission limits are equivalent as noted by Equations 1-1. 

Substituting the “Emission Limit (pounds per million Btus)” and “Maximum Capacity 

(million Btus per hour)” from Table 1-1 into Equation 1-1 provides the BART emission 

limits in ARSD § 74:36:21:06 and also listed in the fourth column of Table 1-1. 

Equation 1-1 – Converting from “pounds per MMBtus” to “pounds per hour” 

⎟

⎠

⎞ ⎜

⎝

⎛ ⎟ =

⎠

⎞ ⎜

⎝

⎛ ⎟ ×

⎠

⎞ ⎜

⎝

⎛

hour

pounds Emission Limit

hour

MMBtus Maximum Capacity MMBtuspounds Emission Limit

Table 1-1 – BART Emission Limit Comparison 

BART Emission Limit Maximum Capacity BART Emission Limit 

Pollutant (pounds/MMBtus) (MMBtus/hour) (pounds/hour) 

Particulate Matter 0.012 5,609 67.3 

Sulfur Dioxide 0.09 5,609 505 

Nitrogen Oxides 0.10 5,609 561 

During the public hearing on South Dakota’s Regional Haze State Implementation Plan, the 

Board of Minerals and Environment revised the particulate pounds per million Btus limit in 

ARSD 74:36:21:06(2) to cover all operations including startup and shutdown based on 

previous testimony from Otter Tail Power Company. Otter Tail Power Company had testified 

the baghouse would be in operation prior to starting up the boiler and could meet the pounds 

per million Btus limit even during startup and shutdown. 

4. In accordance with ARSD 74:36:21:11, a permit to construct is required to include the 

controls, emission limits, monitoring, recordkeeping, and reporting requirements identified in 

the BART determination and approved by DENR. EPA states without seeing the details of 

such permit; it is difficult to determine whether this section of the SIP adequately addresses 

the requirements for enforceability, including appropriate averaging times, compliance 

verification procedures, and recordkeeping and reporting requirements, and proper operation 

and maintenance procedures. 

Response: DENR discusses this in the written portion of South Dakota’s Regional Haze 

State Implementation Plan and as we responded in response to Comment #1, DENR adopted 
 6 

these requirements in ARSD Chapter 74:36:21. The requirements in ARSD Chapter 74:36:21 

will be submitted as part of South Dakota’s State Implementation Plan and included in the 

permit to construct and eventually in the Title V air quality permit as applicable 

requirements. 

DENR believes it has already satisfied EPA’s concerns involving the enforceability of the 

BART emission limits, compliance schedules, monitoring, recordkeeping, and compliance 

determining methods. 

5. EPA stated the public must be provided a calculation of the number of years required to 

reach natural conditions if the Reasonable Progress Goal provides a slower rate of 

improvement than that needed to attain natural conditions by 2064 per 40 CFR 

§51.308(d)(1)(ii). Although DENR indicates the goal of reaching natural visibility by 2064 

is still achievable, EPA believes the modeling results does not support DENR’s conclusion 

and is requesting that we identify when the current evidence indicates natural conditions will 

be achieved. 

Response: Although DENR believes it will achieve natural conditions by 2064, DENR will 

project when WRAP’s modeling depicts natural conditions will be achieved in South 

Dakota’s Regional Haze State Implementation Plan. 

6. Despite the fact that South Dakota’s sulfur dioxide and nitrogen oxide emissions from point 

sources represent 1.5% and 4% of the contribution from point sources on our two Class I 

areas, respectively, EPA believes a four factor analysis is still required for GCC Dacotah, 

Black Hills Corporation (Ben French), and Pete Lien and Sons. 

Response: Although DENR demonstrated in the original response to EPA’s comment that 

South Dakota’s sulfur dioxide and nitrogen oxide contributions to visibility impairment in the 

Class I areas is minimal based on WRAP’s modeling, DENR will conduct a four factor 

analysis on GCC Dacotah, Black Hills Corporation (Ben French), and Pete Lien and Sons. 

7. EPA states the BART requirements need to be incorporated in the state implementation plan 

and does not believe it appropriate for DENR to rely on the construction permit since EPA 

has not been approved in our State Implementation Plan yet. 

Response: DENR addressed this in Comment #1. 

8. EPA reiterated Comment #5 involving the recalculation of when South Dakota plans on 

achieving natural visibility and would like the year recalculated. 

Response: DENR addressed this in Comment #5. 

9. EPA stated federal land managers must be provided a 60-day consultation period prior to any 

public hearing on the regional haze state implementation plan. Since the BART permit is an 

integral part of the Regional Haze state implementation plan, the 60-day consultation period 
 7 

must extend to the federal land managers’ BART permit review as well. EPA did not believe 

our response to this comment earlier addressed their concern. 

Response: Again, South Dakota’s draft Regional Haze State Implementation Plan was 

submitted to the federal land managers on January 15, 2010, which included the BART 

determination and requirements. DENR adopted those requirements in ARSD 74:36:21 to be 

submitted as part of the state implementation plan. 

DENR revised ARSD 74:36:21:12 to state federal land managers will have 60 days to submit 

an analysis on a BART determination or by the end of the public participation process, 

whichever is later. However, DENR believes this is a mute point since the federal land 

managers were provided 8 months to provide comments on the BART determination and 

requirements. 

DENR believes the federal managers had over 60 days to review the BART requirements 

specified in South Dakota’s draft Regional Haze state implementation plan. DENR 

established EPA’s comment in ARSD 74:36:21 which will be submitted as part of South 

Dakota’s Regional Haze State Implementation Plan. 

3.0 Sierra Club’s Comments 

10. South Dakota’s draft regional haze plan states that, because Big Stone I has a generating 

capacity less than 750 megawatts, the state is not required to follow the BART Guidelines in 

40 CFR Part 51, Subpart Y. South Dakota Draft Regional Haze Plan at 82. Specifically, the 

South Dakota Regional Haze Plan states “...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.” While the Federal regional haze regulations 

mandate that BART for units of 750 megawatts or greater must follow the BART Guidelines, 

the fact that Big Stone I has a generating capacity less than 750 megawatts does not mean 

South Dakota does not have to follow a reasoned analysis in evaluating BART and setting 

BART emission limitations. Thus, there is no justification for the state to ignore the fact that 

pollution controls can be designed and operated at varying levels of control efficiency. If the 

state does not consider the capabilities of the various pollution controls evaluated in the case 

by case BART analysis, its cost impacts analysis will be skewed in favor of the lowest capital 

cost equipment rather than properly evaluating cost impacts in terms of amount of pollution 

reduced. Thus, South Dakota must consider the varying levels of control efficiency of 

pollution controls in the BART analyses for Big Stone. 

Response: The Sierra Club appears to be singling out a specific sentence and not reading the 

entire BART determination on how DENR decided on the case-by-case BART emission 

limits. As noted on page 82 of the South Dakota’s Regional Haze State Implementation 

Plan, DENR identified that “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, 
 8 

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.” This approach allowed 

DENR to remove the infeasible technology in Step 2 before considering the permutations of 

the varying control efficiencies that were used to rank the control options in Step 3. 

Based on the cost analysis for both the dry and wet scrubber technology discussed to control 

sulfur dioxide emissions, the capital cost of the scrubbers did not change with the varying 

level of control efficiencies. There would be operational and maintenance costs; but the cost 

differences would be insignificant. As such, Sierra Clubs’ comment that the cost impacts 

would be skewed in favor of the lowest capital cost equipment did not occur. 

11. The Sierra Club believes the BART analysis for sulfur dioxide is flawed because DENR 

based the analysis on coal with higher uncontrolled sulfur dioxide emissions than historically 

burned at Big Stone I. The Sierra Club took the last 10 years of data from EPA’s Clean Air 

Markets Database and stated the highest annual average sulfur dioxide emission rate was no 

higher than 0.70 pounds per million Btus. The Sierra Club stated DENR should use this 

uncontrolled sulfur dioxide emission rate or at worst, determined the highest 30-day average 

uncontrolled sulfur dioxide emission rate in setting the BART emission limit for Big Stone 

based on the control efficiency of the sulfur dioxide controls evaluated. 

Response: In considering what emission limit represents BART, one needs to consider the 

operation of the emission unit and the control device. DENR considers it inappropriate to 

take an arbitrary emission rate Otter Tail Power Company has actually emitted and multiply 

it by an arbitrary control efficiency to develop an emission limit. 

The control efficiency is variable as recognized by EPA’s fact sheet (EPA-452/F-03-024) for 

fabric filters controlling particulate matter emissions. The fact sheet notes a fabric filter is a 

constant outlet device and not a constant collection efficiency device. This fact sheet also 

notes the collection efficiency of the fabric filter is constantly changing and average 

collection efficiencies are based on tests with a constant inlet pollutant loading. EPA also 

recognized the variability in another fact sheet (EPA-452/F-03-034) for flue gas 

desulfurization (wet and dry) controlling sulfur dioxide emissions. In this fact sheet, EPA 

states control efficiencies range from 50 percent to 98 percent. 

In addition, EPA acknowledges this concept in rules. For example, in accordance with 40 

CFR §60.482-10, a vapor recovery system shall be designed and operated to recover the 

volatile organic compound emissions vented to them with an efficiency of 95 percent or 

greater or to an exit concentration of 20 parts per million by volume, whichever is less 

stringent. Another example is in the new source performance standard for electrical utility 

steam generators. In accordance with 40 CFR 60.43Da(i)(1), an electrical utility steam 

generating unit that commenced construction after February 28, 2005, shall not emit sulfur 

dioxide in excess of 1.4 pounds per megawatt hour or 5 percent of the potential combustion 

concentration (95 percent reduction). 
 9 

DENR does not recommend any changes. 

12. The Sierra Club believes the BART analysis for sulfur dioxide is flawed because DENR 

failed to consider the level of control achievable with wet scrubbers. The Sierra Club 

identified wet scrubbers in Japan that guaranteed 99% sulfur dioxide control efficiency and 

claimed this technology was demonstrated at the University of Illinois’ Abbott power plant, 

Georgia Power’s Plant Yates, Dayton Power & Light’s Killen Unit 2, and Plant Bowen Unit 

#3. The Sierra Club went on to identify other facilities that identify 97.5% efficiency or 

better. The Sierra Club’s conclusion was the BART analysis should have evaluated these 

levels of control based on the actual uncontrolled sulfur dioxide emissions emitted by the unit 

over a 30 day average basis in the evaluation of a wet scrubber for BART. 

Response: The Sierra Club provided vender data for several systems implementing the 

Chiyoda CT-121 wet flue gas desulfurization system. With the exception of the data for the 

Shinko-Kobe power plant in Japan, the 2008, 2009, and 2010 data notes that to obtain the 

98% and greater control efficiency the inlet sulfur dioxide concentrations to those scrubbers 

needed to be greater than 1,680 parts per million. At these inlet concentrations and control 

efficiency, this data indicates that controlled emission rate for these systems would be in the 

range of approximately 0.07 and 0.15 pounds per million Btus. DENR calculated these 

emission rates using EPA’s Method 19 at 5% oxygen. Since the oxygen content of the data 

was not given, the calculated concentrations will vary slightly. 

The Chiyoda CT-121 wet flue gas desulfurization vender data indicates that for those 

systems with an inlet concentration between 500 and 1,000 parts per million, an average of 

95% control efficiency was obtained. At these inlet concentrations and control efficiency, 

this data indicates that controlled emission rate for these systems would be in the range of 

approximately 0.05 and 0.10 pounds per million Btus. Again, DENR calculated these 

emission rates using EPA’s Method 19 at 5% oxygen. 

As discussed in Appendix D of South Dakota’s Regional Haze State Implementation Plan, 

for calendar years 2006, 2007, and 2008, and not considering periods of startup and 

shutdown, Otter Tail Power Company’s hourly sulfur dioxide emission rates ranged from 

approximately 0.5 to 1.3 pounds per million Btus. These emission rates correspond to a 

sulfur dioxide inlet concentration of 262 to 683 parts per million. This range represents the 

data associated with the 500 to 1,000 parts per million (95% control efficiency) but is also 

below that range which means the control efficiency would be less than 95%. DENR’s 

BART emission limit for sulfur dioxide of 0.09 pounds per million Btus is within the 

emission rate range for both the 95% and 98% control efficiencies. 

In regards to the Shinko-Kobe power plant in Japan, the CT-121 wet flue gas desulfurization 

Kobe was designed for operation at 99 percent sulfur dioxide removal for a one percent 

sulfur bituminous coal, analogous to an Eastern U.S. low-sulfur coal. Otter Tail Power 

Company burns Powder River Basin subbituminous coal, which is a Western U.S. low-sulfur 

coal. Due to the coal characteristic differences, this plant is not comparable. 
 10 

The Sierra Club also states Mitsubishi guarantees a control efficiency of 99.8%. The 

document submitted by the Sierra Club does not state Mitsubishi guarantees this control 

efficiency for every project. The data indicates this guarantee was associated with a sulfur 

dioxide inlet concentration of 7,800 parts per million. As stated above, the sulfur dioxide 

inlet concentration for Otter Tail Power Company’s facility ranges from 262 to 683 parts per 

million, which is well below the range Mitsubishi guaranteed a 99.8% control efficiency for 

and is not comparable to Otter Tail Power Company’s facility. 

The Sierra Club references a permit issued by the Georgia Environmental Protection Division 

for Plant Washington. In reviewing this permit, on page #9, Georgia appears to have 

established Best Available Control Technology Limits of 0.052 pounds per million Btus on a 

12-month rolling basis, 0.069 pounds per million Btus on a 30-day rolling average, and 959 

pounds per hour (equivalent to 0.116 pounds per million Btus at maximum capacity) on a 3-

hour average. DENR’s BART emission limit for sulfur dioxide is 0.09 pounds per million 

Btus on a 30-day rolling average which is comparable to Georgia’s BACT emission limit for 

that same time period. 

The Sierra Club also references actual monitoring data from EPA’s Clean Air Markets 

division for several coal fired power plants. The Sierra Club notes there is actual monitoring 

data that indicates lower emission rates are being achieved. DENR agrees actual monitoring 

data is useful information. However, DENR disagrees with the concept or emphasis that an 

emission rate limit should be set at the same level of the actual monitoring data. In 

evaluating an emission rate that will be used as an emission limit, DENR considers the 

variability within the actual monitoring data to determine if a facility is able to achieve an 

emission limit on a continuous basis underneath all proposed operations and into the future. 

DENR reviewed the monitoring data for Pleasant Prairie for calendar year 2008. The 

monitoring data notes that Pleasant Prairie had on an hourly basis actual emission rates as 

high as 0.22 pounds per million Btus per hour, which is approximately 10 times higher than 

the annual average. These higher hourly emission rates need to be considered in establishing 

an emission rate to ensure the emission limit may be achieved continuously and at all 

proposed operations.

In summary, DENR conducted a case-by-case BART determination for Otter Tail Power 

Company’s facility and determined the BART emission limit should be 0.09 pounds per 

million Btu using a dry flue gas desulfurization unit to control sulfur dioxide emission and is 

within the range Sierra Club provided for a wet flue gas desulfurization unit. 

13. The Sierra Club believes DENR and Otter Tail Power Company failed to evaluate the highest 

sulfur dioxide removal efficiencies achievable with a state-of-the-art dry scrubber. The 

Sierra Club mentioned four coal fired power plants that will or have installed a dry scrubber 

and are subject to higher control efficiency requirements and/or lower sulfur dioxide BACT 

emission limits than the 0.09 pounds per million Btu proposed by DENR. The four coal fired 

power plants are: 1) Newmont Nevada TS power plant; 2) White Pine power plant; 3) 

Toquop power plant; and 4) Dry Fork power plant. Thus DENR should have evaluated these 

levels of control based on the uncontrolled sulfur dioxide emissions emitted by the unit over 

a 30-day average basis. 
 11 

Response: The Sierra Club references four coal-fired power plants that have installed or are 

proposing to install a “state-of-the-art” dry scrubber. DENR reviewed three of the four 

facilities but was unable to review Dry Fork since it was not available and the Sierra Club did 

not provide Exhibit 13 to DENR. DENR determined that the Newmont and White Pine 

power plants installed or proposed to install a dry scrubber system to control sulfur dioxide 

emissions. However, the Toquop power plant actually proposed to install a wet scrubber 

system so is not comparable in this scenario. The Newmont and White Pine are located in 

Nevada and have the same sulfur dioxide BACT emission limits which consist of the 

following: 

1. 0.09 pounds per million Btu based on a 24-hour average if the sulfur content of the 

subbituminous coal is equal to or greater than 0.45% based on a 30-day rolling 

average and a 95% sulfur dioxide removal efficiency based on a 30-day rolling 

average; and 

2. 0.065 pounds per million Btu based on a 24-hour average if the sulfur content is less 

than 0.45% based on a 30-day rolling average and a 91% sulfur dioxide removal 

efficiency based on a 30-day rolling average. 

The Sierra Club identifies the sulfur dioxide BACT emission limit of 0.07 pounds per million 

Btu. 

As the Sierra Club indicates, these four power plants either have just started operation 

(Newmont began operation in 2008), are currently under construction (Dry Fork), or have not 

started construction (White Pine). These permits established emission limits that represent 

best available control technology for new coal fired power plants and not a retrofit of an 

existing power plant that represents Best Available Retrofit Technology. After taking that 

into consideration, DENR established a sulfur dioxide BART emission limit of 0.09 pounds 

per million Btu based on a 30-day rolling average which is comparable to Newmont and 

White Pine. 

As outlined in Appendix D of the Regional Haze State Implementation Plan submittal, 

DENR reviewed EPA’s Reasonable Achievable Control Technology, Best Available Control 

Technology, and Lowest Achievable Emission Rate Clearinghouse (RBLC) for permits 

issued after calendar year 2000 on the emission limits established for coal fired boilers using 

a flue gas desulfurization system. The RBLC notes that the best available control technology 

emission limits for new coal fired boilers using a flue gas desulfurization system (either wet 

or dry) were in the range from 0.04 to 0.17 pounds per million Btu. DENR’s sulfur dioxide 

BART emission limit is within the range identified for BACT emission limits for new 

boilers. 

14. The Sierra Club believes DENR’s cost effectiveness calculation of the wet scrubber at a 

sulfur dioxide emission rate of 0.043 pounds per million Btu of $1,699 per ton is a reasonable 

cost when compared to other sulfur dioxide BART determinations. The Sierra Club 

references a spreadsheet put together by the National Park Service with cost information for 

BART determinations. According to the Sierra Club, the spreadsheet identifies the average 
 12 

cost effectiveness of sulfur dioxide BART controls as $1,571 pounds per ton, the mean cost 

effectiveness as $1,966 per ton, and the highest cost is $7,309 pounds per million Btu. The 

Sierra Club states that similar facilities will have to incur similar costs to meet BART; 

therefore, DENR has no justification to discount installation of a wet scrubber based on costs. 

Response: The Sierra Club did not provide a copy of the spreadsheet they used to provide 

the different effectiveness. It is impossible to compare the effectiveness since the Sierra Club 

uses three different units in comparing cost effectiveness, mean cost effectiveness, and 

highest costs. DENR was unsuccessful in obtaining the National Park Services’ spreadsheet 

from the internet and was unable to compare the numbers. 

DENR based its BART determination on a case-by-case basis taking into consideration the 

technology available, the costs of compliance, the energy and non-air 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. As noted one of the 

consideration is the improvement in visibility. Based on the visibility modeling, there was no 

discernable difference between installing a wet or dry flue gas desulfurization system. 

In making its BART determination, DENR reviewed the modeling results and in some cases 

the wet flue gas desulfurization system would cause a higher visibility impact than the dry 

flue gas desulfurization system. Just as the modeling shows in some other cases the dry flue 

gas desulfurization system would cause a higher visibility impact than a wet flue gas 

desulfurization system. After taking everything into consideration, DENR determined a dry 

flue gas desulfurization system represented BART. 

15. The Sierra Club states DENR and Otter Tail Power Company did not fully evaluate the 

environmental impacts of a wet scrubber versus a dry scrubber. Specifically, they mention a 

wet scrubber will provide lower sulfur dioxide emission rates which will be needed for the 

effective removal of carbon dioxide from the gas stream once it is required; greatly improve 

the removal of hydrogen chloride and hydrogen fluoride; significantly remove arsenic, 

beryllium, cadmium, chromium, lead, manganese, and mercury from flue gas; lower 

particulate matter 2.5 microns in diameter or less concentrations; and decrease the 

methylization of mercury. 

Response: As defined in 40 CFR § 51.301, BART is established on a case-by-case basis 

taking into consideration the technology available, the costs of compliance, the energy and 

non-air 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. 

There are advantages and disadvantages to operating a wet and dry flue gas desulfurization 

system. The Sierra Club identifies what it believes to be advantages of a wet flue gas 

desulfurization system but do not identify the disadvantages of a wet flue gas desulfurization 

system or the advantages of a dry flue gas desulfurization system. 
 13 

The Sierra Club cites a letter from Alstom to Duke Energy and testing data from the 

WYGEN II facility in Wyoming as documentation that a wet scrubber is better at reducing 

hydrogen chloride and hydrogen fluoride emissions. The hydrogen chloride and hydrogen 

fluoride emission rates for both a wet scrubber and a dry scrubber are dependent upon several 

factors, which include the type of coal, boiler design, inlet concentrations, etc. These factors 

are innately important when trying to compare control efficiencies. Unfortunately, DENR 

did not receive the exhibits the Sierra Club cites and is unable to locate these specific 

documents. Therefore, DENR was unable to determine how the efficiencies cited by the 

Sierra Club were derived. 

The Institute of Clean Air Companies webpage cited by the Sierra Club also specifies the 

following: “According to the EPA and others, both wet and dry scrubbers have been shown 

to reduce HCl emissions by 95% and more...Others have reported ranges of 87-94% removal 

of chlorine and 43-97% removal of fluorine by both wet and dry scrubbers.” As indicated 

by the Sierra Club and the documents cited, both a wet scrubber and dry scrubber will reduce 

hydrogen chloride and hydrogen fluoride emissions, which notes the two control options are 

beneficial in reducing hydrogen chloride and hydrogen fluoride. 

The Sierra Club also cites the Institute of Clean Air Companies as specifying that a wet 

scrubber “significantly remove arsenic, beryllium, cadmium, chromium, lead, manganese, 

and mercury from flue gas.” In reviewing the cited webpage, DENR could not locate what 

was classified as “significant,” or what type of coal was being burned in the system being 

referenced. 

The emission rates of heavy metals are dependent upon several factors, such as the type of 

coal being burned. For example, mercury is present in coal in trace amounts. When coal is 

burned, the mercury is found in the gas stream in several forms. Mercury is volatilized and 

converted to elemental mercury vapor in the high temperature regions of a coal-fired boiler. 

As the gas stream cools, a series of complex reactions begin to convert a portion of the 

elemental mercury into ionic mercury compounds and particulate mercury. 

This partitioning of a portion of the elemental mercury into ionic mercury and particulate 

mercury is known as mercury speciation, which can have considerable influence on the 

selection of mercury control approaches. In general, the majority of gaseous mercury in 

bituminous coal-fired boilers is ionic mercury. On the other hand, the majority of gaseous 

mercury in subbituminous and lignite fired boilers is elemental mercury. 

To complicate the mercury speciation, the type of coal burned, the chlorine content of the 

coal, fly ash content (unburned coal), sulfur trioxide, and water concentrations of the gas 

stream appear to impact the mercury reactions and chemistry. The mercury chemistry is 

important because the particulate mercury may be captured and controlled by a particulate 

matter control device such as a baghouse but ionic mercury is captured and controlled more 

efficiently by a wet scrubber system. The hardest to capture and control with existing 

technology is elemental mercury. Therefore, being able to convert elemental mercury to one 

of the other two forms is essential in capturing a high percentage of the mercury emissions. 
 14 

Regardless of the technology both a wet scrubber and dry scrubber are expected to reduce 

mercury emissions. 

Other advantages identified in Otter Tail Power Company’s BART analysis are 1) a dry flue 

gas desulfurization system generates a dry byproduct which can be handled with 

conventional ash handling systems which is not available to a wet flue gas desulfurization 

system, 2) the dry flue gas desulfurization system does not have true “wet zone” so there is 

less corrosion issues and reduces the “exotic” construction materials and 3) the dry flue gas 

desulfurization system also produces less acid aerosols such as sulfuric acid. 

The BART determination is a case-by-case review that takes into account several factors. 

After taking everything into consideration, DENR determined a dry flue gas desulfurization 

system represented BART. 

 

16. The Sierra Club believes the BART analysis for nitrogen oxide is flawed because DENR 

failed to consider the level of control achievable with the proposed selective catalytic 

reduction at Big Stone I. The Sierra Club indicates a selective catalytic reduction system is 

capable of achieving an additional 90% nitrogen oxide reduction. The Sierra Club reviewed 

recent selective catalyst reduction retrofits and states establishing BACT nitrogen oxide 

emission limits of 0.05 to 0.06 pounds per million Btu with at least one nitrogen oxide BACT 

emission limit as low as 0.035 pounds per million Btu. Because of this, the Sierra Club 

believes DENR must establish a lower nitrogen oxide BART emission limit. 

Response: The response to this comment is already addressed in the response to Comment 

#2. 

17. The Sierra Club states that DENR must lower its particulate matter BART emission limit of 

0.012 pounds per million Btu to 0.010 pounds per million Btu or lower because baghouses 

can achieve much lower emission rates and permitting authorities have required lower limits 

as BACT. The Sierra Club cites the BACT limits in a permit for Plant Washington in Atlanta, 

Georgia that was issued April 8, 2010. 

Response: The Sierra Club identifies one Prevention of Significant Deterioration (PSD) 

permit with a BACT particulate matter emission limit of 0.010 pounds per million Btu. 

DENR reviewed three of the permits the Sierra Club mentioned in this comment that have 

opacity limits to determine what was used for BACT particulate matter emission limits. In 

the three permits, MidAmerican in Council Bluffs, Iowa has a particulate matter limit of 

0.027 pounds per million Btu (e.g., includes front and back half); Plum Point in Osceola, 

Arkansas has a particulate matter limit of 0.018 pounds per million Btu; and Desert Rock has 

a particulate matter limit of 0.010 pounds per million Btu and a total particulate matter 10 

microns in diameter or less (PM10) emission limit of 0.020 pounds per million Btus. It 

appears there is a range of BACT emission limits that states and EPA have determined on a 

case-by-case basis. 

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 
 15 

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. 

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 Btu. DENR decision to establish a BART PM10 emission limit of 0.012 pounds per 

million Btu is based on a case-by-case basis and meets the requirements to improve visibility 

at Class I areas. 

 

18. The Sierra Club recommends DENR require Otter Tail Power Company to install a 

particulate matter continuous emission monitoring system or establish an opacity limit as an 

indicator of compliance. Since Otter Tail Power Company already has a continuous opacity 

monitoring system, the system can be used as an indicator of continuous compliance with the 

particulate matter BART emission limit. The Sierra Club identified the following coal plants 

with stringent BACT opacity limits: 1) MidAmerican facility in Council Bluffs, Iowa (5%); 

2) Plum Point facility in Osceola, Arkansas (10%); 3) Fort Howard (Fort James) Paper 

Company’s 500 megawatt coal-fired boiler in Wisconsin (10%); 4) Desert Rock (10%). 

Response: The Sierra Club provided examples of states which established Best Available 

Control Technology (BACT) limits for particulate matter and opacity. In the case of 

MidAmerican in Council Bluffs, Iowa, the permit identifies a BACT opacity and particulate 

matter limit. However, compliance with the two limits are not related to each other. 

Compliance with the particulate matter limit is based on an annual stack test while the 

opacity limit is based on a continuous opacity monitoring system. In the case of Plum Point 

in Osceola, Arkansas, compliance with the BACT particulate matter limit is based on an 

annual stack test and compliance with the opacity limit using a continuous opacity 

monitoring system. In the case of Desert Rock, compliance with the particulate matter BACT 

emission limit is based on annual stack tests and a particulate matter continuous monitoring 

system. However, for particulate matter 10 microns in diameter or less (PM10), compliance 

is based just on annual stack performance tests. 

The BART determination is based on a case-by-case basis taking into consideration a variety 

of situations similar to how a BACT analysis is conducted. As you can see, one state and 

EPA based compliance with the particulate matter and opacity limits separately while one 

state based compliance together. In the EPA case, EPA based compliance with the particulate 

matter emission limit on annual stack tests plus a particulate matter continuous emission 

monitoring system. In the case of PM10, EPA based compliance on annual stack tests. The 

BART particulate matter emission limits for Big Stone I are based on PM10. DENR agrees it 

has the authority to require a particulate matter continuous emission monitoring system. But 

like some states and EPA, DENR considers an annual stack test sufficient at this time to 

demonstrate compliance with the BART particulate matter limit. 

DENR agrees it has the authority to establish an opacity limit. However, establishing an 

opacity limit is at the reasonable discretion of the permitting authority based on its case-bycase analysis of the facility. DENR believes the PM10 BART emission limits and annual 

stack performance test are adequate to meet the requirements to improve visibility at Class I 

areas. 
 16 

19. The Sierra Club states there should be no exemptions from BART emission limits during 

startup and shutdown periods. The Sierra Club bases this on EPA’s BART Guidelines which 

state the BART emission limits must be met on a continuous basis pursuant to section 302(k) 

of the Clean Air Act. Startup and shutdown are part of the normal operations of a power plant 

like Big Stone, and the emissions during startup and shutdown impact visibility and regional 

haze. So DENR’s proposed BART limits must include periods of startup and shutdown. The 

Sierra Club also brought up that during the 2008 contested case hearing for the Big Stone II 

permit, Otter Tail Power Company’s Terry Graumann made clear in his testimony that Otter 

Tail Power Company was not requesting exemptions from emission limits during periods of 

startup and shutdown and Otter Tail Power Company’s Mark Rolfes indicated the pollution 

controls would operate during startup and shutdown. 

Response: As outlined in Comment #3, DENR is not exempting Otter Tail Power 

Company’s Big Stone I facility from BART emission limits during periods of startup and 

shutdown. Just because there is no startup and shutdown emission limit in pounds per million 

Btu does not mean DENR exempted the Big Stone I facility from a BART emission limit 

during startup and shutdown. On the contrary, DENR established a pound per hour emission 

limit for particulate mater, sulfur dioxide, and nitrogen oxide to represent a BART emission 

limit during normal operations, including startup and shutdown. The pounds per hour limit is 

based on the maximum capacity of the unit and the pounds per million Btu BART emission 

limit. In addition, the pounds per hour BART emission limit was used in the modeling 

analysis to demonstrate Otter Tail Power Company was not causing visibility impairment in 

a Class I area. 

During the public hearing on South Dakota’s Regional Haze State Implementation Plan and 

associated rules, the Board of Minerals and Environment revised the particulate pounds per 

million Btus limit to cover all operations including startup and shutdown based on previous 

testimony from Otter Tail Power Company that the baghouse would be in operation prior to 

starting up the boiler and could meet the pounds per million Btus hour limit even during 

startup and shutdown. 

20. The Sierra Club indicates the state’s regulation under ARSD 74:36:21:06-09 must identify 

Big Stone I as the source subject to these emission limits to ensure enforceability of the 

BART limits. 

Response: In developing our rules, DENR consults with our Legislative Research Council, 

which approves the proposed state rules for form, style, and legality. The Legislative 

Research Council informed DENR that South Dakota has as part of its Constitution a clause 

that states private and special laws are prohibited. This may be found in Constitution 3-23 – 

Private and Special Laws Prohibited. The state constitution states that “In all other cases 

where a general law can be applicable no special law shall be enacted.” The Legislative 

Research Council required DENR to word the language in a form which applies only to Otter 

Tail Power Company’s Big Stone I facility and meets the requirements in South Dakota’s 

Constitution. 
 17 

21. The Sierra Club recommends the state’s BART regulation should require compliance with 

the particulate matter BART emission limit now given Big Stone has already installed a 

fabric filter baghouse and can comply with the BART limit now. 

Response: As Otter Tail Power Company’s BART submittal notes, a dry flue gas 

desulfurization system must be located upstream of the particulate control devices. Two of 

the issues associated with adding this system are: 1) can the existing particulate control 

device handle the particulate loading; and 2) will the existing particulate control device still 

be able to meet its BART emission limits. As the Sierra Club mentions in its comments, the 

federal regulations under 40 CFR §308(1)(e)(1)(iv), requires each source subject to BART to 

install BART as expeditiously as practicable, but no later than 5 years from EPA’s approval 

of the implementation plan revision. Since demonstrating compliance with the sulfur dioxide 

BART affects the compliance demonstration for particulate matter, maintaining the 

compliance periods as allowed under federal regulations is considered appropriate and 

reasonable. 

4.0 Otter Tail Power Company’s Comments 

22. Otter Tail Power Company suggested a clarification revision to ARSD 74:36:21:11. The 

revision moves “in accordance with § 74:36:20” after “application” instead of at the end of 

the sentence to clarify the application is to be processed through the construction permit 

program. 

Response: DENR agreed and revised ARSD 74:36:21:11 appropriately. 
Appendix A 

Comment Letters Received 

During Public Notice Period for 

South Dakota’s Draft Regional Haze Program 
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGIONS 

Ref: 8P-AR 

Brian Gustafson. Administrator 

Air Quality Program 

1595 Wynkoop Street 

DENVER, CO 80202·1129 

Phone 800-227-8917 

hltp:/Iwww.epa.gov/region08 

SEP I 3 ZO In 

South Dakota Department of Environment and Natural Resources 

523 East Capitol Avenue 

Pierre, SD 57501-3182 

Dear Mr. Gustafson: 

RE: EPA Preliminary Comments on August 2010 

Draft Regional Haze State Implementation Plan 

(Public Comment Version) 

EPA has completed a preliminary review of South Dakota's August 20 IO draft Regional 

Haze State Implementation Plan (SIP). Our comments and questions are detailed in Enclosures 1 

through 3 to this letter. 

We understand that you intend to consider all comments received on this public comment 

version of the Regional Haze SIP prior to finalizing and adopting the documents for submission 

to EPA. We emphasize that we will only reach a final conclusion, and perform our complete 

review, regarding the adequacy of South Dakota's Regional Haze SIP when we act on the South 

Dakota Regional Haze SIP revision through our own public notice and comment rulemaking. 

We look forward to continued communications to resolve the remaining concerns with 

the Regional Haze SIP. If you have any questions on EPA's comments, please contact me at 

303-312-6434, or your stafT may contact Gail Fallon at 303-312-6281. 

Enclosures 

cc: John Bunyak, NPS 

Sandra Silva, USFWS 

Thomas Dzomba, USFS 

Sincerely, 

, ~47#id:4:,j-=- L--t...1iIlie A. Videtich, Director 

Air Program 
ENCLOSURE I 

EPA Region 8 Preliminary Comments on the August 2010 Draft Regional Haze SIP 

(Public Comment Version) 

Summary of Major Concerns - (see detailed comments for more information): 

• Many comments from our March 12,2010 letter were not sufficiently addressed. All of 

the detailed preliminary comments below pertain to those previous comments and 

provide additional information on areas which arc still problematic. 

• Insufficient details were provided on how the best available retrofit technology (BART) 

emission limits will be made enforceable as a practical matter. See comments #1, #4 and 

#7 below. 

• No identification of the number of years to reach natural conditions was provided as 

required when the Reasonable Progress Goal is less than the Uniform Rate of Progress. 

Sce comments #5 and #8 below. 

• No four-factor Reasonable Progress analysis was completed. See comment #6 below. 

• Recommcnd reviewing ARSO regulation references for typographical errors throughout 

both the response to comments (for future clarity in the SIP record) as well as the main 

SIP document. There arc numerous errors likely due to the addition of 74:36:21 :06, 

which changed the numbering of the subsequent chapters. 

Detailed Comments: 

I. Executive Summary. pp. vii-viii: Additional details are necessary to ensure that BART 

emission limits will be enforceable as a practical matter. The BART emission limits, 

compliance schedules, monitoring, recordkeeping, and compliance determining methods for 

Big Stone I must be specified in the text of the Regional Haze SIP or in a permit that is 

incorporated into the SIP. For example, in your response to our comment on this issue (#1 

and #39 from Appendix D), you relied heavily on requirements of your Title V program 

(ARSO 74:36:05). As this program is not part of the SIP, our concerns with reliance on the 

Title V program in this area remain. Two examplcs of all the various elements of adequate 

language that were coordinated with the States of Wyoming and Colorado are provided in 

Enclosures 2 and 3 for reference. 

2. Table 6-9, p. 91: Footnote 5 references a 1999 EPA Technical Bulletin on NQ'( controls as 

justification for the 35%-90% control efficiency range for the top three options. The large 

range in EPA's bulletin is due to inclusion of selective catalytic reduction (SCR), selective 

non-catalytic reduction (SNCR), and fuel reburning for wet-bottom boilers. It is well 

documented that SCR achieves the high end of the range. The EPA bulletin also lists a 30%-

70% control efficiency for a group of temperature-reducing controls, including over-fire air. 

Therefore, the proposed BART determination ofSCR plus separated over-fire air (SOFA) 

should be better than the 90% control efficiency of SCR alone. In your response to this 

comment (#31 from Appendix D), there was no discussion regarding how the addition of 
SOFA would not contribute to a better than 90% control efficiency. This needs to be 

addressed. 

3. Section 6.3.5. BART Emissions Limits for Big Stone I, pp. 99-103: In order for EPA to 

entertain the establishment of separate BART limits for startup and shutdown conditions, an 

adequate record showing that the otherwise applicable limits are not achievable and that the 

separate startup/shutdown limits constitute BART is required as justification. Your response 

to this comment (#38 from Appendix D) does not provide sufficient justification for 

establishing the separate startup/shutdown limits. We continue to offer to work closely with 

you to establish appropriate 30-day rolling average emissions limits for particulate matter, 

sulfur dioxide and nitrogen oxides that allow for startup/shutdown conditions to help ensure 

SIP approvability. 

4. Section 6.4, BART Requirements, p. 103: According to your proposed revisions to the South 

Dakota Administrative Rules, Chapter 74:36:21: 1 0, a pennit modification will be required 

for your BART detennination on Otter Tail's Big Stone I. Without seeing the details of such 

pennit, it is difficult to determine whether this section of the SIP adequately addresses 

requirements for enforceability, including appropriate averaging times, compliance 

verification procedures, and recordkeeping and reporting requirements, and proper operation 

and maintenance procedures. As noted in comment # 1 above, these requirements must be 

specified either in the text of the Regional Haze SIP or in a permit that is incorporated into 

the SIP. Your response to this comment (# 39 from Appendix D) relied heavily on your 

Title V program which is not part of the SIP and does not fully address this issue. 

5. Section 7.2.1. Breakdown of CMAQ Modeling Results, pp. 106-107: Your response (#47 

from Appendix D) addressed most of our questions with one exception. The SIP must 

provide the number of years necessary to reach natural conditions, as required by 40 CFR 

SI.308(d)( 1 )(ii) when the reasonable progress goal (RPG) is less than the uniform rate of 

progress (URP). While you state in Section 10.3 on page 127 that you believe South Dakota 

can still meet the reasonable progress goals and achieve natural conditions by 2064, the data, 

as currently presented, does not support this proposed conclusion. 

6. Section 7.2.2, Four Factor Analysis, pp. 107-109: DENR's detcnnination that a four-factor 

analysis is not warranted at this time is not acceptable. A four-factor analysis must be 

completed in establishing the RPGs for Class I areas impacted by South Dakota emissions, as 

well as in justifying a RPG that is less than URP. Despite your response to this comment 

(#49 from Appendix D) regarding minimal contribution from point sources to visibility 

impainnent, a four-factor analysis is required to justify this conclusion. Again, we suggest 

looking for additional reductions from GCC Daeotah, Ben French, and Pete Lien as well as 

the potential from the close proximity of Rapid City to Badlands. 

7. Section 8.5.6, Enforceable Emission Limits and Control Measures, p. 116: Though this 

section was slightly reworded per your response (#56 from Appendix D), your intention to 

establish the Big Stone I BART limits and control measure requirements in an air quality 

permit requires the pennits' incorporation into the SIP. The South Dakota draft construction 

2 
permit program regulations are currently under review by our office. Until this has been 

approved into the SIP, it will not be appropriate to rely upon the program for your BART 

permits. 

8. Section to.3, Public Input, pp. 126-127: As noted in comment #5 above, the SIP must 

provide the public with a calculation of the number of years required to reach natural 

conditions if the RPG provides a slower rate of improvement than that needed to attain 

natural conditions by 2064 per 40 eFR SIJ08(d)( I )(ii). We understand your concerns 

regarding assumptions for other states included in the WRAP analysis; however, this SIP 

must include your best estimate of number of years to reach natural conditions with the 

proposed RPGs. Though this section was slightly reworded per your response (#48 from 

Appendix D), the number of years is still lacking. 

9. ARSD Chapter 74:36:21: 12, Federal Land Manager Notification and Review: Your response 

(#65 from Appendix D) did not adequately address our concern related to FLM consultation 

on BART permit reviews. As required by the Regional Haze Rule, the Federal Land 

Managers must be provided a 60-day consultation period prior to any public hearing on the 

Regional Haze SIP. Since a BART permit is an integral part of the Regional Haze SIP, this 

60-day consultation period must extend to FLM BART pennit review as well. In addition, 

since any BART permit must be incorporated into the Regional Haze SIP, the 3~ day public 

notice for the SIP needs to identify the inclusion of any BART permits. 

3 
ENCLOSURE 2 

EPA RegionS - Preliminary Comments on Wyoming's Regional Haze Monitoring. 

Recordkeeping, and Reporting Requiremenl~ (MRR) 

Please note: This document is divided into two sections. The first section provides 

comments on the current MRR language in the State's Regional Haze SIP. We have included 

comments (in italics) and in some instances suggested language. The second section of this 

documenl contains infonnation on SIP MRR elements that need to be added to the SIP and 

suggested language. 

I. Current SIP Language for Pacificorp Unit 

The State of Wyoming considers the control effectiveness of a control technology to be 

cquivalem to the BART -detennincd pennit limit <1\ indir.:ated 111 Tallie XX hclov. . The Slate 

,hllUIJ challW; the pn:q;d!Dg ~cntcncc to n.:ad "The State (If Wyoming nlm,isJer~ the BARl 

determined rx.'nniL limit ttl he euuivalentt" the t.:ontnll ctTccti\ene"', of a (,:Iliuml 

tedmulu)!\ The limit is based on continuous compliance when the contwl equipment is 

well maintained and operated in a manner consistent with good air pollution control pmctices 

for minimizing emissions. flit' SIP mil 1/ h"/iI CI/r /hlll/he SmUll' 11/1/ (fl/l~ 1111 JJANfJil 

all limn LliT lillie ill Snliol! 1\:, h!'lml'! 

rubl,' XX .. Unit-by-unit BART determinations for NO~ and PMlPMlo: 

Un it Pollutant Comrol Type lbfMMBtu Ibfhr tpy 

J NO" LNB/OFA 0.28 nil· day 784 em·day 3.434 

rolling) rolling) 

PMfPMI!),,, Fabric Hlter 0.015 42.1 IH4 

4 NO, LNBfOFA 0.15 OO-day 615130-day 2.694 

rolling) rolling) 

PMlPMI!)'al Fabric Filter 0.015 61.5 269 

III. Expeditious Installation and Operation of BART 

""i~ ~"lIk 1/1'1'(/1 til /IIdiw/(' ill Iltil ItTljell! IlIlIl III(' HARr dl'/(,r/1111/11/1II1/ i ,1 1l!'l11'IIt/OIl IlII 

IlfJllrO\ /1/ hi' 1:"1'. \. nit' S'I/It' 1//11\1 (//\0 {lrm'lell' III/Ilk hi 11"111('1, rill' IIII/ra IIn'dl (111m/all 

(lIId t '/1//111/\ 1IIIIi till' Il. 'Sf limil.1 I/0' lUll lit,' l"t'IIIl/rt'I1N'nt til ill l'lltll (11f' "/IIlirml'llf_ Pa (Iw 

/I, lSf (.illiddi/lt" I \o/lrn'.1 .1//lmM ill\(/I/l cllllfro!1 CI\ t'.lflnJi/lOu,l/) til IIrIU-rinlblr hllllW lu(n 

IIIWI/ii/' Win fllit"!" EP .. \ t/lmrow{ of'lht' SIP_ The State of Wyoming cropms;" that 

PacifiCorp install new low NOx burners with advanced OFA on Units 3 and~. in accordance 

with the Division's BART dctennination, and conduct the required initial perfonnance tests 

no later than December 31. 2010 and December 3 1,2009, respectively. The State of 

Wyoming nropll"C' that PacifiCorp install new full-scale fabric filters on Units 3 and 4. in 

accordance with the Division's BART detcnnination. and conduct the initial perfonnancc 

tests required no laterthan December 31, 2010 and December 3 L 2012. respectively. For 

111'rlinm(/IIII' (I'Hill!!. flrl' mmfimb/r [P. \ (('If mcrltmJ mil\! he If/fL'ilit,d 1I101/I! with 1111' 

In'tlllell('\' of '('Hill!! alit! olilef felt'I'(JII( mtflf/1/(ui(m. 
IV. Proper Maintl!nance and Operation of Control Equipment 

\t illl urllC~ ilftcr Ihe cmnpl1il1ll'l! dcadlLnc ~rc(llictlllllbuccih ~di()nll. Ihe 

O\\nCr/opcralnr Hf cal:h BART umt ..,hall maintalll, l:alibr.llt!. ilnd operall! il Cl:MS, in lull 

ctllllphancl! ..... lIh the rcyuircmct1hJ~~ynl.titl·!Q..C~~~ part 7'), 10 al,'f~r.!t<;lLl1lca~~n; SOl. 

NOx, diluent jCO~ or o,!, ilnd :-.I"C~ I!a~ \olulllctric nnw mtl! from each BART unit. Thc 

('I·,.~tS_-".b<lJI ~ 1~t:.,.I.!!.I_IIt.:".!lJuiIiC compliallc~ wlth Ill£. SO:! an~l N()~_B:\R T Cllll""'l\lIl 

Ijllllh_fuLl':!.\,;.!lBART ..!!!!!L 

111 uelcflllll1l1lg compliancc \.\ ith the sen and NOx HART IIml"'. all pcrilxh {If cmi ...... lOn~ 

... hall he In~Jllticlli..in!:=!!Jdi~hlnulh, ~huldnwn ... , l!l1lcrgenl.'il''', ;1I!lUJ~:~!f~~I!lJ.!£l.Il'>, 

S()TR: t'er !'e('li(}tI 3fJZOd II{tJre etA. B.tR" limits "II/_~t he met CO",i,llwlI'ilr. rhe 

HART limits sectioll o{the 5i/P Ileed tu ,"tate tlral tire RART /illlir,~ apnlv at allliml'~, 

illL'iudim! "erioti,\ o(SS,'/. 

The State of Wyoming rrO(ltl~l'~ Ihat PacifiCorp conduct initial NO~ perfonnance tesls on 

Units 3 and 4 after the inslallation of low NOx burners and advanced OFA. within 30 days of 

achieving a maximum design rate, but not later than 90 days following initial start-up, I'"or 

ualim11l1111 I II'I/ill!! (11(' IllJllIiC"llh/e f.P \ It's/lIIeth"d I1Im( he \/lnirh'd (11ol/l! \l'llh 11/1' 

""/'(/111"111') III fflflll!! Ill/sf olha rril'\',l//f l/I(or/1ldfio/l. 

(h\ ner/llrel~tJO[ -JHII ~uhmit n:ron~ of all\' rcuuir!!ti pcrfnnnanr.:!! :-.tit~,," le'>l ~ ,li!r!\ll h 

\~Ithln 6() r.:alcndar t.!a ..... aJh:r n'll1pll!lion of the Il!'>t, If a maximum design rate is not 

achieved within (,)0 days of slart-up. the AQD Administrator may require tcsting be done al 

the rate achieved and again when a maximum rate is achieved_ {1,1' SlIIll' ,lIl1l/ltl !"I'fllt/n' 

'/1111 I I" till' IIrn'WI/I \I 1111'1/1" II'ill! . 1/1t/"", I r iI max imul1l i.il!:-.i<lll mit' I..; nnl .,chi\.!, l'tI 

",Ith,n 1)0 da\~ III ~tan-up, the AQI) :\dmini~trilwr ,>hall require tC~ling he done ;tllhe r,IIC 

ih:hIC\cd ,Uld 'Igain \1.1\1,,'11 a lllirl>imUIIl ralC i'> adllc\ed. A tesl protocol shall be submiued 

for Division approval prior 10 testing and a written rcpon of the test results shall be submiucd 

to the Division. Testing required by the WAQSR Chapter 6, Section 3 operating pennit'> Ilr 

tllllwlll''>tIIlL r~qLllrcd h\ \\' .. \QSR t 'halll!!! h SCI.·lio/l ! I\r Sl'CI1UIl'" may be submitted to 

satisfy the testing required. fhl' "rior \1'1I1l'11n' i,1 II rdi'I"l'IIn' /0 till Ihl' (lOadlilll! "ama 

rn!/I/111ioll.\. fhi.1 1/1,(,111 fo ht' rl'{I/III"I'd \l'ith (/ ortH'i,\;Olllhlll \\,;1/ Itt' i" IIIl' SIP, 

The State of Wynming nrorn)<;,c<;, that PacifiCorp conduct initial PM/PM I 0 perfonnance 

tests on Units 3 itnd 4 after the installation of fabric filters within 30 days of ach ieving a 

maximum design rate, but not later than 90 days following initial start-up, For 

palilf}!lfill/"l' Inl/II!!. Ihl' Im"ji.!jlhll .rPr) 1/'11 /lIl'lhod 1/1/1.\/ ht, ,\I'I'I';li("l1 II/Oil!! wilh Ihl 

In'wlt'lI('\' or 1('ltim! Will oIlier rl'i(,!,(1II1 ill{orllltlfio//, 

It " m<l.\Illlum dc~'!.i.&!! Gtl~!.':!Jl!--'UIr.:hIC\ cd '"' ithin YO dil\:~ 01 ,>tart-up. the AOn 

:\dmini'>tralo[ ... hall rcuuin: Ic~llm; hc done al tht' rate al'hie\ cd anti it"ain \~ hell.i! 

1ll,I~iIllUm ritlc .i~.acbj~_'-t'~,J2~\-ncr/opcralor ~I!illl,>uhmit repon ... Ill' .lIly rClluirl'd 

ocrfnrmalKt' stac,," tC<;,h for paniculutc mailer. within 00 calendar dav ... after I.·omn!ction 

Ilf the tt; ... t, In "d~jtion 1.!!.,tIll~!J<l1 "'Ia~k t!!\I~, 1)~}l~r/(~r;~I.!.lr "hal! !lH~[lHI!f...p;m_~!J!,ttt~ 

ClTli"~lIlrl'> for r.:olllrlian~c w ilh tht' BART clllls ... ion Ii IIlII'> in m:wn.larKc \~ itll thc 
~,,"I~ ( IlUpilall"S; ,\"urUlKC "'hll11hlnJll.! (CAM! plan Yl'\do! ,J anJ IppOl\,l'd In 

:(~lrd,II\(': \\ ilh ·m (TR pan M. A test protocol shall be submiued for Division approval 

prior to testing and a written report of the test results shall be submiued to th\! Division, 

Testing required by the WAQSR Chapter 6, Section 3 operating permit may be submitted to 

s<ltisfy the testing required. I~kll' Ihe pnnr 'I.'nl 'lrr lll!'.b...d.!l rl'lh: ... 10.11. lhl 

')PCratlll).; J}C.mil rl.;u!...L[IOn", l1u-.ncI.'J" [n be replaced "itll a pro", Itln that \\ill be III 

1'_ sU' 

The State of Wyoming prn!lll~' performance tests and compliance with the BART limits for 

NO~ be determined for Units 3 and 4 using a continuous emissions monitoring system 

(CEMS). clll1,j .. jellt .... uh Ih\' pnwi"lun" in Iht-. "ccUlm certified in accordance with 40 CFR 

part 60 and dutu from the CEMS ~hall meet th\' requirenwnh !!1 40 CFR part 75. The State of 

Wyuming ~ :..... performance tests for compHance with the BART limits lor PMIPM 10 

conducted annually following 40 CFR 60.46 and EPA Reference Test Methods 1-4 and 5. 

fJ', . .l 1!I~l III ill II ,I fP,\ .\/t-I}wd), 5/J. 50. II! J .1'.\ (//l(Irflmilli • ..ll! I.'} erR (Jllrl 

~m ,\ 

\ ,I ,h!ll '11 ,I ,f III! \' ,un .. "'Hh ~'jk:h run .It :"t 120 I!!!!!J III til f 'n .lIlll .Ich run 

Il. ~ m.:')1 flOor", .. tanJ;Jru ,:uhic fecI. Testing required by the WAQSR Chapter 

6. Section 3 operating pennit may Ix submitted to satisfy the testing required. Ikktc [hl 

Ir III nt, I h. I~I_K '-'rt!n~t!_I() all the "r aim!! QCmH! rc 'ui ItlHn,,-,J hi' lic~d." [ulll' 

1\,' ~ hAl....o!' 'iun that ",III "'-: In jhe_SIl~ 

II. SIP Elements that must be added: 

• I ~II' lilli" 'IX,\'I" the J.\e"u!l!li! lim, II the ~t.!J.i!u, ~ .. Iun limih ulI:luJJIIg 

)1\1 

• SIP must contain monitoring and compliance detcmlination speCifics. I See 

Section at the end of this analysis J 

• The SIP must also contain the specific recordkccping and reporting n.'quirements, 

(See Footnote I lor suggested language) 

• The SIP must explicitly state those records the sources are required to keep to assess 

compliance for the time frame specified in the SIP, Records must be commensurate 

wilh regulatory requirements. Records must be available for examination upon 

request. (See Footnote I for suggested language) 

• The SIP must give reporting schedules and reponing formats, 

• Recordkceping 

o The recordkeeping must be required such that failure to do so would be a 

scpamte violation. 

o Preferably. the SIP should specify that records must be kept for at least 

five years' 

I Sugge~tcd language. Owner/oper,l1or sh:!11 maintain the foUowin: records for at [ea.~t [i v( Y(itfS. and thc:y 

must ~ availahk on requesl: 

1. All CEMS data. Slack tcst dala. and data coll(Cted pursuant 10 the CAM plan. including the date. 

place, and tin'K! of sampling. m(asurement. or tcsting: parameters sampled. mca..urcd. or test(l[ and results: 

lh( company. entity. or jl(rson Ihat performed the te.~ ing, if applicable: and any lield dam sheets from 

testing. 
• The SIP should require periodic rcporting.2 

• The SIP should require timely deviation reporting.H 

• Include definitions for: ( I) boiler openlting da/; (2) CEMS6

; and (3) substitute 

hourly emission rates7 

Suggested language for monitoring and compliance determinations: 

I. Pounds Per Hour And Tons Per Year Limits 

For any hour in which fuel is combusted in the boiler. owner/opercltor shall 

calculate hourly S02 and NOx emissions in pounds at the CEMS in accordance with the 

monitoring procedures and requirements of 40 CFR part 75. In calculating hourly mass 

emissions and emissions nltes, owner/operator shall use the conversion procedures 

specified in 40 CFR part 75. Appendix F. For any hour that valid. quality assured CEMS 

data are unavailable, emissions shall be calculated in accordance with the missing data 

substitution procedures in 40 CFR part 75. subpart D. These hourly values shall then be 

used to determine compliance in accordance with Ihe particular limit's averaging period, 

as foHows: 

2, Records of quality us. .. urance and quality control activities fo r emissions measuring system~ 

including. but notlimjtoo to. any records required by 40 CFR Pan 75. 

J. Records of all major maintenunce activities conducted on emission units, air pollution control 

equipment. and CEMS. 

4, Any other records requir~d by 4{) CFR pan$ 64 and 75. 

~ Suggested language · OWller/openllor shall also submit quanerly CEMS performance rcpons. to include 

dates and dur.llion of each period during which the CEMS was inoperative (ellcepl for zero and span 

adjustments and calibration checks), rea,;on{sJ why the CEMS was inoperative and steps taken to prevent 

recurrence. any periods for which missing data substitution procedures were used. any CEMS repairs or 

adjustments. and results of any CEMS performance tests re4uired by 40 CFR pan 15 (Relative Accuracy 

Test Audits, Relative Accuracy Audits. and Cylinder Gas Audits) . 

.l Su ggested language . Owner/operator shall submit quanerly ellccss emissions repuns no later than the 

':WLh day following the end of each calendar quaner. Ellces.~ emi~sions me:IOS emissions that exceed the 

emission.~ limits specified in _ _ above. 

, Sugge ~ted language· Owner/operator sh:1I1 also submit quanerly rcpons uf any exceedances or excursions 

under the approved CA:vI plan, and steps taken to correct the excet..'<iances or cxcur:;itlns. in accordance 

with 4() crR 64.lJ(a). 

~ Define boiler operating day as "any 2J.·hour period between J 2:00 midnight and the following midnight 

during which any fud is COl11busted at any time at the steam generating uni!." See. 4() CFR pan 51. 

Appt:ndill y, section V. 

"Sugge.~ted language· Continuous emis.~ion monitoring system" or ''CEMS'' means the equipment 

required by [Ihis Sttlion llo sample. anaIY7.e, measure. and provide. by means of readings recorded at least 

un~'e every 15 minutes !using an automated data acquisition and handling system (DAHSj). a pcnnancnt 

record of SO:! or NOli emis.~i on . other pollutant emissions. diluent. or stack gas volumetric flow rate. 

7 Suggestoo language . "Substitute hourly emission rates" or "substitute hourly emission values" mcans 

any hourly emission nues (lr values calculated in accordance with the missing data substitutiun pmcedures 

of 40 CFR pan 75 . . ~ubp.1tt D, where valid. quality a .. sured CEMS data for that hour are unavailable. 
a. Pound .. Per Hour Limit". If the limit Un Table _(cross-ref BART limit 

table)Jis e)(prcssed as a Ib/hr limit, owner/operator shall calculate average Iblhr emis. .. ions 

over the appropriate averaging period. as follows: 

i. Limits with a 30-day averaging period: Emissions shall be calculated on a 

30-day rolling average basis. At the end of each boiler openlting day, owner/operator 

shall calculate a new 30-day rolling averJge emission nne in Iblhr from the arithmetic 

average of all valid and substitute hourly emission values from the CEMS for the most 

recent JO boiler operating days 

ii. Limits with a 12-month averaging period: emissions shaH be calculated 

on a 12-month rolling average basis. At the end of each month. owner/operator shall 

calculate a new 12-month rolling avcmge emission rate in Iblhr from the arithmetic 

average of all valid and substitute hourly emission values from the CEMS for the most 

rt..'Ccnt 12 months. 

h. Tons Per Year Limits. If the limit [in Table _(cruss-ref BART limit table)lis 

c)(presscd as a tons/yr limit, rolling 12-month lotal. total emissions in tons/yr shall be 

calcuillted on a 12-month rolling basis. At the end of cach month. owner/operator shall 

calculate a new 12-month emissions total. in tons/yr, using all vnlid and substitute hourly 

emission valw!s from the CEMS for the most re<..'Cnt 12 months. 

2. Pounds Per Million Btu Limits 

For any hour in which rud is combusted in the boiler. owner/operator shall 

calculate hourly average 502 and NO)( eoncentrJtions in pounds per million Btu at the 

CEM5 in u(,'Cordance with the requirements of 40 CFR pan 75. For any hour that valid. 

quality assured CEMS data are unavailable, emissions shall be calculated in accordance 

with the missing data substitution procedures in 40 CFR part 75 subpart D. These hourly 

averages shall then be used to detennine compliance in accordance with the particular 

limit's averaging period. as follows: 

a. Limits with a 3-hour averaging period: emissions shall be calculated on a 3-hour 

rolling avemge basis. At the end of each hour, owner/operator shall calculate a new 3-

hour average emission rate in IblMMBtu from the arithmetic averugc of the valid and 

substitute hourly emission rates from the CEMS for the most recent three hours. 

b. Limits with a 30-day averaging period: emissions sh.11I be calculated on a 30-day 

rolling average basis. At the end of each boiler operating day, owner/operator shall 

calculate a new JO-day rolling average emission rate in IblMMBtu from the arithmetic 

averJge of all valid and substitute hourly emission mtcs from the CEMS for the most 

recent 30 boiler operating days. 

c. Limits with a 9O-day averaging period: emissions shall be calculated on a 9O-day 

rolling avcmge basis. At the end of each boiler operating day. owner/opcrntor shall 
calculate a new 90-day roUing average emission rate in Ib/MMBtu from the arithmetic 

avemge of all valid and substitute hourly emission rates from the CEMS for the most 

recent 90 boiler operating days. 

d. Limits with a 12-month avemging period: emissions shall he calculated on a 12-

month rolling average basis. At the end of each month, oW,ner/operator shall calculate a 

new 12-month rolling average! emission mtc in Ib/MMBtu from the arithmetic avcmge of 

all valid and substitute hourly emission rates from the CEMS for the most recent 12 

months. 

e. Limits with an annual calendar averaging period: emissions shall be calculated on 

a calendar year basis. At the end of each calendar year, owner/operator shall calculate a 

new emission rate in Ib/MMBtu from the arithmetic average of all valid and substitute 

hourly emission rates from the CEMS for the preceding year. 
ENCLOSURE 3 

DRAFT COMPLIANCE DETERMINATION LANGUAGE FOR COLORADO 

BART LIMITS 

2111110 

I. Monitoring, Recordkecping, and Reporting 

A. Dctinitions 

"BART unit" means any unit subject to a BART emission limit in Table __ _ 

"Boiler operating day" means any twenty-fouf-hour period between midnight and 

the following midnight during which any fuel is combustcd at any time in a BART unit. 

"Continuous emission monitoring system" or "CEMS" means the equipment 

required by Ithis section I to sample. analyze, measure, and provide, by means of 

readings recorded at least once every J 5 minutes (using an automated data acquisition 

and handling system (DAHS) . a permanent record ofS02 or NOx emissions, other 

pollutant emissions, diluent, or stack gas volumetric flow ratc. 

"Substitute hourly emission rates" or "substitute hourly emission values" means 

any hourly emission rates or values calculated in accordance with the missing data 

substitution procedures of 40 CFR part 75, subpart D, where valid, quality assured CEMS 

data for that hour arc unavailable. 

B. Monitoring/Compliance Determination: S02 and NOx BART Limits 

At all times after the compliance deadline specified in " specify sectionlJ, the 

owner/operator of each BART unit shall maintain, calibrate, and operate a CEMS, in full 

compliance with the requirements found at 40 CFR part 75, to accurately measure S02, 

NOx, diluent, and stack gas volumetric flow rate from each BART unit. The CEMS shall 

be used to determine compliance with the S02 and NOx BART emission limits for each 

BART unit. 

In determining compliance with the S02 and NOx BART limits. all periods of 

emissions shall be included, including startups, shutdowns, emergencies, and 

malfunctions. 

NOTE: Per section 302(k) of the CAA, BART limits must be met continuously. The 

BART limits section of the SIP and Reg. 3 need to state that the BART limits apply 

at all times, including periods of SSM. 

I. Pounds Per Hour And Tons Per Year Limits 

For any hour in which fuel is combusted in the boiler, owner/operator shall 

calculate hourly S02 and NOx emissions in pounds at the CEMS in accordance with the 

monitoring procedures and requirements of 40 CFR part 75. In calculating hourly mass 
emissions and emissions rates, owner/operator shall use the conversion procedures 

specified in 40 CFR part 75, Appendix F, For any hour that valid, quality assured CEMS 

data are unavailable, emissions shall be calculated in accordance with the missing data 

substitution procedures in 40 CFR part 75, subpart D. These hourly values shall then be 

used to detennine compliance in accordance with the particular limit's averaging period, 

as follows: 

a. Pounds Per Hour Limits. If the limit [in Table _ (cross-refBART limit 

table)Jis expressed as a Iblhr limit, owner/operator shall calculate average Ib/hr emissions 

over the appropriate averaging period, as follows: 

i. Limits with a 30-day averaging period: Emissions shall be calculated on a 

3D-day rolling average basis. At the end of each boiler operating day, owner/operator 

shall calculate a new 3D-day rolling average emission rate in Iblhr from the arithmetic 

average of all valid and substitute hourly emission values from the CEMS for the most 

recent 30 boiler operating days 

ii. Limits with a 12-month averaging period: emissions shall be calculated 

on a 12-month rolling average basis. At the end of each month, owner/operator shall 

calculate a new 12-month rolling average emission rate in Iblhr from the arithmetic 

average of all valid and substitute hourly emission values from the CEMS for the most 

recent 12 months. 

b. Tons Per Year Limits. If the limit lin Table _ (cross-ref BART limit table)Jis 

expressed as a tons/yr limit. rolling 12-month total, total emissions in tonslyr shall be 

calculated on a 12-month rolling basis. At the end of each month. owner/operator shall 

calculate a new 12-month emissions total, in tons/yr, using all valid and substitute hourly 

emission values from the CEMS for the most recent 12 months. 

2. Pounds Per Million Btu Limits 

For any hour in which fuel is combusted in the boiler, owner/operator shall 

calculate hourly average S02 and NOx concentrations in pounds per million Btu at the 

CEMS in accordance with the requirements of 40 CFR part 75. For any hour that valid, 

quality assured CEMS data are unavailable, emissions shall be calculated in accordance 

with the missing data substitution procedures in 4D CFR part 75, subpart D. These hourly 

averages shall then be used to determine compliance in accordance with the particular 

limit's averaging period. as follows: 

a. Limits with a 3-hour averaging period: emissions shall be calculated on a 3-hour 

rolling average basis. At the end of each hour, owner/operator shall calculate a new 3-

hour average emission rate in Ib/MMBtu from the arithmetic average of the valid and 

substitute hourly emission rates from the CEMS for the most recent three hours. 

b. Limits with a 30-day averaging period: emissions shall be calculated on a 3D-day 

rolling average basis. At the end of each boiler operating day, owner/operator shall 

2 
calculate a new 30-day rolling average emission rate in IblMMBtu from the arithmetic 

average of all valid and substitute hourly emission rates from the CEMS for the most 

recent 30 boiler operating days. 

c. Limits with a 90-day averaging period: emissions shall be calculated on a 90-day 

rolling average basis. At the end of each boiler operating day, owner/operator shall 

calculate a new 90-day rolling average emission rate in Ib/MMBtu from the arithmetic 

average of all valid and substitute hourly emission rates from the CEMS for the most 

recent 90 boiler operating days. 

d. Limits with a 12-month avemging period: emissions shall be calculated on a 12-

month rolling average basis. At the end of each month, owner/operator shall calculate a 

new 12-month rolling average emission rate in Ib/MMBtu from the arithmetic average of 

all valid and substitute hourly emission rates from the CEMS for the most recent 12 

months. 

e. Limits with an annual calendar averaging period: emissions shall be calculated on 

a calendar year basis. At the end of each calendar year, owner/operator shall calculate a 

new emission rate in Ib/MMBtu from the arithmetic average of all valid and substitute 

hourly emission rates from the CEMS for the preceding year. IINeed to address 

bubbled units.1I 

C. Monitoring/Compliance Determination: Particulate BART Limits 

I. EGU Particulate BART Limits. 

Compliance with the particulate BART emission limits for each EGU BART unit 

shall be determined from annual performance stack tests. Within 60 days of the 

compliance deadline specified in , and on at least an annual basis thereafter, the 

owner/operator of each EGU BART unit shall conduct a stack test on each unit to 

measure particulate emissions using EPA Method 5, 58, 5D, or 17. as appropriate, in 40 

CFR part 60, Appendix A. A test shall consist of three runs, with each run at least 120 

minutes in duration and each run collecting a minimum sample of 60 dry standard eubic 

feet. 

In addition to annual stack tests, owner/operator shall monitor particulate 

emissions for compliance with the BART emission limits in accordance with the 

applicable Compliance Assurance Monitoring (CAM) plan developed and approved in 

accordance with 40 CFR part 64. 

2. CEMEX Particulate BART Limits. /lNeed to address CEMEX particulate 

limits - 20% opacity and Iblton of dry feed.1I 

D. Recordkeeping 

Owner/operator shall maintain the following records for at least five years: 

3 
I. All CEMS data, stack test data, and data collected pursuant to the CAM plan, 

including the date, place, and time of sampling, measurement, or testing; parameters 

sampled, measured, or tested and results; the company, entity, or person that performed 

the testing, if applicable; and any field data sheets from testing. 

2. Records of quality assurance and quality control activities for emissions 

measuring systems including, but not limited to, any records required by 40 CFR Part 75. 

3. Records of all major maintenance activities conducted on emission units, air 

pollution control equipment, and CEMS. 

4. Any other records required by 40 CFR parts 64 and 75 . 

E. Reporting requirements 

Owner/operator shall submit quarterly excess emissions reports no later than the 

30lh day following the end of each calendar quarter. Excess emissions means emissions 

that exceed the emissions limits specified in __ above. Owner/operator shall submit 

reports of any required performance stack tests for particulate matter, within 60 calendar 

days after completion of the test. Owner/operator shall also submit quarterly reports of 

any exceedances or excursions under the approved CAM plan, and steps taken to correct 

the exeeedances or excursions, in accordance with 40 CFR 64.9(a). 

Owner/operator shall also submit quarterly CEMS performance reports, to include 

dates and duration of each period during which the CEMS was inoperative (except for 

zero and span adjustments and calibration checks), reason(s) why the CEMS was 

inoperative and steps taken to prevent recurrence, any periods for which missing data 

substitution procedures were used, any CEMS repairs or adjustments, and results of any 

CEMS performance tests required by 40 CFR part 75 (Relative Accuracy Test Audits, 

Relative Accuracy Audits, and Cylinder Gas Audits). 

4 
1

September 14, 2010 

Rick Boddicker, Environmental Senior Scientist 

South Dakota Department of Environment and Natural Resources 

523 East Capital, Joe Foss Building 

Pierre, South Dakota 57501 

 Re: Comments on the South Dakota Draft Regional Haze SIP Re: Comments on the South Dakota Draft Regional Haze SIP Re: Comments on the South Dakota Draft Regional Haze SIP 

Dear Mr. Boddicker: 

 Sierra Club, the National Parks Conservation Association, and Plains Justice 

respectfully submit the following comments on South Dakota’s draft regional haze plan. 

South Dakota’s draft plan represents a good start to a rule that will protect nearby Class I 

areas from haze-causing pollution. However, the state’s plan could, and must, go further 

still to ensure the goal of natural visibility by 2064. 

Best Available Retrofit Technology (BART) Determination for Big Stone Power Plant 

 Federal regulations mandate that states’ regional haze SIPs include emission 

limitations representing BART for each BART-eligible source. 40 C.F.R. §51.308(e). Best 

available retrofit technology or BART is defined as follows: 

Best Available Retrofit Technology (BART) means 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. 

40 C.F.R. § 51.301. 

 BART is to be determined based on a five factor analysis. 40 C.F.R. Part 51, 

Subpart Y, Section I.F.1. EPA’s five factor analysis requirements stems from statutory and 

regulatory requirements regarding how BART is to be determined. Specifically: 
2

The determination of BART must be based on an analysis of the best system 

of continuous emission control technology available and associated emission 

reductions achievable for each BART-eligible source that is subject to BART 

within the State. In this analysis, the State must take into consideration the 

technology available, the costs of compliance, the energy and nonair quality 

environmental impacts of compliance, any pollution control equipment 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. 

40 C.F.R. § 51.308(e)(1)(ii)(A). See also § 169A(g) of the Clean Air Act 

 South Dakota’s draft regional haze plan states that, because Big Stone I has a 

generating capacity less than 750 MW, the state is not required to follow the BART 

Guidelines in 40 C.F.R. Part 51, Subpart Y. South Dakota Draft Regional Haze Plan at 82. 

Specifically, the South Dakota Regional Haze Plan states “...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.” Id.

 While the Federal regional haze regulations mandate that BART for units of 750 

MW or greater must follow the BART Guidelines, the fact that Big Stone I has a generating 

capacity less than 750 MW does not mean South Dakota does not have to follow a reasoned 

analysis in evaluating BART and setting BART emission limitations. The state’s BART 

requirements still must comply with BART as defined at 40 C.F.R. § 51.301 and, in 

evaluating the “best system of continuous emission reduction,” the state must include the 

top level of pollutant removal efficiency of the control being evaluated. This would include 

evaluation of emission limits required as lowest achievable emission rate (LAER) and best 

available control technology (BACT), and must also include the top levels of pollution 

control achieved at facilities anywhere including outside the United States. Thus, there is 

no justification for the state to ignore the fact that pollution controls can be designed and 

operated at varying levels of control efficiency. If the state does not consider the 

capabilities of the various pollution controls evaluated in the case by case BART analysis, 

its cost impacts analysis will be skewed in favor of the lowest capital cost equipment rather 

than properly evaluating cost impacts in terms of amount of pollution reduced. Thus, 

South Dakota must consider the varying levels of control efficiency of pollution controls in 

the BART analyses for Big Stone. 

A. BART for Sulfur Dioxide (SO2 A. BART for Sulfur Dioxide (SO2 . BART for Sulfur Dioxide (SO2) Emissions at Big Stone Emissions at Big Stone Emissions at Big Stone 

 

 The BART analysis for SO2 at Big Stone I is flawed because Otter Tail and the state 

failed to consider the level of control achievable with wet and dry scrubbers and because it 

is based on coal with higher uncontrolled SO2 emissions than Otter Tail has historically 

burned at Big Stone I. Further, DENR and Otter Tail failed to consider the other 

environmental benefits of a wet scrubber. 

1. Analysis of BART Emission Limits Achievable Must Be 1. Analysis of BART Emission Limits Achievable Must Be Based on Current Coal on Current Coal 

Characteristics. Characteristics
3

 Based on the percent removal assumed for the wet and dry scrubbers and the 

proposed emission limits, it is clear that Otter Tail assumed an uncontrolled SO2 emission 

rate of approximately 0.86 lb/MMBtu.1 This is what Otter Tail claimed was the highest 24-

hour average rate of SO2 emitted by Big Stone I during 2001-2003. Table 1.2-1 of Otter 

Tail’s November 2009 BART Submittal to DENR. While the BART guidelines require use 

of highest daily emissions in the visibility modeling analysis, that is not an appropriate 

starting point for setting a BART emission limit that is supposed to reflect BART, 

especially given that the BART emission limits apply on a 30 day average basis. 

 A review of the annual average SO2 emission rates from Big Stone I over the last 10 

years from EPA’s Clean Air Markets Database shows that the highest annual average SO2 

emission rate was no higher than 0.70 lb/MMBtu. This emissions rate reflects the 

uncontrolled SO2 emissions from Big Stone I since it currently has no SO2 controls. DENR 

should have used this emission rate, or, at worst, determined the highest 30 day average 

uncontrolled SO2 emission rate, in setting the BART emission limit for Big Stone based on 

the control efficiency of the SO2 controls evaluated. 

2. DENR and Otter Tail Failed to Evaluate the Highest SO2 Removal Efficiencies 

Achievable with a State- Achievable with a State-of-the-Art Wet Scrubber. Art Wet Scrubber. Art Wet Scrubber. 

 DENR assumed a wet scrubber would achieve 95% control from the worst case daily 

SO2 emission rate at Big Stone of 0.86 lb/MMBtu. Using the highest uncontrolled SO2 

emissions from the past 10 years of 0.70 lb/MMBtu, the BART emission limit with a 95% 

efficient wet scrubber should be no higher than 0.035 lb/MMBtu. 

Further, wet scrubbers can achieve higher removal efficiency, as high as 99%. A 

prime example is the Chiyoda CT-121 FGD. Vendor information for this technology 

indicates that this scrubber has achieved 98-99% SO2 removal even with low sulfur coal.2 

For example, the Chiyoda’s bubbling jet reactor has consistently achieved >99% SO2

removal during long-term operation at the Shinko-Kobe power plant in Japan. This facility 

consists of two 700-MW coal-fired utility boilers. The wet FGD was designed to achieve 

0.014 lb SO2/MMBtu (9 ppmv at 3% oxygen) on an instantaneous basis and has 

consistently exceeded this level of control while treating gases with inlet SO2 concentrations 

of 1.78 lb/MMBtu.3 This technology has been guaranteed by Chiyoda to achieve 99% SO2

removal on three coal-fired boilers in Japan.4 It also has been demonstrated in the U.S. at 

the University of Illinois’s Abbott power plant, Georgia Power’s Plant Yates5, Dayton 

 

1

 For example, Otter Tail’s BART analysis assumed a controlled SO2 emission rate of 0.043 

lb/MMBtu with a wet scrubber at 95% control. Table 3.3-1 of Otter Tail’s November 2009 

BART Submittal to DENR. This reflects an uncontrolled SO2 emission rate of 0.86 lb/MMBtu. 

2

 See Black & Veatch vendor brochure on CT-121, Ex 1. 

3

 Yasuhiko Shimogama, Hirokazu Yasuda, Naohiro Kaji, Fumiaki Tanaka, and David K. Harris, 

Commercial Experience of the CT-121 FGD Plant for 700 MW Shinko-Kobe Electric Power 

Plant, Paper No. 27, presented at MEGA Symposium, Air & Waste Management Association, 

May 19-22, 2003, Ex.2. 

4

 CT-121 FGD Process – Jet Bubbling Reactor, http://www.bwe.dk/fgd-ct121.html. 

5

 Emission-control Technologies Continue to Clear the Air, Power, May/June 2002. 
4

Power & Light’s Killen Unit 2,6 and Plant Bowen Unit 3.7 It has also been licensed for 

installation on several additional units in the US, including the other three units at Plant 

Bowen in Georgia, the other units at Dayton Power & Light’s Killen plant, Dayton Power & 

Light’s Stuart plant, and AEP’s Big Sandy Unit 2, Conesville Unit 4, Cardinal Units 1 and 

2, and Kyger Creek, among others.8 Black & Veatch and Southern Company are both U.S. 

licensees. Further, this technology also has shown to be very effective in removing fine 

particulates, oxidized and elemental mercury, and acid gases, and the technology uses less 

energy compared to traditional wet scrubbers. 

Further, Mitsubishi, a vendor of scrubber systems, reports it has guaranteed SO2

removal efficiencies up to 99.8 percent, including for coal-fired boilers.9, 10, 11

 Finally, a recent Lake Michigan Air Directors Consortium (“LADCO”) and the 

Midwest Regional Planning Organization (“MRPO”) presentation indicated that advanced 

FGD technologies could achieve 99.5% control for $1,240 to $2,875 per ton of SO2 removed 

and wet FGD could achieve 99% SO2 control for $1,881 to $3,440 per ton of SO2 removed. 

Ex. 8 These costs are well within the range that EPA normally considers cost effective in 

best available control technology (BACT) analyses. 

In addition, the Georgia Environmental Protection Division recently issued a PSD 

permit for Plant Washington which will burn Powder River Basin coal as its primary coal, 

and this permit requires a 97.5% SO2 removal efficiency to be achieved on a 30 day rolling 

average basis. A copy of that permit is attached as Exhibit 9. 

 An annual average was compiled of SO2 emission rates for 2008 using data 

submitted to the Clean Air Markets website by similar coal-fired electric generating units. 

The annual average SO2 emission rates were ranked from low to high to identify the best 

performing similar sources. This analysis is shown in Ex. 10. The best performing similar 

source in 2008 was Pleasant Prairie Units 1 and 2 in Wisconsin. The 2008 annual average 

achieved at Unit 1 was 0.021 lb/MMBtu and at Unit 2, 0.027 lb/MMBtu. These units are 

equipped with a wet limestone scrubber and burn a low sulfur Powder River Basin Coal. 

 

6

 See Black & Veatch, First Black&Veatch/Chiyoda Wet Flue Gas Desulfurization System in 

North America Successfully Goes Operational, Ex. 3. 

7

 Blankinship, Steve, Go Take a Bath, Power Engineering, October 2008, available at 

http://pepei.pennnet.com/display_article/342997/6/ARTCL/none/none/1/Go-Take-a-Bath/. 

8

 Chiyoda Licenses Its Flue Gas Desulfurization Technology in USA Newly for 5 Coal-Fired 

Generation Units, Press Release, May 2, 2005, Ex. 12; Chiyoda Licenses its Flue Gas 

Desulfurization Process in USA for Georgia Power Owned 4 FGD Units, January 26, 2005, Ex. 

4. 

9

 Jonas S. Klingspor, Kiyoshi Okazoe, Tetsu Ushiku, and George Munson, High Efficiency 

Double Contact Flow Scrubber for the U.S. FGD Market, Paper No. 135 presented at MEGA 

Symposium, Air & Waste Management Association, May 19-22, 2003, p.8, Table 4, Ex. 5. 

10 Yoshio Nakayama, Tetsu Ushiku, and Takeo Shinoda, Commercial Experience and ActualPlant-Scale Test Facility of MHI Single Tower FGD, Ex. 6. 

11 Mitsubishi High SO2 Removal Experience, Ex. 7. 
5

Similar data for the first six months of 2009 indicate that other units are currently 

achieving even lower SO2 emissions, including Iatan Unit 1 at 0.0051 lb/MMBtu; Muscatine 

Unit 9 at 0.013 lb/MMBtu; Hammond Unit 2 at 0.016 lb/MMBtu; Gorgas Unit 10 at 0.017 

lb/MMBtu; Prairie Creek Unit 4 at 0.019 lb/MMBtu; Hopewell Power Station Units 1 and 2 

at 0.020 lb/MMBtu; and Centralia Unit BW22 at 0.021 lb/MMBtu. 

Thus, the Big Stone I BART Analysis should have evaluated these levels of control 

based on the actual uncontrolled SO2 emissions emitted by the unit over a 30 day average 

basis in its evaluation of a wet scrubber for BART. 

3. DENR and Otter Tail Failed to Evaluate the Highest SO2 Removal Efficiencies 

Achievable with a State- Achievable with a State-of-the-Art Dry Scrubber. Art Dry Scrubber. Art Dry Scrubber. 

DENR assumed only 90% control with a dry scrubber at Big Stone I and proposed an 

emission limit of 0.09 lb/MMBtu, which reflects somewhat less than 90% SO2 removal 

efficiency from the worst case 24-hour SO2 emissions of 0.86 lb/MMBtu. Using the highest 

uncontrolled SO2 emissions from the past 10 years of 0.70 lb/MMBtu, the BART emission 

limit with a 90% efficient dry scrubber should be no higher than 0.07 lb/MMBtu. DENR 

and Otter Tail thus should have evaluated this SO2 emission rate achievable with a dry 

scrubber in the BART analysis. 

There have been several proposed coal-fired power plants burning low sulfur Powder 

River Basin coal that have proposed to use dry scrubbers to meet PSD requirements and 

that are subject to higher control efficiency requirements and/or lower SO2 BACT limits 

than 0.09 lb/MMBtu. Those facilities include the Newmont Nevada TS power plant, the 

proposed White Pine power plant, the proposed Toquop power plant, and the Dry Fork 

power plant. The Newmont Nevada power plant is subject to a minimum 95% SO2 removal 

efficiency requirement when burning coal with a sulfur content equal to or greater than 

0.45% and is subject to a minimum 91% SO2 removal efficiency when burning coal with 

sulfur content less than 0.45%.12 This facility is currently operating in compliance with its 

limits. The Newmont Nevada is also subject to an SO2 BACT limit of 0.065 lb/MMBtu 

when burning coal with less than 0.45% sulfur content. The proposed Toquop permit 

included an SO2 BACT limit of 0.06 lb/MMBtu on a 24-hr average basis.13 The Dry Fork 

power plant in Wyoming, which is also currently under construction, will burn Powder 

River Basin coal, will be equipped with a dry scrubber, and is subject to an SO2 BACT limit 

of 0.07 lb/MMBtu.14 

Thus, the Big Stone I BART Analysis should have evaluated these levels of control 

based on the uncontrolled SO2 emissions emitted by the unit over a 30 day average basis. 

4. DENR’s Determination of Cost Effectiveness of a Wet Scrubber is within the 

Range of the Costs of Other SO2 BART Determinations. Range of the Costs of Other SO2 BART Determinations. BART Determinations. 

 

 

12

 See Section V.A.2.a.8. of Newmont Nevada Permit, Ex. 11. 

13

 See Section V.A.2..a.(8) of draft Toquop permit, Ex. 12. 

14

 See Dry Fork PSD Permit, Ex. 13. 
6

 Even if we ignore the fact that DENR and Otter Tail failed to evaluate the control 

efficiencies and emission rates achievable with a wet scrubber at Big Stone I, DENR’s cost 

effectiveness calculation of the wet scrubber at an SO2 emission rate of 0.043 lb/MMBtu of 

$1,699/ton is a reasonable cost when compared to other SO2 BART determinations. 

According to a spreadsheet put together by the National Park Service with cost information 

for BART determinations, the average cost effectiveness of SO2 BART controls is $1,571 

lb/ton, the mean cost effectiveness is $1,966/ton, and the highest cost required to meet SO2 

BART was $7,309 lb/MMBtu. Because similar facilities will have to incur similar costs to 

meet BART, DENR has no justification to discount installation of a wet scrubber based on 

costs. 

5. DENR and Otter Tail Did Not Adequately Evaluate th 5. DENR and Otter Tail Did Not Adequately Evaluate the Other Environmental e Other Environmental 

Benefits of a Wet Scrubber. Benefits of a Wet Scrubber. 

DENR and Otter Tail did not fully evaluate the environmental impacts of a wet 

scrubber versus a dry scrubber. Specifically, the higher SO2 removal efficiencies and very 

low SO2 emission rates, on the order of single digit parts per million (ppm) concentrations, 

will be needed for the effective removal of carbon dioxide (CO2) from the gas stream. Many 

of the amine-based CO2 control methods currently under development are very sensitive to 

sulfur and thus require very low SO2 inlet concentrations, on the order of 1 to 2 ppm.15 This 

will require 98-99%+ SO2 removal or an outlet SO2 of 0.01 lb/MMBtu. It will be more cost 

effective and operationally simpler to design and install controls in one retrofit program. 

It is well recognized that it is not a matter of if but when Congress and/or EPA will 

mandate CO2 reductions from industrial sources such as Big Stone. Thus, if an SO2 

control technology will better prepare Big Stone to be able to effectively remove CO2 in the 

future, that must be taken into account in the BART analysis as another environmental 

benefit from a wet scrubber versus a dry scrubber. Indeed, as described above, there are 

wet scrubber technologies available that can remove 99+% of the SO2. Dry scrubbers do 

not achieve as high levels of SO2 emission reduction. 

 Another environmental benefit of wet scrubbers versus dry scrubbers is greatly 

improved removal of hydrogen chloride (HCl) and hydrogen fluoride (HF) as compared to a 

dry scrubber. Actual measurements have demonstrated that very high HCl and HF control 

efficiencies, 99.7% to 99.9% for HCl and 99.8% to 99.9% for HF, are being achieved at wet 

scrubbed plants.16 Such high levels of HCl and HF removal have not been shown for coal 

fired boilers controlled with dry scrubbers. Tests at the recently constructed Wygen II, an 

electrical generating unit burning subbituminous coal from the Powder River Basin and 

equipped with a spray dryer absorber, showed only 49% removal of HF and 58% removal of 

HCl. According to the Institute of Clean Air Companies, “wet scrubbers also provide 

significant removal of arsenic, beryllium, cadmium, chromium, lead, manganese, and 

mercury from flue gas.”17

 

15 Chuck Dene, Lesley A. Baker, and Robert J. Keeth, FGD Performance Capability, Mega 

2008, Ex. 14. 

16

 See 10/14/08 Letter from Alstom to Duke Energy, Exs. 15A and B. 

17

 See http://www.icac.com/i4a/pages/index.cfm?pageid=3401. 
7

 Further, lower emissions of SO2 that are achievable with a wet scrubber also equate 

to lower PM2.5 concentrations since there will be less SO2 in the air to contribute to sulfate 

formation. And studies have demonstrated that sulfate addition to sulfate-limited water 

bodies or wetlands can increase the transformation of mercury to its neurotoxic form, 

methylmercury.18 Thus, with lower SO2 emissions from Big Stone via the use of a wet 

scrubber as compared to a dry scrubber, the result should be less sulfate deposition which 

should decrease methylization of mercury. 

 

 These environmental benefits must also be considered in evaluating the 

environmental benefits of the SO2 control options for BART at Big Stone I. 

B. BART for Nitrogen Oxides (NOx) Emissions at Big Stone. 

 

The BART analysis for NOx at Big Stone I is flawed because Otter Tail and the state 

failed to consider the level of control achievable with the proposed selective catalytic 

reduction (SCR) at Big Stone I. 

 

 DENR has proposed a NOx emission limit of 0.10 lb/MMBtu, on a 30 day average, 

based on the use of separated overfire air and installation of SCR. The Big Stone I boiler 

has already been modified to use overfire air as a NOx control.

19 A review of monthly 

average NOx emission rate data from EPA’s Clean Air Markets Database shows that the 

highest monthly emission rate of NOx in 2009 was 0.71 lb/MMBtu. DENR’s proposed 0.10 

lb/MMBtu NOx emission rate therefore reflects 85.9% NOx control with the SCR. However, 

SCR systems can achieve 90+% reductions in NOx. The emission limit reflective of a 90% 

reduction in NOx would be 0.071 lb/MMBtu. This level of emissions has commonly been 

required as BACT in the last decade for numerous coal-fired boilers. In more recent years, 

lower levels of NOx have been required as BACT. 

A review of recent SCR retrofits definitively shows that very high levels of NOx 

removal are being achieved by recent SCR retrofit installations. NOx emission rates less 

than 0.05 lb/MMBtu are routinely achieved, and NOx removal efficiencies are typically 

around 90%.20 Permitting agencies have required lower NOx limits in recent BACT 

determinations, with many proposed and required BACT limits of 0.05-0.06 lb/MMBtu and 

at least one NOx BACT limit as low as 0.035 lb/MMBtu.21

 

18

 See, e.g., Jeremiason, Jeff D. et al., Sulfate Addition Increases Methylmercury Production in 

an Experimental Wetland, Environ. Sci. Technol., 2006, 40, 3800-3806, Ex. 16; Krabbenhoft, 

David P. et al., Unravelling the Complexities Mercury Methylation in the Everglades: The Use 

of Mesocosms to Test the Effects of “New” Mercury, Sulfate, Phosphate, and Dissolved Organic 

Carbon, available at http://sofia.usgs.gov/projects/merc_carbon/hgmeso_geer03abs.html. 

19 Terry Graumann of Otter Tail testified that the overfire air system had already been installed at 

Big Stone I to comply with acid rain requirements in the Big Stone Title V permit contested case 

hearing, in testimony given August 21, 2008. 

20

 See Erickson, Clayton A. et al., Selective Catalytic Reduction System Performance and 

Reliability Review, The 2006 MEGA Symposium, Paper # 121, Ex. 17. 

21 The Plant Washington Permit has a NOx limit of 0.050 lb/MMBtu on a 30 day rolling average 
8

 Thus, the proposed NOx BART limit of 0.10 lb/MMBtu fails to reflect emissions level 

achievable with the proposed BART controls (i.e., separated overfire air and SCR). DENR 

must evaluate this lower level of NOx emissions in its BART analysis for Big Stone. 

C. BART for PM at Big Stone. C. BART for PM at Big Stone. 

 DENR has proposed as BART for PM an emission limit of 0.012 lb/MMBtu and the 

use of a fabric filter baghouse. However, baghouses can achieve much lower emission rates, 

and permitting authorities have required lower limits as BACT. For example, the Plant 

Washington permit has a filterable PM limit of 0.010lb/MMBtu. Ex. 9. Thus, DENR must 

lower the PM BART emission limit of 0.010 lb/MMBtu if not lower. 

 In addition, EPA’s BART Guidelines require that, because BART limits must be met 

on a continuous basis, there must be adequate provisions ensuring compliance with BART 

on a continuous basis. Yet, DENR has only proposed an annual stack test to demonstrate 

compliance with its proposed PM BART limit. DENR could require a PM continuous 

emission monitoring system (CEMS) to ensure continuous compliance with the BART limit, 

such as is required by the Plant Washington permit to meet a 0.010 lb/MMBtu emission 

limit. Alternatively, DENR should impose an opacity limit reflective of BART, which 

should be a limit of no more than 10% opacity. Given that Big Stone already has 

continuous opacity monitoring (COMs), the opacity limit would help ensure continuous 

compliance with the PM BART limit. 

Many coal plant permits include stringent opacity limits as part of the BACT limits 

for those facilities. The MidAmerican facility in Council Bluffs, Iowa, has an opacity limit of 

5 percent. The Plum Point facility in Osceola, Arkansas, has a BACT limit of 10 percent 

opacity. The Wisconsin Department of Natural Resources set a 10 percent opacity limit as 

BACT for the Fort Howard (Fort James) Paper Company’s 500 MW CFB boiler. The Desert 

Rock permit has a 10% opacity limit. 

In summary, DENR must impose a PM BART limit reflective of the best system of 

continuous emission reduction, and limits lower than 0.012 lb/MMBtu can be met with a 

baghouse. DENR should require either PM CEMS or set an opacity limit reflective of 

BART in addition to a lb/MMBtu limit and use COMs to ensure continuous compliance with 

the opacity limit and use that data as an indicator of continuous compliance with the PM 

BART limit. 

D. There Should Be No Exemptions from BART Emission Limits During Startup and 

Shutdown. Shutdown. 

 As EPA has said in the BART Guidelines, BART emission limitations must be met 

on a continuous basis pursuant to section 302(k) of the Clean Air Act. Yet, DENR has 

proposed to exempt Big Stone from meeting the lb/MMBtu BART emission limits during 

startup and shutdown. Startup and shutdown are part of the normal operations of a power 

plant like Big Stone, and startup and shutdown emissions impact visibility and regional 

 

and 0.030 lb/MMBtu on a 12 month average when burning Powder River Basin coal. See Ex. 9. 
9

haze. So DENR’s proposed BART limits must include periods of startup and shutdown. 

Further, there is no justification to exempt Big Stone from meeting BART limits during 

startup and shutdown. Numerous permitting authorities have issued as stringent if not 

more stringent BACT limits for coal-fired boilers with no exemptions for startup and 

shutdown. Further, during the 2008 contested case hearing for the Big Stone II permit, 

Otter Tail’s Terry Graumann made clear that they were not requesting exemptions from 

emission limits during periods of startup or shutdown, and Otter Tail’s Mark Rolfes 

indicated the pollution controls would operate during startup and shutdown.22

 Thus, not only is continuous compliance with BART limits required under federal 

rules, but there is no technical justification for exemptions from BART limits during 

startup and shutdown. Thus, these BART exemptions must be deleted. 

E. The State’s Proposed BART Regulation Must Make Clea E. The State’s Proposed BART Regulation Must Make Clear that the Emission Limitations r that the Emission Limitations 

Apply to Big Stone I. Apply to Big Stone I. 

 

 The EPA’s BART Guidelines require that the state impose BART through 

enforceable requirements and that the enforceable requirements require that BART be met 

as expeditiously as practicable but no later than 5 years from the date EPA approves the 

state’s regional haze SIP. DENR has proposed a state regulation to make these 

requirements enforceable at ARSD 74:36:21:06-09. However, the regulation specifying the 

emission limits fails to specify that Big Stone is subject to these emission limits. The 

regulation must identify the source that is subject to these emission limits ensure 

enforceability of the BART limits. 

 Second, regarding the compliance timeframe, the BART regulation should require 

compliance with the PM BART limit now given that Big Stone has already installed a fabric 

filter baghouse and can comply with the BART limit now. 

 

Given that South Dakota is not meeting its “glide path” milestones to natural 

visibility conditions by 2064, it is imperative that DENR require Big Stone to install the 

most effective BART controls and meet stringent emission limits. We appreciate your 

consideration of our comments. 

Sincerely, 

Holly Bressett 

Project Attorney 

Sierra Club Environmental Law Program 

85 Second St., 2nd Floor 

San Francisco, CA 94105 

(415) 977-5646 (phone) 

(415) 977-5793 (fax) 

Lynn McClure 

Midwest Regional Director 

National Parks Conservation Association 

 

22 See Big Stone Contested Case Hearing Transcript, August 2008, at 617-618, 679 and 602-603. 
10

8 South Michigan Ave., Suite 2900 

Chicago, IL 60603 

312-263-0111 office 

312-343-7216 cell 

www.npca.org

Carrie La Seur, D.Phil., J.D., LEED A.P. 

President & Founder 

Plains Justice 

310 N. 27th St., Ste. 12 

Billings, MT 59101 

http://www.plainsjustice.org/ 

406-696-8700 

866-484-2373 (fax) 

Exhibits 
215 South Cascade Street 

PO Box 496 

Fergus Falls, Minnesota 56538-0496 

218 739-8200 

www.otpco.com 

August 31, 2010 

Mr. Rick Boddicker 

Senior Environmental Scientist 

South Dakota Department of Environment 

and l'Jatural Resources 

523 East Capitol 

Joe Foss Building 

Pierre, SD 57501-3181 

Dear Mr. Boddicker: 

Subject: Connnent - Proposed Regional Haze Program 

Chapter 74:36,21 

RECEIVED 

SEP 022010 

AIR QUALITY 

PROGRAM 

C» OriER~;;:rIIJ=L= POWER COMPANY 

The following connnent is offered by Otter Tail Power Company as operating agent for Big 

Stone Plant. Big Stone Plant is co-owned by North Western Corporation d/b/a NorthWestern 

Energy, Montana-Dakota Utilities Co, A Division ofMDU Resources Gronp, Inc" and Otter 

Tail Power Company, a wholly owned subsidiary of Otter Tail Corporation. 

Otter Tail suggests the following clarifying revision to ARSD 74:36:21: 11: 

74:36:21:11. Permit meaifieatieB required for BART determination. The owner or 

operator of a BART-eligible source shall submit an application in accordance with § 

74:36:20 to modify its operations to include the controls, emission limits, monitoring, 

recordkeeping, artd reporting requirements identified in the BART determination and 

approved by the department in aeeordanee with § 74 :36:20. 

Thank you for your consideration of our connnent. 

Manager, Environmental Services 

An Equal Opportunity Employer AN ~ OTTERTAIL COMPANY