January 8, 2010

Via email:

Terry O’Clair

Director, Division of Air Quality

North Dakota Department of Health

918 East Divide Avenue

Bismarck, North Dakota 58501-1947

toclair@nd.gov

RE: Comments on North Dakota’s Regional Haze State 

Implementation Plan

Dear Mr. O’Clair:

On behalf of Dakota Resource Council, National Parks Conservation 

Association, Dakota Resource Council, Friends of the Boundary Waters 

Wilderness, Plains Justice, Dakotah Chapter of the Sierra Club, South Dakota 

Chapter of the Sierra Club, and Voyageurs National Park Association, we 

respectfully submit the following comments on the Draft North Dakota 

Regional Haze (RH) State Implementation Plan (SIP). Our organizations 

represent hundreds of North Dakotans and thousands of people throughout the 

nation that care deeply about protecting the air quality in our national parks 

and wilderness areas in the Dakotas and Midwest. We hope and strongly 

encourage the North Dakota Department of Health (NDDH) to revise its SIP 

by requiring further reductions in haze causing pollutants and otherwise 

advancing measures that will improve regional visibility.

For the reason stated herein, North Dakota’s regional haze plan is both legally 

and technically deficient. The regional haze plan fails to require sufficient 

reductions in visibility impairing pollutants from its major polluting sources 

and fails to provide a long term strategy that would meet reasonable progress 

goals. As addressed below, the State can and must achieve much greater 

emission reductions in haze causing pollution with available control 

technologies and/or by imposing more stringent emission limits reflective of 

the best level of continuous emission reduction in its Best Available Retrofit 

Technology (BART) determinations. In addition, the long-term strategy must

ensure appropriate BART requirements and other measures, including 

consideration of source retirement and replacement, to improve visibility in
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North Dakota and other downwind states’ Class I areas to ensure that the SIP will meet its share 

of the emission reductions needed to meet the reasonable progress goals for the area. 

Regional haze results from small particles in the atmosphere that impair a viewer’s ability 

to see long distances, color and geologic formation. While some haze causing particles result 

from natural processes, most result from anthropogenic sources of pollution. Haze forming 

pollutants including sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter (PM), 

volatile organic compounds (VOCs), and ammonia (NH3) contribute directly to haze or form 

haze after breaking down in the atmosphere. These air pollutants contribute to the deterioration 

of air quality and reduced visibility in our nation’s national parks and wildlife refuges. Visibility 

impairment is measured in deciviews, which is understood as the perceptible change in visibility. 

The higher the deciview value is, the worse the impairment. 

Through the Clean Air Act (CAA), Congress established ―as a national goal the 

prevention of any future, and remedying of any existing, impairment of visibility in the

mandatory class I Federal areas which impairment results from manmade air pollution.‖ 42 

U.S.C. §7491(a)(1). In order to meet this goal, a State is required to design an implementation 

plan to reduce and ultimately eliminate haze from air pollution sources within its borders that 

may reasonably be anticipated to cause or contribute to visibility impairment for any protected 

area located within or beyond that State’s boundaries. In creating and implementing the plan the 

State has an unparalleled opportunity to protect and restore regional air quality by curbing 

visibility impairing emissions from some of its oldest and most polluting facilities.

Each SIP must provide ―emission limits, schedules of compliance and other measures as 

may be necessary to make reasonable progress towards meeting the national goal.‖ 42 U.S.C. § 

7491(b)(2). Two of the most critical features of a SIP are requirements for (1) the installation of

BART for delineated major stationary sources of pollution and (2) a long-term strategy for 

making reasonable progress towards the national visibility goal. 42 U.S.C. § 7491(b)(2)(A) & 

(B).

There are two Class I areas in North Dakota—Theodore Roosevelt National Park and 

Lostwood National Wildlife Refuge Wilderness Area. Other Class I areas impacted by North 

Dakota sources of air pollution include: Badlands National Park and Wind Cave National Park 

in South Dakota, Medicine Lake National Wildlife Refuge Wilderness Area and U.L. Bend 

National Wildlife Refuge Wilderness Area in Montana, Boundary Waters Canoe Area 

Wilderness Area and Voyageurs National Park in Minnesota, and Isle Royale National Park and 

Seney National Wildlife Refuge Wilderness Area in Michigan. These Class I areas preserve the 

region’s inspiring landscapes, rare geologic formations, breathtaking water country, and diverse 

wildlife and vegetation. They also serve as living museums of our nation’s history. Visitors from 

across the nation and globe are drawn to these lands and their tourist dollars benefit state and 

local economies. 

National parks and wilderness areas are of great natural and cultural value and also 

engines for sustainable local capital. For example, in 2008, National Park Service units received 

over 274 million visits accounting for over $2.5 billion in revenue.1 National parks support $13.3 

 

1

See http://www.census.gov/compendia/statab/2010/tables/10s1215.pdf, Ex. 1.
Page 3 of 34

billion of local private-sector economic activity and 267,000 private-sector jobs.2They also 

attract businesses and individuals to the local area, resulting in economic growth in areas near 

parks that is an average of 1 percent per year greater than statewide rates over the past three 

decades.3 National parks also generate more than four dollars in value to the public for every tax 

dollar invested.4 Of the number of annual park visitors in 2008, approximately 516,804 people 

journeyed to Theodore Roosevelt National Park spending nearly half a million dollars. The same 

year 845,734 people visited Badlands National Park; 573,433 visited Wind Cave National Park; 

221,585 visited Voyageurs National Park and 14,038 visited Isle Royale National Park.5

Excessive emissions from North Dakota not only obscure the region’s scenic vistas 

Congress sought to protect, but also contribute to a host of public health problems as well as 

adverse impacts to wildlife and vegetation. For example, NOx and VOCs are precursors to 

ground level ozone, or smog. Ground level ozone is associated with respiratory diseases, asthma 

attacks, and decreased lung function.6SO2 pollution contributes to respiratory problems, 

particularly for children and the elderly, and aggravates existing heart and lung diseases. 

Exposure to particulate matter, made up of sulfates and nitrates, has been associated with 

reduced lung function, increased susceptibility to respiratory infections, chronic bronchitis, and

premature death.

7

The U.S. Environmental Protection Agency (EPA) has found that in 2015, the 

Regional Haze Rule also will provide substantial health benefits valued at $8.4 - $9.8 billion 

annually -- preventing 1,600 premature deaths, 2,200 non-fatal heart attacks, 960 hospital 

admissions, and over 1 million lost school and work days. The total annual cost will range from 

1.4 – 1.5 billion dollars.8These benefits are estimated under the assumption that the Regional 

Haze Rule will be implemented as intended-therefore these numbers may be lower if North 

Dakota does not revise its plan.

The regional haze program imposes a legal obligation on the State to abate the adverse 

visibility effects to which its haze causing facilities contribute in order to restore visibility levels 

to their natural conditions as mandated by the Clean Air Act. To prevent and remedy visibility 

impairment to the implicated Class I areas, North Dakota can and must revise and substantially 

improve the draft RH SIP. A strong regional haze program will not only help protect and restore 

treasured landscapes and the economies that rely on them but also benefit public health. With 

this in mind, we offer the comments below for consideration by the NDDH and strongly 

encourage the Department to strengthen its regional haze plan. 

 

2 Hardner and Gullison, ―The U.S. National Park System, An Economic Asset at Risk‖ (November 2006) [prepared 

for the National Parks Conservation Association]. Ex. 2. 

3

Id. 

4

Id. 

5

See http://www.nature.nps.gov/stats/index.cfm. 

6

70 Fed. Reg. 25162, 25169 (May 12, 2005).

7 U.S. EPA. Air Quality Criteria for Particulate Matter (Final Report, April 1996). U.S. Environmental Protection 

Agency, Washington, D.C., EPA 600/P-95/001.

8 EPA, Fact Sheet, Final Regional Haze Regulations for Protection of Visibility in National Parks and Wilderness 

Areas (June 2, 1999) at http://www.epa.gov/visibility/fs_2005_6_15.html, Ex. 3.
Page 4 of 34

In addition, we note that the public comment for North Dakota’s SIP was open for 30

days. It is common in other jurisdictions to provide for 45 or 60 day comment period. Given the 

lengthy history and technical complexity of this SIP, such an abbreviated window is not 

conducive to a full and fair evaluation by the public. We understand that the EPA has requested 

states to submit SIPs by January 15, 2010. Understandably, North Dakota would like to abide by 

this suggested timeline, however, the short turnaround—five business days from the end of the 

public comment period to the EPA deadline—does not provide NDDH an adequate amount of

time to genuinely consider public comments and make needed changes to the SIP. Accordingly, 

we request NDDH coordinate with EPA to submit the North Dakota SIP in a timely manner 

without compromising full consideration of public comments.

I. The Clean Air Act and Federal Regulation Require NDDH to Abate Visibility 

Impairment

In 1977, the Clean Air Act declared ―as a national goal the prevention of any future, and 

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

impairment results from manmade air pollution[]‖ where visibility has been determined to be an 

important value. 42 U.S.C. § 7491(a)(1) &(2). ―Manmade air pollution‖ is defined as ―air 

pollution which results directly or indirectly from human activities[.]‖ 42 U.S.C. §7491(g)(3). 

Congress adopted the visibility protection program to protect the ―intrinsic beauty and historical 

and archeological treasures‖ of specific public lands.9To protect these treasures, the regional 

haze program establishes a regulatory floor and requires states to design and implement 

programs at least as stringent as the national floor to curb haze causing emissions located within 

their jurisdictions. States are required to submit State Implementation Plans or SIPs if they host 

federally protected areas or the emissions of a facility located within a State ―may be reasonably 

be anticipated to cause or contribute to any impairment of visibility‖ for a protected area located 

beyond their borders. 42 U.S.C. §7491 (b)(2).

The SIP must contain ―emission limits, schedules of compliance and other measures as 

may be necessary to make reasonable progress towards meeting the national goal...‖ including

BART requirements for all eligible sources and a long-term strategy for making reasonable 

progress towards meeting the national goal. 42 U.S.C. §7491(b)(2)(A) &(B). 

BART is defined as an emission limitation

. . .based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction for 

each pollutant which is emitted by an existing stationary facility. The 

emission limitation must be established, on a case-by-case basis, taking 

into consideration the technology available, the costs of compliance, the 

energy and 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 

 

9

See H.R. REP. NO. 95-294, at 203–04 (1977). 
Page 5 of 34

visibility which may reasonably be anticipated to result from the use of 

such technology.

40 C.F.R. §51.301, emphasis added. BART limits are required for major stationary sources that 

were in existence on August 7, 1977 and began operating after August 7, 1962 and emit air 

pollutants that may reasonable be anticipated to cause or contribute to any impairment of 

visibility is a Class I area. 42 U.S.C. § 7491(b)(2)(A). The term ―major stationary source‖ is 

defined as sources that have the potential to emit 250 tons or more of any pollutant and fall 

within one of 26 categories of industrial sources defined by the Act. 42 U.S.C. § 7491(g)(7). A 

BART-eligible source is one that meets the above criteria and is responsible for an impact on 

visibility in a Class I area of 0.5 deciview or more. 40 C.F.R. Part 51, Appendix Y. BART must 

be installed and operated no later than five years after the SIP approval. 40 

C.F.R.§51.302(c)(4)(iv).

The SIP must also provide a long-term strategy for achieving reasonable progress toward 

meeting natural visibility conditions at mandatory Class I areas by 2064. 40 C.F.R. 

§51.308(d)(1)(i)(B). If a state’s reasonable progress goals do not anticipate restoring visibility to 

natural conditions by 2064 the state must demonstrate why the goal of attaining natural 

conditions by the established date is unreasonable. 40 C.F.R. §51.308(d)(1)(ii). The SIP must

provide for improved visibility on the most impaired days and ensure no degradation in visibility 

for the least impaired days. 40 C.F.R. §51.308(d)(1)(i)(B). The long-term strategy is typically a 

10-15 year plan containing enforceable measures designed to meet regional progress goals. In 

developing its plan, the State must document the technical basis for the SIP, including 

monitoring data, modeling, and emission information, including the baseline emission inventory 

upon which its strategies are based. 40 C.F.R. §51.308(d)(3)(iii).

In developing its long-term strategy, the State must consider all anthropogenic sources of 

visibility impairment and evaluate different emission reduction strategies beyond those 

prescribed by the BART provisions. 40 C.F.R §51.308(d). The state should consider ―major and 

minor stationary sources, mobile sources and area sources.‖ Id. At a minimum, the state must 

consider the following elements:

(A)Emission reductions due to ongoing air pollution control programs, including measures to 

address reasonably attributable visibility impairment;

(B) Measures to mitigate the impacts of construction activities;

(C) Emissions limitations and schedules for compliance to achieve the reasonable progress 

goal;

(D)Source retirement and replacement schedules;

(E) Smoke management techniques for agriculture and forestry management purposes 

including plans as currently exist within the State for these purposes;

(F) Enforceability of emission limitations and control measures; and

(G)The anticipated net effect on visibility due to projected changes in point, area, and mobile 

emissions over the period addressed by the long-term strategy. 

40 C.F.R. 51.208(d)(3)(v)(A)-(G).
Page 6 of 34

North Dakota’s regional haze plan falls far short of meeting reasonable progress 

goals. In fact, North Dakotas’s draft regional haze plan will only bring the state to, at 

most, 38% of its 2018 regional progress target at Theodore Roosevelt National Park and 

even less than that at Lostwood Wilderness Area. Table 8.11 of the draft North Dakota 

State Implementation Plan (SIP) for Regional Haze. The State appears to be claiming 

that the national visibility goal of returning to natural visibility conditions by 2064 is 

unattainable, because the the majority of regional haze pollution comes from sources in 

Canada and outside the state. Draft North Dakota SIP for Regional Haze at 44-45. While 

it may be true that some of the pollution responsible for haze in the State’s Class I areas 

is due to sources outside of North Dakota’s control, that does not relieve the State from 

requiring industrial sources within North Dakota to be subject to BART emission limits 

reflective of the best degree of continuous emission reduction achievable, nor does it 

relieve the State from adopting other measures to improve visibility in North Dakota and 

other downwind states’ Class I areas. 

Furthermore, to ensure that reasonable progress goals are met, North Dakota 

should actively encourage other states and Canada to reduce emissions impairing 

visibility in its state and region. State-to-state consultations are part of the regional haze 

process, and North Dakota is well within its rights to formally request reductions from 

other states where appropriate. The U.S. EPA, in comments on the FLM version of the 

draft SIP, suggests that a three-prong approach is appropriate: ―NDDH needs to be 

addressing sources within its control in North Dakota, requesting reductions from 

contributing states, and asking EPA to address the Canadian emissions.‖10 To the extent 

that North Dakota has not undertaken each of these actions, it should do so. While there 

are multiple opportunities for North Dakota to pursue to ensure reasonable progress goals 

are attained, the State may not use emissions from outside sources as a scapegoat to avoid 

in-state action. 

Our review of North Dakota’s proposed BART emission limits and controls 

shows that the State has clearly not required emissions controls and limits that reflect 

BART for the BART-eligible sources. This is discussed in detail below. Further, the 

State has not required any source emission reductions or source retirements other than its 

proposed BART requirements to meet reasonable progress requirements. Regardless of 

the impacts that other sources outside of North Dakota have on regional haze in North 

Dakota’s Class I area, North Dakota has a responsibility under the federal regional haze 

requirements to reduce haze causing emissions from its own sources of air emissions to 

do its part to meet the reasonable progress goals. Under the Long Term Strategy 

regulations, North Dakota is required to demonstrate that ―it has included in its 

implementation plan all measures necessary to obtain its share of the emission reductions 

needed to meet the progress goals for the area‖ even when other states contribute to 

visibility impairment in the State’s Class I areas. 40 C.F.R. §51.308(d)(3)(ii). Thus, the 

State cannot shirk its responsibility to address its sources of regional haze pollution by 

putting the blame on sources outside the state.

 

10 U.S. EPA Region 8 Comments on August 21, 2009 Draft Regional Haze SIP (FLM Consultation Version), 

Enclosure 1, p. 5. 
Page 7 of 34

Further, the State has a responsibility to reduce emissions from North Dakota 

sources that are reasonably anticipated to impact visibility in other states’ Class I areas. 

Minnesota is one such state, and Minnesota submitted a letter to the North Dakota 

Department of Health (NDDH) indicating the need for North Dakota electrical generating 

units to meet an average SO2 limit of 0.25 lb/MMBtu as well as the need for NOx

emission reductions from North Dakota sources. September 19, 2007 letter from the 

Minnesota Pollution Control Agency (MPCA) to NDDH and other states (Appendix 

J.2.1. of the draft North Dakota Regional Haze SIP). NDDH did not agree with these 

requests and stated that ―[a]dditional reductions from Minnesota sources may provide 

much greater reduction of visibility impacts.‖ August 22, 2008 letter from NDDH to 

MPCA at 2 (Appendix J.2.2. of the draft North Dakota Regional Haze SIP.)

North Dakota could achieve additional reductions in visibility impairing 

pollutants from its own sources, but this draft regional haze SIP and BART limits do not 

require such reductions. As we will show below, North Dakota could achieve much 

greater emission reductions in haze causing pollution with available control technologies 

and/or by imposing more stringent emission limits reflective of the best level of 

continuous emission reduction in its BART determinations.

II. NDDH’s Draft BART Determinations are Flawed

A. The SO2 BART Limits Fail to Reflect the Degree of SO2 Emission Reduction 

Achievable with the Best System of Continuous Emission Reductions.

NDDH simply has proposed the EPA’s presumptive BART limits as BART at 

most of the BART-eligible coal-fired electric utility steam generating units (EGUs) that 

NDDH determined were subject to BART. Specifically, NDDH proposed SO2 BART 

limits for Leland Olds Units 1 and 2, Milton R Young Unit 2, and Coal Creek Units 1 and 

2 of 0.15 lb/MMBtu or 95% control. While NDDH purported to do a case-by-case 

evaluation of BART for each EGU, it appears that the case-by-case analyses were simply 

written to support the imposition of EPA’s presumptive BART limits rather than to truly 

reflect the best level of continuous SO2 emission reduction at each EGU. 

EPA’s BART Guidelines include ―presumptive BART‖ emission limits for EGUs which 

were based on EPA’s broad review of the control technologies and emission limits that could be 

met cost effectively at a wide range of coal-fired power plants. See Sections IV.E.4 and 5 of the 

BART Guidelines in 40 C.F.R. Part 51, Appendix Y. However, it must be stated that EPA’s 

presumptive BART limits do not negate the need for the State to determine BART for each 

BART-eligible source on a case-by-case basis through a five factor analysis. The regulations 

and the Clean Air Act require the determination of BART to be source-specific. See 40 C.F.R. § 

51.308(e)(1)(ii)(A); § 169A(g) of the Clean Air Act. 

The five steps of determining BART are:

STEP 1 -- Identify All [fn 12] Available Retrofit Control 

Technologies,
Page 8 of 34

STEP 2-- Eliminate Technically Infeasible Options,

STEP 3-- Evaluate Control Effectiveness of Remaining Control 

Technologies,

STEP 4-- Evaluate Impacts and Document the Results, and

STEP 5 – Evaluate Visibility Impacts.

Fn 12: In identifying "all" options, you must identify the most stringent 

option and a reasonable set of options for analysis that reflects a 

comprehensive list of available technologies. It is not necessary to list all 

permutations of available control levels that exist for a given technology –

the list is complete if it includes the maximum level of control each 

technology is capable of achieving.

Section IV.D. of BART Guidelines at 40 C.F.R. Part 51, Appendix Y.

Clearly, EPA’s BART Guidelines require an evaluation of the top level of pollution 

reduction achievable with each control system evaluated in a BART analysis. EPA’s BART 

Guidelines provide that, if a control system can be operated at a wide range of control 

efficiencies, ―the most stringent emissions control level that the technology is capable of 

achieving‖ must be evaluated. Section IV.D.3. of the BART Guidelines at 40 C.F.R. Part 51, 

Appendix Y. The BART Guidelines further require that ―[y]ou should consider recent regulatory 

decisions and performance data (e.g., manufacturer's data, engineering estimates and the 

experience of other sources) when identifying an emissions performance level or levels to 

evaluate.‖ Id.

The BART Guidelines also provide:

In assessing the capability of the control alternative, latitude exists to consider 

special circumstances pertinent to the specific source under review, or regarding 

the prior application of the control alternative. However, you should explain the

basis for choosing the alternate level (or range) of control in the BART analysis. 

Without a showing of differences between the source and other sources that have 

achieved more stringent emissions limits, you should conclude that the level being 

achieved by those other sources is representative of the achievable level for the 

source being analyzed.

Id.

Further, while one can consider varying levels of pollution control in evaluation of a 

particular control device, one ―must consider the most stringent level as one of the control 

options.‖ Id.

NDDH did not follow these guidelines or otherwise meet the intent of the BART 

requirements because it did not evaluate the most stringent option available for reducing 

SO2 from the State’s EGUs as is discussed further below.
Page 9 of 34

1. NDDH Cannot Take Into Account Projected Worst Case Sulfur Content of Coal 

in Setting BART Limits

For all of the coal-fired EGU SO2 BART determinations, NDDH relied on worst 

case projections of sulfur content of the coal to be burned in justifying the SO2 emission 

limits as BART. For example, for Leland Olds, which currently has an uncontrolled SO2

rate exiting the boilers of 1.82 to 1.83 lb/MMBtu (2000-2004 average)11, NDDH assumed 

an uncontrolled SO2 emission rate of 3.02 lb/MMBtu12. There is no justification for 

assuming such a high uncontrolled SO2 emission rate. Similarly, Coal Creek Units 1 and 

2 burned coal with a sulfur content of 0.61% during 2003-200413, and yet NDDH relied 

on a worst case coal sulfur content of 1.1%, close to double the 2003-2004 average coal 

sulfur content, in proposing a BART SO2 limit.14 

Milton R. Young Unit 1, which currently has no scrubber, had an uncontrolled 

SO2 emission rate exiting the boiler of 1.83 lb/MMBtu (2000-2004 average)15. Yet, for 

Milton R. Young Unit 2, which presumably burned the same coal as Milton R. Young 

Unit 1, NDDH assumed an uncontrolled SO2 emission rate of 3.48 lb/MMBtu in 

proposing BART limits for SO2.

16

 Although NDDH’s BART Determination for Unit 1 

did not include an uncontrolled SO2 emission rate, it also appears that NDDH assumed a 

higher-than-actual SO2 rate for Unit 1. NDDH assumed 95% SO2 removal would result 

in an emission reduction of 20,443 tpy.17 Yet, the 2000-2004 average SO2 emissions 

from Unit 1 were only 20,148 tpy.18 If actual average emissions were reduced by the 

projected amount, Unit 1 would be emitting negative amounts of SO2, which is an 

impossibility.

This shows that, not only did NDDH improperly rely on the worst case sulfur 

content coal in proposing BART limits, NDDH also inflated the baseline actual emissions 

for some EGUs to reflect higher sulfur content coal, and then calculated SO2 emission 

reductions based on assumed levels of SO2 removal from baseline emissions that never 

actually occurred. Thus, NDDH greatly overstated the emission reductions that would 

occur from implementation of SO2 BART controls. Presumably, this was also carried 

over into NDDH’s modeling conducted for the BART analyses as well. 

In evaluating SO2 BART for Stanton Unit 1, NDDH’s approach was slightly 

different but had the same result of artificially inflating the proposed limit. Two scenarios 

 

11 See NDDH’s BART Determination for Leland Olds at 2-3.

12 Id. at 5.

13 See NDDH’s BART Determination for Coal Creek at 9.

14 Id.

15 See NDDH’s BART Determination for Milton R. Young at 3.

16 Id. at 24.

17 Id. at 7.

18 Id. at 3.
Page 10 of 34

were evaluated for Stanton Unit 1, burning lignite and burning Powder River Basin, or 

PRB, coal. While developing a limit for burning lignite, NDDH did not rely on worst 

case coal. Instead, it used the average of the annual SO2 emission rate from 2001-2004, 

applied its assumed SO2 control factor for each control evaluated, 19 and then, for the 

proposed limit, increased the calculated controlled emission rate by 33% to arrive at a 30-

day average emission limit.20 While developing an SO2 emission limit for burning PRB 

coal, however, NDDH did arbitrarily rely on higher sulfur Powder River Basin coal than 

currently burned at Stanton Unit 1, and NDDH also applied a 33% increase.21

The purpose of BART is to reduce emissions from current levels to improve 

visibility, and that purpose will be ignored if BART limits are determined based on worst 

case sulfur content coals of the future. As we have seen with Milton R. Young Unit 1, 

the nonsensical nature of this approach is highlighted when it leads to projected emission 

reductions that are greater than actual emissions. Because NDDH is proposing BART 

limits based on 30-day averages, the averaging time can allow the EGU owners to take 

into account variability in sulfur content of coal and still comply with the limit. Further, 

retrofitted and upgraded wet scrubbers can achieve much higher levels of SO2 control 

than the 95% control assumed by NDDH, as is discussed further below. Thus, if an EGU 

owner anticipates burning a higher sulfur coal in the future, it can have its scrubber 

designed to achieve higher levels of SO2 removal to meet a SO2 BART emission limit 

that is set based on the coal currently burned at the EGU. There are also other options 

that the EGUs could use to address unusually high levels of sulfur in the coal, such as 

blending with a lower sulfur coal, rejecting high sulfur coal altogether, or coal drying, as 

has been demonstrated at the Coal Creek facility.22 Thus, there is no justification to base 

SO2 BART limits on the ultimate worst case sulfur content coal to be burned at these 

units.

2. The Proposed SO2 BART Limits Fail to Reflect the Degree of SO2 Reduction 

Achievable with the Best SO2 Controls

All but one23 of NDDH’s SO2 BART determinations requires the use of new or 

upgraded wet scrubbers, a technology capable of reducing SO2 emissions by 99% or 

more. Despite this achievable control efficiency, NDDH simply proposed EPA’s 

presumptive BART limits for SO2: either 95% control or an emission limit of 0.15 

lb/MMBtu. While wet scrubbers can routinely achieve the highest levels of SO2 control, 

NDDH’s proposed BART emission limits fail to reflect this. 

 

19 See NDDH’s BART Determination for Stanton Unit #1 at 4.

20 Id. at 8. Note that NDDH did not adequately justify applying a 33% increase to the controlled SO2 emission rate 

based on annual average uncontrolled SO2 emission rates, as we will discuss further below.

21 Id. at 17, 22.

22 To the extent that it may be capable of additional reductions of NOx and SO2 above and beyond the proposed 

technologies, coal drying should have been evaluated as part of the BART determinations as well. 

http://www.greatriverenergy.com/makingelectricity/dryfining_factsheet.pdf, Ex. 4.

23 As discussed below, a wet scrubber was not required for Stanton Unit 1.
Page 11 of 34

Wet scrubbers can achieve 99% removal efficiency. 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.24 For example, the Chiyoda’s bubbling jet 

reactor has consistently achieved >99% SO2 removal during long-term operation at the ShinkoKobe 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.25 Based on actual SO2 emissions data, the North 

Dakota BART-eligible EGUs have inlet SO2 concentrations of this level or higher. This 

technology has been guaranteed by Chiyoda to achieve 99% SO2 removal on three coal-fired 

boilers in Japan.26 It also has been demonstrated in the U.S. at the University of Illinois’s Abbott 

power plant, Georgia Power’s Plant Yates27, Dayton Power & Light’s Killen Unit 2,28 and Plant 

Bowen Unit 3.29 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.30 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, another vendor of scrubber systems, reports it has guaranteed SO2

removal efficiencies up to 99.8 percent, including for coal-fired boilers.31, 32, 33

Finally, a Lake Michigan Air Directors Consortium (―LADCO‖) and the Midwest 

Regional Planning Organization (―MRPO‖) presentation indicated that advanced FGD 

 

24

 See Black & Veatch vendor brochure on CT-121, Ex 5.

25

 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. 6.

26

 CT-121 FGD Process – Jet Bubbling Reactor, http://www.bwe.dk/fgd-ct121.html, Ex. 7.

27

 Emission-control Technologies Continue to Clear the Air, Power, May/June 2002.

28 See Black & Veatch, First Black&Veatch/Chiyoda Wet Flue Gas Desulfurization System in North America 

Successfully Goes Operational, Ex. 8.

29 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/, Ex. 9. 

30

 Chiyoda Licenses Its Flue Gas Desulfurization Technology in USA Newly for 5 Coal-Fired Generation Units, 

Press Release, May 2, 2005, Ex. 10; Chiyoda Licenses its Flue Gas Desulfurization Process in USA for Georgia 

Power Owned 4 FGD Units, January 26, 2005, Ex. 11. 

31

 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. 12.

32

 Yoshio Nakayama, Tetsu Ushiku, and Takeo Shinoda, Commercial Experience and Actual-Plant-Scale Test 

Facility of MHI Single Tower FGD, Ex. 13. 

33

 Mitsubishi High SO2 Removal Experience, Ex. 14.
Page 12 of 34

technologies could achieve 99.5% control for $1,240 to $2,875 per ton of SO2 removed. Ex. 15. 

These costs are well within the range that EPA normally considers to be cost effective in best 

available control technology (BACT) analyses.34 Further, these costs are also well within the 

range of what other states have found to be cost effective for SO2 BART determinations.35 

3. The Proposed SO2 BART Limits Should Be Expressed Multiple Ways

Many of the proposed limits are listed either as lb/mmbtu OR as percent removal 

efficiency. To ensure continuous compliance with ―the degree of reduction achievable through 

the application of the best system of continuous emission reduction‖ over the range of possible 

coal sulfur content, all the SO2 BART limits should be expressed both ways. Without a minimum 

required removal efficiency, the achievable SO2 removal efficiency will not be required at lower 

coal sulfur content. 

Further, a maximum cap on emissions should be required. EPA guidance suggests that 

emission limits be expressed both as a maximum allowable emission rate per unit time (e.g., 

lb/hr, tons/year) to reflect application of emissions controls at maximum capacity and as an 

instantaneous emission limit (e.g., lb/mmbtu). NSR Manual, pp. B.56, H.5, I.2, I.4. This is good 

practice for compliance purposes, and also serves as an actual time-based limit for modeling 

purposes. 

4. NDDH’s Proposed SO2 Emission Limits Fail to Reflect BART

Thus far, three general flaws have been noted in the NDDH SO2 BART determinations: 

use of worst case coal sulfur content; failure to reflect the actual removal efficiency of wet 

scrubbers; and failure to express limits in multiple ways. These errors and others noted below on 

a case-specific basis combine to allow for significantly higher SO2 emission rates from the EGUs 

evaluated for BART. Table 1 below highlights this impact.

 

34 $10,000/ton in 2001, equivalent to over $13,000/ton today. See expert report of Matt Haber - EPA, Best Available 

Control Technologies for the Baldwin Generating Station, Baldwin, Illinois, prepared for the United States in 

connection with United States v. Illinois Power Company and Dynegy Midwest Generation, Inc., Civil Action 99-

883-MJR, in the U.S. District Court for the Southern District of Illinois, April 2002, p. 17, Ex. 16; Memorandum of 

John S. Seitz to Air Division Directors, BACT and LAER for emissions of nitrogen oxides and volatile organic 

compounds at Tier 2/Gasoline Sulfur Refinery Projects (Jan. 19, 2001), at 3, Ex. 17. 

35 See National Park Service Spreadsheet ―EGUs with Proposed BART SO2 Controls‖ dated November 13, 2009, 

Ex. 18.
Page 13 of 34

Table 1: Proposed and Appropriate BART Limits for EGUs Evaluated By NDDH

Facility Proposed BART Appropriate BART

Leland Olds Units 1 and 2 95% removal OR 

0.15 lb/MMBtu

95 – 99% removal AND 

0.03 – 0.091 lb/MMBtu

Milton R. Young Unit 1 95% removal 95 – 99% removal AND 

0.035 – 0.094 lb/MMBtu

Milton R. Young Unit 2 95% removal OR 

0.15 lb/MMBtu

95 – 99% removal AND 

0.035 – 0.094 lb/MMBtu

Coal Creek Units 1 and 2 95% removal OR 

0.15 lb/MMBtu

95 – 99% removal AND 

0.03 – 0.087 lb/MMBtu

Stanton Unit 1 90% removal OR

0.24 lb/MMBtu

95 – 99% removal AND 

0.02 – 0.085 lb/MMBtu

a. Leland Olds

For Leland Olds, NDDH proposed SO2 BART limits for each unit of either 95% removal 

of the inlet SO2 concentration to the scrubber or 0.15 lb/MMBtu on a 30-day average basis based 

on use of wet scrubbers. The proposed emission limitation of 0.15 lb/MMBtu only reflects 

91.8% SO2 removal at each unit based on the annual average of uncontrolled SO2 emissions at 

each unit. Such an SO2 removal efficiency falls far short of what is achievable with a wet 

scrubber at the Leland Olds units. A removal efficiency of 95% control reflects the minimum 

level of SO2 removal that is achievable with a wet scrubber. Thus, at the minimum, the BART 

emission limit should be based on 95% removal from the annual average of the uncontrolled SO2

emissions at each unit - or a limit of 0.091 lb/MMBtu. Because the proposed 95% removal is an 

alternate and not concurrent limit, the fact that NDDH has also proposed an alternative limit of 

95% SO2 removal will not ensure 95% removal is required until the uncontrolled SO2 emissions 

increase significantly, to about 2.8 lb/MMBtu. Thus, it is imperative that the lb/MMBtu limit 

reflect no less than 95% control off of current coal in order for the BART limit to reflect at least 

the minimum level of SO2 control efficiency of a wet scrubber.

Indeed, based on the discussion above regarding the SO2 removal capabilities of a wet 

scrubber, a more appropriate BART limit would reflect 98-99% SO2 removal. Even assuming 

the worst case uncontrolled SO2 emissions identified by NDDH of 3.20 lb/MMBtu, 98% removal 

would reflect an emission limit of 0.064 lb/MMBtu. This SO2 emission limit based on worst 

case coal and an achievable level of SO2 removal would reflect 96.5% SO2 removal from current 

coal – a control efficiency that is clearly achievable with a wet scrubber. Ninety-nine percent 

removal off of worst case coal at Leland Olds would equate to a SO2 emission limit of 0.03 

lb/MMBtu. With current coal, this would reflect 98.4% removal. This emission level and SO2

removal efficiency has been shown to be achievable and has been achieved in practice. 

The attached National Park Service spreadsheet of best available control technology 

(BACT) determinations for coal-fired power plants shows that BACT limits as high as the 0.15 

lb/MMBtu SO2 BART limits proposed for the Leland Olds units are unheard of. Ex. 19. The 

proposed permit for the Plant Washington facility requires as part of the facility’s BACT limits a 

97.5% SO2 removal efficiency requirement that would apply on a 30-day rolling average 
Page 14 of 34

regardless of the type of coal burned.36 This facility may burn Powder River Basin coal or 

Central Appalachian coal or a combination of the two. The Desert Rock facility, which will burn 

low sulfur western coal, is subject to an SO2 BACT limit of 0.060 lb/MMBtu on a 24-hour basis 

(Ex. 21), and the proposed Toquop (Ex. 22) and Ely Energy Center 37(Ex. 23) permits, both of 

which would burn Powder River Basin coal, also included BACT limits of 0.06 lb/MMBtu for 

SO2. As Ex. 25 shows, there are numerous coal-fired units that are achieving SO2 emission rates 

much lower than the 0.15 lb/MMBtu SO2 BART limit proposed for the Leland Olds Units. The 

lowest SO2 emission rates being achieved are at the Pleasant Prairie units which are emitting SO2

at 0.021 to 0.027 lb/MMBtu with wet scrubbers.

Thus, for all of the reasons discussed above as supported by the attached documentation, 

BART emission limits of no higher than 0.091 lb/MMBtu and as low as 0.03 lb/MMBtu should 

have been evaluated as BART for the Leland Olds Units. Such limits should be readily met on a 

30-day average basis, especially because higher SO2 removal efficiencies than represented by 

this range of more appropriate BART limits could be met with a wet scrubber. There is no 

justification for increasing the emission rate determined from annual average coal characteristics 

to arrive at a higher 30-day average emission limit as NDDH has proposed. Thirty day average 

emission limits are long term average emission limits, and peaks in emissions can be smoothed 

out with increased SO2 removal efficiencies and/or use of lower sulfur content coal. In addition 

to imposing a numerical emission limit, NDDH should also set a minimum control efficiency 

requirement not as an alternative limit but as a second BART limit, to ensure the achievable SO2

removal efficiency is required regardless of the type of coal burned. 

Thus, the proposed 0.15 lb/MMBtu SO2 BART limits fall far short of reflecting the best 

system of continuous emission reduction at the Leland Olds units. In fact, a much more 

appropriate SO2 BART limit would be in the range of 0.03 to 0.091 lb/MMBtu, 30-day average, 

along with an SO2 removal efficiency requirement of no less than 95% control.

b. Milton R. Young

For Milton R. Young Unit 1, NDDH has proposed use of a wet scrubber and an SO2

BART limit of a 95% removal efficiency from the inlet SO2 concentration to the scrubber, to be 

achieved on a rolling 30-day average basis. For the reasons previously discussed and the 

documentation attached, 95% control does not reflect best system of continuous emission 

reduction of SO2 emissions from Milton R. Young Unit 1. Instead, an SO2 removal efficiency of 

98 to 99% should be achievable with a wet scrubber and the coal to be burned at Milton R. 

Young Unit 1. 

Along with an SO2 removal requirement, NDDH should also impose an emissions limit. 

Otherwise, it is difficult for NDDH to project emissions from Milton R. Young Unit 1 for use in 

air modeling analyses such as PSD increment analyses or for the visibility modeling done for this 

regional haze SIP and subsequent SIP submissions. Based on the same reasoning provided 

 

36 Proposed Plant Washington PSD Permit (Ex. 20) at Condition 2.14.

37 NV Energy no longer plans to build the Ely Energy Center, and officially withdrew its application to the state 

Public Utilities Commission in June 2009. See http://www.lvrj.com/news/breaking_news/48923992.html, Ex. 24.
Page 15 of 34

above, the numerical SO2 BART limit should be based on no less than 95% removal from the 

current uncontrolled emission rate of 1.88 lb/MMBtu - 0.094 lb/MMBtu. However, as discussed 

above, higher SO2 removal efficiencies are achievable. Even using NDDH’s worst case 

uncontrolled SO2 emission rate for Milton R. Young Unit 1 of 3.48 lb/MMBtu, 98% SO2

removal would reflect an emissions limit of 0.070 lb/MMBtu. Ninety-nine percent removal 

would result in an emissions limit of 0.035 lb/MMBtu. As shown in the attachments to this 

letter, such emission rates have been required as BACT and/or have been met in practice.

Thus, the proposed 95% SO2 removal efficiency requirement for Milton R. Young Unit 1 

falls far short of reflecting the best system of continuous emission reduction at the unit. A much 

more appropriate SO2 BART limit would be in the range of 0.035 to 0.094 lb/MMBtu, 30-day 

average, along with a 95% or higher SO2 removal efficiency requirement.

Milton R. Young Unit 2 is already equipped with a wet scrubber which, according to 

NDDH, achieves approximately 65% SO2 control. NDDH has proposed requiring upgrades to 

the scrubber to achieve 95% control or meet an SO2 emission limit of 0.15 lb/MMBtu, 30-day 

average, as BART for Milton R. Young Unit 2. NDDH found the costs to upgrade the scrubber 

to 95% control to be quite reasonable. Given the low costs for upgrading the scrubber to achieve 

95% removal, it should also be cost effective to require the scrubber to be upgraded to achieve 

the level of SO2 control that is achievable with a wet scrubber – up to 98-99% SO2 removal.

Along with an SO2 removal requirement, NDDH should also impose an emissions limit 

as BART for Unit 2. Because the same coal is burned and the same control efficiencies can be 

expected, the same analysis applies to Unit 2 as that described for Unit 1 above. 

Thus, the 95% removal efficiency requirement that would apply to Unit 2 does not satisfy 

BART. An SO2 emission limit in the range of 0.035 – 0.094 lb/MMBtu along with a high SO2

removal efficiency requirement should instead be required as BART for Unit 2.

Such limits should be readily met on a 30-day average basis, especially because higher 

SO2 removal efficiencies than represented by this range of more appropriate BART limits could 

be met with a wet scrubber. There is no justification for increasing the emission rate determined 

from annual average coal characteristics to arrive at a higher 30-day average emission limit as 

NDDH has proposed. Thirty day average emission limits are long term average emission limits, 

and peaks in emissions can be smoothed out with increased SO2 removal efficiencies and/or use 

of lower sulfur content coal. 

c. Coal Creek

For Coal Creek Units 1 and 2, NDDH proposed SO2 BART limits for each unit of either 

95% removal of the inlet SO2 concentration to the scrubber or 0.15 lb/MMBtu on a 30-day 

average basis based on use of wet scrubbers. Assuming each unit achieved 68% SO2 removal 

efficiencies as claimed by NDDH, then the uncontrolled SO2 emissions at the inlet to the 

scrubber averaged over 2000-2005 ranged from 1.59 to 1.71 lb/MMBtu. The 0.15 lb/MMBtu 

emission limit only reflects 90.6% to 91.4% SO2 removal based on the annual average of 

uncontrolled SO2 emissions at each unit. Such SO2 removal efficiencies fall far short of what is 

achievable with a wet scrubber at the Coal Creek units. A removal efficiency of 95% control 
Page 16 of 34

reflects the minimum level of SO2 removal that is achievable with a wet scrubber. Thus, at the 

minimum, the BART emission limit should be based on 95% removal from the annual average of 

the uncontrolled SO2 emissions at each unit - or a limit of 0.080 to 0.087 lb/MMBtu. Because 

the proposed 95% removal is an alternate and not concurrent limit, the fact that NDDH has also 

proposed an alternative limit of 95% SO2 removal will not ensure 95% removal is required until 

the uncontrolled SO2 emissions increase significantly, to about 2.8 lb/MMBtu. Thus, it is 

imperative that the lb/MMBtu limit reflect no less 95% control off of current coal. 

Indeed, based on the discussion above regarding the SO2 removal capabilities of a wet 

scrubber, a more appropriate BART limit would reflect 98-99% SO2 removal. Even assuming 

the worst case uncontrolled SO2 emissions identified by NDDH of 2.92 lb/MMBtu38, 98% 

removal would reflect an emission limit of 0.058 lb/MMBtu. And this SO2 emission limit based 

on worst case coal and an achievable level of SO2 removal would reflect at most 96.6% SO2

removal from current coal – a control efficiency that is clearly achievable with a wet scrubber. 

Ninety-nine percent removal off of worst case coal at Coal Creek would equate to a SO2

emission limit of 0.03 lb/MMBtu. With current coal, this would reflect 98.2% removal. These 

emission rates and control efficiencies are achievable as evidenced by the previously referenced 

and attached documentation.

Thus, for all of the reasons discussed above as supported by the attached exhibits, SO2

emission limits of no higher than 0.087 lb/MMBtu and as low as 0.03 lb/MMBtu should have 

been evaluated as BART for the Coal Creek Units. Such limits should be readily met on a 30-

day average basis, especially because higher SO2 removal efficiencies than represented by this 

range of more appropriate BART limits could be met with a wet scrubber. There is no 

justification for increasing the emission rate determined from annual average coal characteristics 

to arrive at a higher 30-day average emission limit as NDDH has proposed. Thirty day average 

emission limits are long term average emission limits, and peaks in emissions can be smoothed 

out with increased SO2 removal efficiencies and/or use of lower sulfur content coal. In addition 

to imposing a numerical emission limit, NDDH should also impose a minimum control 

efficiency requirement not as an alternative limit but as a second BART limit, to ensure the 

achievable SO2 removal efficiency is required regardless of the type of coal burned. Therefore, a 

SO2 control efficiency requirement should also be imposed as BART, no less than 95% control.

d. Stanton Unit 1

For Stanton Unit 1, NDDH proposed as BART for SO2 the use of a spray dryer with a 

fabric filter and an SO2 emission limit of 0.24 lb/MMBtu or an SO2 removal efficiency of 90%, 

both on a 30-day rolling average basis. This emission limit was derived assuming 90% removal 

from the highest calendar year average SO2 emissions of 1.81 lb/MMBtu, increased by 33% to 

adjust from an annual average to a 30-day average. NDDH has provided absolutely no 

justification for this 33% increase. Given that the limit is based on the worst year of 

uncontrolled SO2 emissions, that the assumed control efficiency of the spray dryer is much lower 

than what can actually be achieved in practice with a spray dryer, and that Stanton Unit 1 also 

 

38 This was calculated from the table of future case emissions rates and the expected control efficiencies of the 

various options evaluated, Coal Creek BART Determination at 10.
Page 17 of 34

burns Powder River Basin (PRB) coal which has much lower uncontrolled SO2 emissions, there 

is no valid justification for NDDH to increase the derived emission rate reflective of 90% control 

by 33%.

Spray dryers can achieve greater than 90% SO2 removal. There have been several 

proposed low sulfur PRB coal-fired power plants that have proposed to use dry scrubbers to meet 

PSD requirements and that are subject to much lower SO2 BACT limits than 0.23 lb/MMBtu. 

Those facilities include the Newmont Nevada TS power plant, the proposed White Pine power 

plant39, Toquop, 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%.40 This facility is currently operating in 

compliance with its limits. The Newmont Nevada plant 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.41 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.42 Other examples of low SO2 emission limits and high SO2 removal rates being 

required as BACT can be found in the National Park Service’s spreadsheet of BACT 

determinations for coal-fired electrical generating units, Ex. 19. 

Regardless of whether NDDH underestimated the effectiveness of a spray dryer, a wet 

scrubber can remove an even greater amount of SO2 than a spray dryer. Although NDDH did 

not find the costs of a wet scrubber at Stanton Unit 1 to be excessive, NDDH discounted the use 

of a wet scrubber because it determined the increased amount of SO2 removed would not provide 

that much of a visibility improvement. The cost effectiveness of the wet scrubber at 95% 

removal for Stanton Unit 1 was actually quite reasonable at $1,480 per ton of SO2 removed. 

Stanton BART Determination at 5. As shown in the National Park Service spreadsheet of BART 

determinations (Ex. 18), there are several instances where wet scrubbers were required to meet 

SO2 BART requirements with similar or even higher costs on a $/ton of SO2 removed basis, 

specifically Clay Boswell Unit 3 ($1,640/ton) and Naughton Units 1 ($1,707/ton) and 2 

($1,700/ton). There are also several instances of dry scrubbers being required as BART for SO2

with even higher cost effectiveness values than $1,480 per ton, including Boardman 

($3,053/ton), Martin Drake Units #6 ($2,765/ton) and #7 ($2,276/ton), Dave Johnston Units #3 

($1,848/ton) and #4 ($4,743/ton), and Silver Bay ($7,309/ton), among others. Thus, the cost of a 

wet scrubber at Stanton Unit 1 is cost effective and is well within the range of the costs required 

at other similar EGUs to meet BART for SO2. Given that North Dakota is far from meeting 

reasonable progress goals in remedying existing visibility impairment, NDDH must require as 

BART the most effective SO2 control – especially when it is as cost effective as a wet scrubber 

would be at Stanton Unit 1.

 

39 In March 2009, LS Power ―indefinitely postpone[d]‖ plans to build the White Pine power plant. 

http://www.lasvegassun.com/news/2009/mar/05/second-coal-fired-plant-canceled-nevada/, Ex. 26.

40

 See Section V.A.2.a.8. of Newmont Nevada Permit, Ex. 27.

41

 See Section V.A.2..a.(8) of draft Toquop permit, Ex. 22.

42

 See Dry Fork PSD Permit, Ex. 28.
Page 18 of 34

In addition, as discussed above and in the attached exhibits, wet scrubbers can achieve 

higher than NDDH’s assumption of 95% removal, as high as 98-99% SO2 removal. If a proper 

SO2 removal efficiency was taken into account, the cost effectiveness of a wet scrubber at

Stanton Unit 1 would be even lower and the benefit to visibility in the affected Class I areas 

would be even greater.

Because the cost of a wet scrubber at Stanton Unit 1 is cost effective and because a wet 

scrubber will reduce SO2 emissions to a much greater extent than a dry scrubber, NDDH must 

require the use of a wet scrubber as BART for SO2 at Stanton Unit 1.

Along the same lines as our previous comments, the SO2 BART limit with a wet scrubber 

should be no less than 95% removal off of current coal, or an emission limit of 0.085 lb/MMBtu. 

As previously stated and shown by the attached exhibits, 98-99% SO2 removal should be 

achievable with a wet scrubber, which would equate to emission limits of 0.034 lb/MMBtu to 

0.02 lb/MMBtu. These emission rates and control efficiencies are achievable as evidenced by 

the previously referenced and attached documentation.

Thus, for all of the reasons discussed above, a wet scrubber should have been required as 

BART for Stanton Unit 1. SO2 emission limits of no higher than 0.085 lb/MMBtu and as low as 

0.02 lb/MMBtu should have been evaluated as BART for the Stanton Unit 1. Such limits should 

be readily met on a 30-day average basis, especially because higher SO2 removal efficiencies 

than represented by this range of more appropriate BART limits could be met with a wet 

scrubber. Thirty day average emission limits are long term average emission limits, and peaks in 

emissions can be smoothed out with increased SO2 removal efficiencies and/or with the use of 

lower sulfur content coal. In addition to imposing a numerical emission limit, NDDH should 

also set a minimum control efficiency requirement not as an alternative limit but as a second 

BART limit, to ensure the achievable SO2 removal efficiency is required regardless of the type of 

coal burned. This is especially important for Stanton Unit 1 which may burn two different types 

of coal with different uncontrolled SO2 emission rates. The minimum control efficiency 

requirement should be no less than 95% control for a wet scrubber.

5. There Are Other Benefits to NDDH Requiring Stringent SO2 BART Limits that 

NDDH Must Take Into Account

Along with providing for improved visibility, there are also other environmental benefits 

to higher SO2 removal requirements. Specifically, 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.43 It will be more cost effective and operationally 

simpler to design and install controls in one retrofit program.

 

43

 Chuck Dene, Lesley A. Baker, and Robert J. Keeth, FGD Performance Capability, Mega 2008, Ex. 29.
Page 19 of 34

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 EGUs. Thus, if a more effective SO2

control technology and more stringent control requirements will better prepare North Dakota’s 

EGUs to be able to effectively remove CO2 in the future, that must be taken into account in the 

BART analysis as another environmental benefit of a lower SO2 emission limit. Indeed, as 

described above, there are wet scrubber technologies available that can remove 99+% of the SO2. 

Further, lower emissions of SO2 that are achievable with wet scrubbers also equate to 

lower PM2.5 concentrations since there will be less SO2 in the air to contribute to sulfate 

formation. Studies have demonstrated that sulfate addition to sulfate-limited water bodies or 

wetlands can increase the transformation of mercury to its neurotoxic form, methylmercury.44 

Thus, with lower SO2 emissions from North Dakota’s EGUs, the result should be less sulfate 

deposition which should decrease methylization of mercury.

All of the above must be taken into account by NDDH in proposing SO2 BART limits for 

the State’s BART-eligible EGUs. NDDH must require the best designed and most effective SO2

controls on its BART-eligible EGUs – i.e., wet scrubbers designed to achieve 98-99% SO2

removal – to meet the regional haze requirements of the Clean Air Act for the State’s Class I 

areas.

B. NOx BART Comments

The following comments are provided with respect to the proposed NOx BART levels in 

the draft RH SIP proposed by NDDH. At the outset, it must be noted that technical issues 

pertaining to NOx BART for the various coal-fired electric utility units, which are the major NOx

sources affecting visibility and regional haze in Class I areas in North Dakota and neighboring 

states, have been under discussion, in one form or another going back to roughly 2006. As such, 

it is impossible to provide meaningful comments on all aspects of NOx BART in the allowed 30-

day time period for public comment. This is particularly so given that the public comment 

period (ending January 8, 2010) coincided with major holidays and year end vacation periods, 

minimizing the ability to fully flesh out important aspects of the proposed BART. As such, the 

focus of the comments is on the following most important issues:

(a) The erroneous determination that high dust Selective Catalytic Reduction (HDSCR) is 

technically infeasible at each and any of the coal-fired electric utility units under 

consideration;

(b) The erroneous determination that tail end or low dust SCR (TESCR or LDSCR) are 

rejected based on cost ineffectiveness considerations at each and any of the coal-fired 

utility units under consideration. 

 

44

 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. 30); See also 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, Ex. 31. 
Page 20 of 34

The net result of rejection of SCR of any design at the coal fired units is that otherwise 

large NOx reductions from these major sources, which could have accrued, and benefitted air 

quality in North Dakota and neighboring states, will not occur. That this outcome is based on 

erroneous regulatory and technical reasoning is untenable. 

It should be noted that, due to the lack of time, the following issues could not be 

extensively commented upon. However, they are noted in summary or brief form below. We 

reserve the right to provide additional comments on these and related topics at a later date:

(a) The process by which North Dakota selected the NOx sources to be analyzed as part of 

the SIP.

(b) The process by which certain emission units were selected at sources and source 

categories which were found to significantly impact visibility, either as part of being 

BART-eligible sources or under the Reasonable Progress provisions of the applicable 

regulations.

(c) The lack of technical basis for the assumed control efficiencies in most of the NOx

control options. For example, in the case of SCR, efficiencies of 80% or 90% or 93% are 

variously assumed, without basis or consistency.

(d) The lack of any support whatsoever for the level of cost-effectiveness which appears to 

be the basis for rejection of technologies (such as TESCR and LDSCR) on costineffectiveness grounds. Nothing in the EPA guidelines for BART determinations 

established a bright-line cap on the cost-effectiveness expressed on $/ton reduced 

grounds. References to EPA’s presumptive limits ($1,300/ton reduced) as a cap in this 

regard is fatally flawed. Numerous BART determinations in other states RH SIPs have 

accepted NOx controls at levels higher than this level.45

(e) The improper use of incremental cost-effectiveness, as a tool to reject technologies (such 

as TESCR and HDSCR) which are otherwise cost-effective, even under the flawed and 

worst-case analyses presented by the utilities (and accepted by the State). EPA has noted 

the error in relying on this metric in its comments. However, such direct and express 

criticism seems to have had no effect in ND’s analysis and proposal.

(f) The lack of discussion and analysis of cost-effectiveness expressed in terms of $/dv 

improved. This metric, clearly relevant in this regard, will allow comparisons of costeffectiveness for North Dakota sources with those from other sources in other states 

subject to RH NOx reductions. 

(g) The lack of explicit discussion of how each of the 5 statutory factors was used or weighed 

in the BART determinations.

(h) The lack of support for how details such as the BART limits themselves were arrived at 

in terms of their averaging time. In other words, why shorter averaging times (such as 7-

day or 24-hour averages) were not considered – especially given that visibility impacts 

can occur on short durations.

(i) The exception accorded to startup and shutdown periods, even though 30-day averaging 

time periods are used for the recommended BART limits. This is without technical and 

regulatory basis.

 

45 See National Park Service Spreadsheet ―EGUs with Proposed BART NOx Controls‖ dated November 13, 2009, 

Ex. 32.
Page 21 of 34

Finally, it should be noted that there was insufficient time to properly critique NOx

BART for the other NOx sources (other than the utility boilers).

1. High Dust SCR (HDSCR) is Technically Feasible

As noted earlier, the applicability of SCR as NOx control – universally agreed to by all 

parties as being the technology with the highest degree of NOx reduction potential (upwards of 

90%, after consideration of in-boiler NOx controls such as low NOx burners or over-fire air etc.) 

– has been the subject of technical discussion in North Dakota since at least 2006. Not only were 

such discussions central to the consent decree implementation at the Milton R. Young units, but 

they were also part of the initial BART submittals of the various affected companies.

It appears that after opposing any type of SCR (high dust, tail end or low dust) for years 

on technical infeasiblity grounds, the State of North Dakota finally revised its position recently 

that tailend and low dust SCR were technically feasible after all. While this is a positive shift, 

we believe that the State has not provided a technical or regulatory basis for continuing to reject 

the even most promising (and likely more cost-effective) option that HDSCR is also technically 

feasible.

Since the State’s position regarding HDSCR is the same in the case of any of the BART 

analyses (see Appendix B.5), comments on this aspect are provided in general, without particular 

reference to specific units. It should be noted that the State’s position is an amalgam of all of 

the arguments that have been pushed consistently by the affected units, their owners, their 

technical consultants (Burns and MacDonnell, Sargent and Lundy, and others) with regards to 

SCR for the last many years. 

The central issue seems to be the use (or lack of use) of technical judgment on the part of 

the State. An important secondary issue seems to be the State’s rejection of technical arguments 

and support from a most important source – namely the vendors of SCR catalysts themselves.

The State’s technical infeasibility rejection of HDSCR boils down to a circular argument. 

Basically, the State has taken the following position:

(a) that each of the boilers at issue burns some form of North Dakota lignite coal (either 

exclusively or in combination with other fuels such as Powder River Basin (PRB) subbituminous coal);

(b) that North Dakota lignite is both unique and highly variable in its properties – such as 

heating value, ash content, sodium content, sulfur content, moisture content, etc. In fact, 

in the State’s view, it is so unique that there are no other similar or comparable aspects to 

any other lignites or brown coals anywhere in the world nor any other fuels such as 

biomass or wood;

(c) that HDSCR has not been applied at any North Dakota lignite fired units (which are only 

used in North Dakota utility units) to date (with the one, flawed exception at Coyote back 

many years ago, which will be discussed shortly);
Page 22 of 34

(d) that since HDSCR has not been applied at any North Dakota lignite fired units 

successfully and for many years, there is no basis to conclude that it can be used 

successfully.

The circular argument is obvious. NDDH basically wants proof that HDSCR will work 

successfully before allowing HDSCR to be implemented – yet it demands that this proof be 

obtained from the very universe of sources (and only those) which are the subject of its analysis. 

This is akin to saying that a control technology will not work at a particular facility because it 

has not been tried there yet. 

It is not unusual for ―new‖ technologies to be faced with such first-time applicability 

challenges in a particular source category. Of course, HDSCR is not ―new‖ in any traditional 

sense - it has been demonstrated successfully in other, closely related source types. In fact, 

implementation of BART46 relies on the fact that emissions reductions will often accrue from 

first-time application of ―new‖ technologies to various source categories. Otherwise the inherent 

―technology-forcing‖ aspect of BACT and BART would not be realized. 

There is no debate that HDSCR has been successfully to all boiler types in other coalfired applications including bituminous coals, sub-bituminous coals, other lignites, brown coals, 

biomass, and combinations of these fuels. There is also no debate that HDSCR has been 

successfully applied to all of the boiler technologies at issue here – namely cyclone, tangential 

fired and wall fired boilers.

Thus, the only issue is whether, in light of its widespread and continued successful use in 

closely related sources types such as other coal-fired applications, HDSCR can be successfully 

―transferred‖ to North Dakota lignite fired units that are either cyclone or tangential fired or wall 

fired (which is the universe at issue at the present time)? We believe that the overwhelming 

evidence in the record suggests that the answer to this question is Yes.

Typically, first-time applicability is the result of careful and proper technical 

consideration by the regulatory agency of the following:

(a) reliance on technology-transfer from other similar sources, broadly construed;

(b) proper reliance on pilot tests, if such tests were properly designed and conducted;

(c) reliance on key technology suppliers such as vendors, who bear the risk of failure –

commercially, and reputationally; and 

(d) fundamental assessment of the likely risk factors that may make the technology a failure.

Of course there will be risks inherent in the first-time application of any technology (new 

or old) to a new source category. We do not believe that demanding zero-risk as a pre-requisite 

is proper. Yet, we believe that this is exactly what North Dakota seems to want in its circular 

argument discussed above.

 

46 We note that implementation of BART can and should necessarily encompass a review of relevant BACT 

analysis. 
Page 23 of 34

We believe that North Dakota has improperly disregarded key aspects of the above 

considerations, in particular the rejection of explicit assurances from at least two experienced and 

reputable SCR catalyst vendors, as far back at 2007/2008, that HDSCR could be installed at the 

units at issue. Substituting its own judgment in place of such vendors was improper. Relying 

only on industry-funded researchers, engineering companies and consultants (who are not 

technology providers) is also improper.

Basically, for the last 4 years, and in spite of much evidence to the contrary, North 

Dakota has chosen to disregard the plain fact that HDSCR can be successfully applied to each 

and every unit at issue. Of course, such application will require case-by-case design and 

analysis. Of course, such application will inherently involve some technical risk. To the extent 

that such risks can be mitigated by coupon tests, or pilot tests, these should be conducted either 

at the units or at vendor locations. That each utility was vehemently opposed to any such tests, 

relying on false regulatory arguments that these somehow violate how BART is determined, 

underscores the outcome-determinative nature of the present proposed analysis. The fact is that 

BART allows for technology transfer. We know of no successful technology transfer that is not 

preceded by prudent engineering judgment, supported by appropriate testing. Thus, excluding 

the possibility of any such type of testing equates to reading-out technology transfer from the 

definition of BART – which directly contradicts EPA guidance and Congressional intent.

Below, we provide some comments on key technical concerns raised by the State in 

attempting to support its position that HDSCR is not technically feasible. 

a. Variability of Fuel Composition

The State notes that North Dakota lignites (or lignite from a particular mine, such as the 

Center Mine, the source of the Milton R. Young units) are highly variable in heat and ash content 

and in the constituents that make ash, and that such variability will affect SCR design and 

operation. While this may be true, it is true of all coals, worldwide. We know of no coal-fired 

boiler designer/operator or SCR designer/operator who does not face fuel variability. However, 

such variability is no reason to conclude that HDSCR will be precluded from successful 

application. In fact, designers routinely factor in such variability such that equipment can 

operate over a wide range of variability. Thus, it is a matter of proper design, anticipating such 

variability, which is required by a case-by-case analysis. Frankly, pointing to such variability as 

a reason for technical infeasibility of HDSCR shows the weakness of the State’s argument.

b. Results of the Coyote Pilot Testing

The State correctly states that "the only pilot testing that has ever been conducted on a 

unit firing North Dakota lignite was at the Coyote stations. The pilot scale SCR was plugged 

after 2 months and little useful data was obtained." In fact, the failure of the Coyote stations test 

is noted as a central point in the State’s determination that HDSCR cannot be successful. Yet, in 

key respects, the State intentionally or otherwise misrepresents these tests and their conclusions. 

This is puzzling because the State correctly notes that "the pilot testing....in hind-sight, was illdesigned for a unit combusting North Dakota lignite..." In fact, it is undisputed that this test was 

poorly designed and executed for the following reasons:
Page 24 of 34

(a) The catalyst used at the Coyote station test was previously used at the Baldwin station. 

While it was supposedly cleaned between tests, the nature of such cleaning and its 

effectiveness are unknown. It is more than likely that the catalyst was impaired before 

tests even began at Coyote station. At any rate, it is undisputed that it was not new or 

fresh catalyst;

(b) The catalyst design was improper with regard to pitch, measure of cell spacing that 

influences gas flow and ash deposit. That resulted in rapid plugging in a short amount of 

time. As a result, no deactivation data were obtained. There is no support whatsoever 

that this type of catalyst or the same pitch would be proper or be used in any of the 

HDSCRs at issue. Improperly disregarding the specific aspects of why these tests failed 

but continuing to make general statements, is the very definition of poor judgment.

Just on this basis alone, the Coyote station ―tests‖ and any conclusions therefrom should 

be rejected. It is a simple data validation issue. In particular, any conclusions relating to catalyst 

blinding or plugging etc., which depend on catalyst geometry, from these flawed tests, should 

definitely be rejected. Knowing these flaws and purposely choosing to ignore them while relying 

on these tests points to poor technical judgment on the part of the State.

In fact, as the State well knows, the prior Baldwin tests also concluded that HDSCR 

would not work for those cyclone boilers. Yet, after proper evaluation, the Baldwin station 

proceeded to install HDSCR and such units have been operating successfully, now for many 

years. This provides further support for rejection of the Coyote tests.

Finally, several of the SCR and catalyst vendors (Alstom, Babcock Power, CERAM, 

Halder-Topsoe), who were aware of the Coyote tests, were still willing to provided proper 

guarantees for HDSCR. The State chose to disregard this.

To the extent that the State is worried about popcorn ash plugging, these issues have been 

widely and successfully addressed in numerous other HDSCR installations using simple 

technologies such as ash removal systems (e.g. mechanical screens). 

c. Sodium

The State notes that the combustion of North Dakota lignite produces or can produce 

soluble sodium compounds, which cause more severe catalyst deactivation than insoluble sodium 

compounds. However, the State fails to show how, under the actual operating temperatures in a 

HDSCR location, such compounds can penetrate or deposit on the catalyst and if they did so, 

why they could not be addressed by mitigation measures such as washing (since they are 

soluble). At least one of the catalyst vendor has noted that "sodium is not a poison to catalyst at 

SCR operating temperatures..." The critical issue is not whether, as a general matter, sodium can 

cause deactivation, but whether, under actual operating conditions, it would do so. Without 

factoring in the operating temperatures, such a statement or concern is meaningless. Since, at the 

expected operating temperatures, such sodium compounds will generally not condense, this 

mechanism is speculative and unlikely. At under conditions where such condensation is an issue 
Page 25 of 34

(such as during shutdown), proper design such as by-pass, can be used. Finally, even if some 

condensation occurred, it can be mitigated using water washing.

 

d. Temperature Variations

In some units (such as the Milton Young cyclone unit), the State is concerned that the 

temperature variation of the flue gas entering a HDSCR will adversely affect its performance. 

We note that this, again, is a matter of proper design and evaluation. Why there are such large 

temperature variations and what is causing them are legitimate design issues that need to be 

resolved on a case-by-case basis. Perhaps additional boiler changes in the backpass, air 

preheater, or economizer may be needed. But the need for such changes does not eliminate 

HDSCR. No regulation or guidance contemplates that application of air pollution control 

technology would be so seamless as to preclude any other changes to the emissions source. To 

provide this argument in support for technical infeasibility for HDSCR has no merit. 

e. Catalyst Erosion

The State is concerned that HDSCR catalysts can erode and that there are ―unresolved 

issues regarding catalyst erosion....‖ Notwithstanding that all SCR catalysts erode to some extent 

and that this is accounted for as part of the design of any SCR, the State’s position is not 

substantiated by any data. SCRs have been exposed to bituminous coal combustion ash as high 

as 40%. Ash contents in coal comparable to that of North Dakota lignite have used SCR for 

many years.

f. Lack of Vendor Guarantees

The Department states that "vendors cannot without further pilot testing, guarantee SCR 

system performance for M.R. Young Station boilers firing North Dakota lignite." This statement 

is simply incorrect as both CERAM and Haldor Topsoe clearly stated, way back in 2007 and 

2008, that they would be willing to offer industry standard guarantees for an HDSCR system 

installed at the Milton R. Young Station, which includes a cyclone boiler. The guarantees that 

were offered were consistent with those that are typical in the utility industry (i.e., up to contract 

value), in spite of claims to the contrary by the State and consultants to the utility companies. 

Making an issue of guarantees in the face of explicit guarantees already being offered by the 

actual catalyst suppliers underscores the nature and weakness of the State’s argument against 

HDSCR.

In summary, we believe that it is grossly erroneous to conclude the HDSCRs are 

technically infeasible for any of the utility boilers that are at issue in the RH SIP. For this reason 

alone, the draft SIP and all of the NOx limits proposed as BART are flawed and the analysis 

needs to be redone. In redoing the analysis, the following approach should be followed:

(a) Request engineering quotes for HDSCR systems from experienced SCR and catalyst 

vendors, capturing up-to-date developments in catalyst design and mitigation strategies 

for the potential problems that may arise in installation. Determine a range of HDSCR 

control effectiveness values and associated costs, as appropriate for each unit;
Page 26 of 34

(b) Do the above in a public process so that the problematic and procedural issues inherent in 

the prior process (in which vendors were essentially brow-beaten by industry consultants) 

when vendors were contacted, are avoided. Involve U.S. EPA, the National Park Service, 

and other relevant regulatory agencies in this process;

(c) Lay out clear guidelines for the cost-effectiveness criteria that will be used in a 

comparison of cost effectiveness of HDSCR. At a minimum, this should include the 

absolute cost effectiveness expressed as $/ton NOx reduced and $/deciview of visibility 

improvement (considering all of the unit’s impacts at all affected Class I areas). 

Secondarily, this can include considerations of incremental cost-effectiveness. However, 

incremental cost-effectiveness is a secondary and not a primary criterion. These 

guidelines should be clearly stated independently of the HDSCR analysis and should be 

supported. Some comments on this aspect are provided later.

(d) Conclude whether HDSCR is cost-effective at each unit and therefore whether it is 

BART or not. 

2. TESCR and LDSCR Are Cost Effective.

As noted above, in rejecting HDSCR, we believe that the State has fatally compromised 

its NOx BART analysis and, therefore, the analysis should be redone.

Separately from that, although the State did require that TESCR and LDSCR be 

considered since they are technically feasible (after incorrectly arguing that they are not for 

years), these technologies were rejected on cost-effectiveness grounds. We believe that this 

rejection was in error for the following reasons:

(a) A lack of transparency of how the costs were developed. In no case were detailed costestimates provided in the record, along with the associated design of the SCRs. Rather, 

gross values of SCR in $/kW terms were assumed along with numerous other 

assumptions, stated and unstated. Without this information, there is insufficient data for 

analysis of cost effectiveness by the public or any agency. The SIP should be considered 

incomplete without this information. Thus, the cost figures arrived at (and the associated 

control efficiencies) are unreliable and are assumed to be higher than actual.

(b) An incorrect reliance on incremental cost-effectiveness as the metric for cost 

effectiveness;

(c) A lack of stated and defensible cost-effectiveness metrics by the State.

We believe that higher values of total (not incremental) cost-effectiveness are 

appropriate. Higher measures of cost-effectiveness than those used by the State have been used 

in both BART analyses and rule-making instances, over $10,000/ton in some instances.47 As 

 

47 See National Park Service Spreadsheet ―EGUs with Proposed BART NOx Controls‖ and ―EGUs with Proposed 

BART SO2 Controls‖ dated November 13, 2009, Ex. 32 and Ex. 18, demonstrating BART determinations at cost 

effectiveness up to $7,309/ton (SO2) and $3,778/ton (NOx); $10,000/ton was determined to be cost effective for 

BACT in 2001, equivalent to over $13,000/ton today. See expert report of Matt Haber - EPA, Best Available Control 

Technologies for the Baldwin Generating Station, Baldwin, Illinois, prepared for the United States in connection 

with United States v. Illinois Power Company and Dynegy Midwest Generation, Inc., Civil Action 99-883-MJR, in 

the U.S. District Court for the Southern District of Illinois, April 2002, p. 17, Ex. 16; Memorandum of John S. Seitz 
Page 27 of 34

noted by EPA itself in its comments in the present instance, there is no justification to limit the 

cost-effectiveness to just those values considered in the examples of presumptive-BART, as has 

been done by the utilities and the State.

Considering a higher range of cost-effectiveness, the application of TESCR and/or 

LDSCR is cost-effective in many cases in the instances where considered. This is in spite of the 

lack of transparency in the costs themselves as noted above. In other cases where it is not costeffective at this metric, we stand by our comment on the lack of transparency. We also note that 

at this level of cost-effectiveness, other NOx control technologies that were incorrectly rejected 

(such as SNCR) are also cost-effective.

Thus, there is no justification for rejecting TESCR or LDSCR as NOx BART. Therefore, 

the proposed BART limits are flawed and the analysis should be rejected.

3. Specific Comments on Each NOx BART Analysis

Our additional comments on the seven specific BART utility boilers NOx BART analyses 

are noted below. However, these are not extensive in view of the lack of time provided for 

public comment. The brevity of these comments should not be interpreted as an indicator of 

agreement with the analyses or the conclusions presented in the proposed RH SIP. As such, we 

stand by comments made by others including the U.S. EPA in specific instances, particularly as 

related to the incorrect assumptions in the design and cost analyses present by industry 

consultants including Sargent and Lundy.

Basin Electric Power Cooperative Leland Olds Station Unit 1 - This unit is a wall-fired 

pulverized coal boiler combusting primarily lignite coal (80-100%) and PRB subbituminous coal 

(20-0%). The existing nitrogen oxides control equipment is low NOx burners installed in 1995. 

The BART selected by the State is a limit of 0.19 pounds per million Btu of heat input on a 30-

day rolling average basis. This limit is to be achieved by the installation of selective noncatalytic 

reduction (SNCR) and basic separated overfire air (SOFA). We believe that these technologies 

do not constitute BART and that HDSCR was improperly rejected in the analysis. We also 

believe that LDSCR with reheat that was considered in the analysis was improperly rejected 

given that its cost-effectiveness, as calculated with non-transparent cost data, was in line with the 

range of other cost-effectiveness decisions. 

Basin Electric Power Cooperative Leland Olds Station Unit 2 - This unit is a cyclone boiler 

combusting primarily lignite coal (80-100%) and PRB subbituminous coal (20-0%). The unit has 

no existing nitrogen oxides control equipment. The BART selected by the State is a limit of 0.35 

pounds per million Btu of heat input on a 30-day rolling average basis. This limit is to be 

achieved by the installation of selective noncatalytic reduction (SNCR) and advanced separated 

overfire air (ASOFA). We believe that these technologies do not constitute BART and that 

HDSCR was improperly rejected in the analysis. As noted above for Unit 1 for this station, 

LDSCR was improperly rejected as BART based on erroneous cost criteria.

 

to Air Division Directors, BACT and LAER for emissions of nitrogen oxides and volatile organic compounds at 

Tier 2/Gasoline Sulfur Refinery Projects (Jan. 19, 2001), at 3, Ex. 17.
Page 28 of 34

Great River Energy Coal Creek Station Unit 1 and Unit 2 - Unit 1 and Unit 2 are identical 

tangentially-fired pulverized coal boilers combusting lignite coal. The existing nitrogen oxides 

control equipment is low NOx burners (LNB) and separated overfire air (SOFA). The BART 

selected by the Department for each unit is a limit of 0.17 pounds per million Btu of heat input 

on a 30-day rolling average basis. This limit is to be achieved by the use of the existing low NOx

burners (LNB) and modified/additional separated overfire air (SOFA). We believe that these 

technologies do not constitute BART and that HDSCR was improperly rejected in the analysis. 

We also believe that an improper value (80%) was used as the control efficiency for LDSCR, 

resulting in an erroneously high cost-effectiveness for LDSCR.

Great River Energy Stanton Station Unit 1 - Unit 1 is a wall-fired pulverized coal boiler 

combusting PRB subbituminous coal and lignite coal. The existing nitrogen oxides control 

equipment is low NOx burners. The BART selected by the State is a limit of 0.29 pounds per 

million Btu of heat input on a 30-day rolling average basis when burning only lignite coal, a limit 

of 0.23 pounds per million Btu of heat input on a 30-day rolling average basis when burning 

subbituminous coal, and a weighted average emission limit when burning a combination of 

lignite and subbituminous coal. These limits are to be achieved by the installation of low NOx

burners (LNB), overfire air (OFA), and selective noncatalytic reduction (SNCR). We believe 

that these technologies do not constitute BART and that HDSCR was improperly rejected in the 

analysis. We also believe that LDSCR, which was considered technically feasible, was 

improperly rejected given its cost-effectiveness of $6,475 is in the range of appropriate costeffectiveness values.

Minnkota Power Cooperative Milton R. Young Station Unit 1 and Unit 2 - Unit 1 and Unit 2 are 

both cyclone boilers burning lignite coal. The units have no existing nitrogen oxides control 

equipment. The BART selected by the State for Unit 1 is a limit of 0.36 pounds per million Btu 

of heat input on a 30-day rolling average basis and for Unit 2 is a limit of 0.35 pounds per 

million Btu of heat input on a 30-day rolling average basis. These limits will be achieved by the 

installation of selective noncatalytic reduction (SNCR) and advanced separated overfire air 

(ASOFA). These technologies and the limits contained in the draft SIP are identical to the 

provisions in the consent decree. The State has done nothing more than take what has already 

been required by law and rolled that into the BART analysis. We believe that this does not 

constitute an adequate BART analysis. 

Specifically, we believe that the selected technologies do not constitute BART and that HDSCR 

was improperly rejected in the analysis. We also believe that LDSCR and TESCR, which were 

considered technically feasible, were improperly rejected given cost-effectiveness values of 

$3,906/$5,591 (LDSCR) and $4,835/$6,266 (TESCR) for Unit 1 and $4291/$6382 (LDSCR) and 

$4,948/$7081 (TESCR) for Unit 2 are in the range of appropriate cost-effectiveness values.
Page 29 of 34

II. NDDH Has Failed to Include Other Emission Reduction Requirements as Part of Its 

Long Term Strategy to Meet Reasonable Progress Requirements Which Must Be Designed 

to Meet the Goal of Natural Visibility Conditions by 2064

Although NDDH evaluated additional controls at Antelope Valley Units 1 and 2, Coyote 

Station, the Great Plains SynFuel Plant, and the Tioga Gas Plant, NDDH did not ultimately 

propose any additional emission reductions as part of its long term strategy to meet reasonable 

progress goals. NDDH placed heavy focus on these additional controls based on costs, and 

NDDH discounted all additional controls at these facilities due to its determination of a limited 

visibility benefit to be gained from the controls. Draft North Dakota SIP for Regional Haze at 

185.

NDDH has not adequately met the regional haze requirements of developing a long term 

strategy to show how it would meet reasonable progress goals to attain natural visibility 

conditions by 2064, as required by 40 C.F.R. §51.308(d)(1) and (d)(3). First, NDDH should not 

have limited its analysis of additional measures to provide for reasonable progress to facilities 

not already controlled by BART. As shown above, NDDH’s proposed BART emission limits 

and requirements do not reflect the maximum emission reductions that could be achieved at the 

State’s EGUs. For those controls or more stringent control efficiencies that NDDH determines 

are not required to meet BART, NDDH must still evaluate use of those control technologies 

and/or methods as part of its long term strategy to meet reasonable progress goals. For example, 

if NDDH determined SCR is not BART for an EGU, it could still require SCR at that EGU to 

meet reasonable progress requirements. Further, NDDH also excluded the Heskett EGU from 

evaluation of long term strategy requirements. While NDDH postponed a determination of 

whether Heskett was subject to BART, that should not exclude the unit from evaluation of 

pollution controls as part of the State’s long term strategy.

Second, in evaluating additional control measures to meet the national visibility goal, 

NDDH should not just place emphasis on the benefit to visibility achieved by the reductions at 

each emissions unit. Instead, NDDH should evaluate the cumulative effective of the State’s 

strategy to meet reasonable progress goals to attain natural visibility conditions by 2064. 40 

C.F.R. §51.308(d)(3)(iv)(G). 

Further, 40 C.F.R. §51.302(d)(3)(ii) provides:

Where other States cause or contribute to impairment in a mandatory Class I 

Federal area, the State must demonstrate that it has included in its implementation 

plan all measures necessary to obtain its share of the emission reductions needed 

to meet the progress goal for the area.

[Emphasis added.]

Thus, NDDH must evaluate all available measure to reduce North Dakota’s share of visibility 

impairing pollution as part of its long term strategy. Such available measures include emission 

reduction programs, imposition of emission limitations, and source retirement and replacements. 
Page 30 of 34

NDDH did not evaluate the potential for any EGU retirements in its draft regional haze 

SIP. Given the age of the State’s coal-fired EGUs along with the fact that North Dakota’s draft 

SIP falls far short of meeting reasonable progress goals for regional haze, NDDH must consider 

EGU retirements to meet reasonable progress goals as part of its long term strategy.

For the sources for which NDDH did evaluate controls, it did not evaluate the most 

stringent levels of control achievable. For example, for Antelope Valley Units 1 and 2, NDDH 

only evaluated a wet scrubber that could achieve 95% SO2 removal even though, as we have 

shown above, wet scrubbers can achieve 98-99% SO2 removal. Further, NDDH did not conduct 

any modeling to show the visibility improvement from use of a wet scrubber at the Antelope 

Valley units because it found the costs to be too high. As shown in the National Park Service 

SO2 BART Summary spreadsheet (Ex. 11), the costs of wet scrubbers at Antelope Valley Units 1 

and 2 ($5,899-$6,780/ton) are not out of the range of SO2 BART control costs. A new wet 

scrubber at the Coyote Station is quite cost effective at $2,593/ton. 

Even if the costs were more than previously required as BART, that should not be a 

reason alone to discount use of a control technology. This is especially true with North Dakota’s 

regional haze SIP which fails to meet the uniform rate of progress necessary to attain natural 

visibility conditions by 2064. Further, given the fact that North Dakota sources cause and 

contribute to visibility impairment in other states, it is imperative that NDDH include all

emission reduction measures in its long term strategy to meet reasonable progress goals. While 

it is true there will be costs to reducing visibility impairing pollution from North Dakota sources, 

such costs do not allow North Dakota to ignore the national visibility goal of the Clean Air Act 

and the requirements for regional haze SIPs. Thus, cost of controls alone should not be a 

determining factor in evaluating additional emission reduction options in the State’s long term 

strategy. Accordingly, NDDH should evaluate the use of SCR at units such as Antelope Valley 

and Coyote, as well as at those EGUs for which NDDH determines SCR is not BART, for 

inclusion in its long term strategy.

In summary, North Dakota’s draft SIP for regional haze fails to include adequate 

reasonable progress goals and fails to include an adequate long term strategy to meet reasonable 

progress goals. While North Dakota’s proposed BART determinations will greatly reduce SO2

emissions and, to a lesser extent, NOx emissions from the State’s BART-eligible EGUs, the 

State’s plan does not go far enough to ensure that North Dakota’s Class I areas and the Class I 

areas in other states that are impacted by North Dakota sources will achieve natural visibility 

conditions by 2064. Thus, North Dakota must adopt additional measures or requirements, 

including consideration of source retirements, as part of its long term strategy to achieve 

reasonable progress toward the national visibility goal.

III. North Dakota Must Also Propose Short Term Average Emission Limits on SO2

Emissions in Order to Ensure Protection of the SO2 Increments of the State’s Class I Areas

The SO2 emission reductions that North Dakota has proposed as BART for the State’s 

BART-eligible EGUs should greatly help the State address the SO2 increment violations that 

have been occurring at the North Dakota Class I areas.48 And we recently learned that the State

 

48 See 5/24/99 North Dakota Class I Area Calpuff Analysis; see also 5/8/03 EPA Dispersion Modeling Analysis.
Page 31 of 34

has issued a draft plan for updating and evaluating a new modeling protocol and that the State

plans on conducting a new periodic assessment of increment consumption in the near future.49 

However, in order for the State to be able to count on the SO2 emission reductions proposed to 

meet BART in its new periodic assessment of SO2 increment consumption or in other increment 

modeling analyses (such as those conducted for PSD permits), NDDH must propose for public 

comment short term average emission limits in addition to the 30-day average BART emission 

limits for the State’s EGUs that are installing pollution controls. A long term average limit does 

not ensure 3-hour average or 24-hour average emissions will be reduced to the same levels, 

especially given that NDDH’s proposed SO2 BART limits are based on worst case sulfur content 

assumptions that are not reflective of the coal the units are currently burning.

The visibility protection program falls under the same part of the Clean Air Act that the 

increments do – that is, the prevention of significant deterioration program of Part C of the Clean 

Air Act. One of the mandates of the prevention of significant deterioration program is to 

preserve, protect, and enhance the air quality in national parks and wilderness Class I areas. 

CAA §160(2). For Class I areas, the Clean Air Act provides protection for Class I areas by 

requiring compliance with stringent PSD increments and by requiring protection of air quality 

related values including visibility. CAA §§162, 165(d), and 169A. 

Because air quality modeling analyses that comply with EPA policies for increment 

consumption have shown that violations of the 3-hour and 24-hour average SO2 increment are 

occurring in the State’s Class I areas, it is imperative that North Dakota harmonize the SO2

emission reductions that the State is requiring as part of its regional haze SIP with the 

requirement for the State’s Class I areas to comply with the 3-hour and 24-hour average SO2

increments. Thus, North Dakota must impose short term average SO2 emission limits reflective 

of the SO2 controls and emission reductions being required in its draft regional haze plan 

(primarily through BART) in order to be able to rely on the emission reductions in analyses of 

compliance with the 3-hour and 24-hour average SO2 Class I increments. 

Such emission limits must be reflective of the capabilities of the SO2 controls being 

installed, in order to be consistent with the general purpose of the North Dakota regulations to 

―state such requirements as shall be required to achieve and maintain the best air quality 

possible, consistent with the best available control technology... and to facilitate the enjoyment 

of the natural attractions of this state.‖ ND Reg. 33-15-01-01. The definition of ―best available

control technology‖ under the State’s PSD regulations is defined as an emission limitation 

―based on the maximum degree of reduction‖ of a pollutant that is achievable. ND Reg. 33-15-

15-01.2 incorporating by reference 40 C.F.R. 52.21(b)(12). And ―emission limitation‖ is defined 

under the Clean Air Act as a requirement established by a state or EPA which limits emissions 

―on a continuous basis.‖ CAA §302(k). Thus, in establishing short term average emission limits 

that can be relied upon in analyses of compliance with the PSD increments, North Dakota must 

set limits consistent with the maximum degree of emission reductions that is achievable with the 

BART SO2 controls and that reflect operation of the SO2 controls on a continuous basis. 

Without such short term average emission limits, NDDH cannot rely on the planned SO2

 

49 As discussed in NDDH’s ―A Plan for Updating and Testing the North Dakota Department of Health’s CALMET 

and CALPUFF Protocol,‖ Draft Final, December 29, 2009, available at 

http://www.ndhealth.gov/AQ/NoticesPSDStatusIncrementConsumption.htm.
Page 32 of 34

reductions at the State’s EGUs in any increment analyses until the BART controls have been 

installed and normal operation has resumed for at least two years. 

As we stated above, we understand from the NDDH’s draft plan to revise the State’s 

modeling protocol that the State plans to conduct a new periodic assessment of SO2 increment 

consumption soon. Not only is such an analysis required under 40 C.F.R. §51.166(a)(4), but a 

new analysis is also required because, in its previous assessment of increment consumption, 

NDDH relied on techniques and methods that are inconsistent with EPA policy and the intent of 

the Clean Air Act. Although EPA proposed revisions to its regulations that would have allowed 

for many of North Dakota’s increment modeling techniques and approaches50, EPA never 

finalized that rulemaking and has indicated it will not finalize that rulemaking. Therefore, North 

Dakota cannot rely on those techniques and approaches that are inconsistent with EPA policy 

and with the intent of the PSD program of the Clean Air Act in evaluating increment 

consumption. Because prior analyses by NDDH (in 1999) and by EPA (in 2003) that more 

closely complied with EPA policy showed numerous violations of the 3-hour and 24-hour SO2

increments in the State’s Class I areas, it is imperative that NDDH conduct a new assessment of 

SO2 increment consumption following EPA policy and consistent with the PSD mandates of the 

Clean Air Act. And, for NDDH to rely on the BART SO2 reductions in such an analysis, the 

State must propose and adopt short term average emission limits.

IV. Other General Comments

1. The proposed RH SIP notes that the visibility monitor (IMPROVE THRO1 monitor) is 

located at the Painted Canyon Overlook in the South Unit of Theodore Roosevelt

National Park. It also notes that this one monitor is ―representative‖ of haze conditions in 

the separate North Unit and the separate Elkhorn Ranch Unit of the THRO Park. 

However, why and how a single monitor can be or is representative of haze conditions at 

these other, distant locations is never discussed. We believe that without technical 

support, the assumption that THRO1 is representative of conditions elsewhere in the 

THRO are unsupported. It is not enough to simply assert that this one monitor is 

representative, without basis (see page 31 of the proposed RH SIP). To the extent that 

the RH SIP relies on this TR-North Unit and TR-Elkhorn Ranch Unit. This is a 

fundamental flaw of the analysis.51

2. The RH SIP does not provide the details of its calculations for baseline visibility 

including all input assumptions. Thus, the values used cannot be verified. This is 

especially important since the values used are greater than EPA recommended values.

3. The proposed SIP (page 68) notes that ―The FLMs and EPA have expressed concerns 

about the modeling that was conducted. MDU has agreed to remodel using a revised 

 

50 72 Fed.Reg. 31372, June 6, 2007.

51 This critique is not in conflict with our support for treating THRO as it was designated: one mandatory Class I 

area, not three. In this case, THRO is one Class I area spread out over significant distance, and multiple monitors are 

appropriate in the same way that they would be for one large contiguous Class I area (e.g. Yellowstone National 

Park). 
Page 33 of 34

modeling protocol. The Department will reassess the determination to exclude Heskett 

Station Unit 2 following review of the revised modeling. Heskett Unit 2 will be 

addressed in a supplement to this SIP revision.‖ This analysis cannot be put off to the 

future and must be part of the regional haze plan. Without this analysis, the SIP is 

incomplete. In the alternate, if the Heskett analysis is not now included, the supplement 

should be subject to full public review.

Thank you for the opportunity to comment on the draft Regional Haze State 

Implementation Plan. 

Sincerely, 

Stephanie Kodish

National Parks Conservation Association

706 Walnut Street, Suite 200

Knoxville, TN 37902

865-329-2424 

Mark Trechock, Staff Director

Dakota Resource Council

P. O. Box 1095

Dickinson ND 58602-1095

701-483-2851

Paul Danicic, Executive Director

Friends of the Boundary Waters Wilderness

401 North Third Street, Suite 290

Minneapolis, MN 55401

612-332-9630

Nicole Shalla, Staff Attorney

Plains Justice

100 First Street SW, Second Floor

Cedar Rapids, IA 52404

319-362-2120

Michael Lukes, Chair

Dakotah Chapter of the Sierra Club

311 East Thayer Ave, Suite 113

Bismarck ND 58501

701-530-9288
Page 34 of 34

Jim Heisinger, Chair

South Dakota Chapter of the Sierra Club

P.O. Box 1624

Rapid City, SD 57709-1624

605-342-2244

Cory MacNulty, Executive Director

Voyageurs National Park Association

126 N. 3rd St., Suite 400

Minneapolis, MN 55401

612-333-5424