January 8 , 2010

Via email:

Terry O’Clair Director, Division of Air Quality North Dakota Department of Health

918 E ast 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 Cl ub, 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

. T he 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 B est Available Retrofit

T echnolog y (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 inPage 2 of 34

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, c olor and geologic formation. While some haze causing particles result from natural processes, most result from anthropogenic sources of pollution

. H aze forming pollutants including sulfur dioxide ( SO 2 ), nitrogen oxides ( NO

x ), particulate matter (PM),

vola tile organic compounds (VOCs), and ammonia (NH 3 ) 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 nation al goal the prevention of any future, and remedying of any existing, impairment of visibility in the mandatory class I Federal areas wh ich impairment results from man made air pollution

. ‖ 42 U.S.C. §7491(a)(1). In order to meet this goal, a State is require d to design an implementation plan to red uce 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 mu st 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). T wo of the most critical features of a SIP are requirements for (1) the inst allation 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

— T heodore R oosevelt 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 Wildli fe 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 Ar ea 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 museum s of our nation’s hist ory

. Visitors from

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

l ocal economies.

N ational parks and wilderness areas are of great natural and cultural value and also engines for sus tainable local capital. For example, in 2008

, Nation al 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. 2 They also

attract businesses and individua ls 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 vis ited Wind Cave National Park; 221,585 visited Voyageurs National Park and 14,038 visited Isle Royale National Park. 5

E xcessive emissions from North Dakota not only obscure the region’s scenic vis tas Congress sought to protect, but also contribute to a ho st of public health problems as well as adverse impacts to wildlife and vegetation . For example, NO

x and VOCs are precursors to ground level ozone , or smog . Ground level ozone is associated with respiratory diseases, asthma attacks, and decreased lung func tion. 6 SO 2 pollution contributes to respiratory problems, particularly for children and the elderly, and aggravates existing heart and lung diseases. Exposure to p articulate matter , m ade up of sulfates and nitrates, has been a ssociated with

r educed lung fu nction, increased susceptibility to respiratory infection s, 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. 8 These benefits are estima ted under the assumption that the Regional Haze Rule will be implemented as i ntended

- therefore these numbers may be lower if North

Dakota do es not revise its plan.

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

visi bility 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 comm ents 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 2 006) [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.g ov/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 provid e 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. W e understand that the EPA has requested

states to submit SIPs by Ja nuary 15, 2010. Understandably, North Dakota would like to abid e by this suggested timeline, however, the short turnaround

— f ive 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,

w e request NDDH coordin ate with EPA to submit the North Dakota SI P in a timely manner without compromising full consideration of public comments.

I. The Clean Air Act and Fe deral 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 impair ment 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. 9 To protect these treasures, the regional haze program establishes a regulatory fl oor and requires states to design and implement programs at least as stringent as the national floor to curb haze causing emissions located within their jurisdiction s . 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 t owards 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 w hich 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 c ompliance, 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 impai rment 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 define d 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 operate d 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. §51.30 8(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 enfor ceable measures designed to meet regional progress goals. In developing its plan, t he State must document the technical basis for the SIP, including monitoring data, modeling, and emission information, including the baseline emission inventory upon which i ts strategies are based. 40 C.F.R. §51.308(d)(3)(iii).

In developing its long

- term strategy, th e State must consider all anthropogenic sources of visibility impairment and evaluate different emission reduction strategies beyond those prescribed by the BAR T 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 retiremen t 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) Enforceabili ty of emission limitation s and control measures; and (G) The anticipat ed 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 T heodore 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 t o 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 poll ution 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

pro cess, and N orth Dakota is well within its rights to formally re quest 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 re ductions 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 re asonable progress goals are attained, the State may n ot 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 emis sions 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 mee t 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 ca using 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 nece ssary 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 re sponsibility 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 s tates’ 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 SO 2 limit of 0.25 lb/MMBtu as w ell as the need for NO

x 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.)

N orth 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 SO 2 BART Limits Fail to Reflect the Degree of SO 2 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

- f ired electric utility steam generating units (EGUs) that NDDH determined were subject to BART. Specifically, NDDH proposed SO 2 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 S O 2 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 co al

- 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 o n 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 BA RT 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 t o 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, Append ix 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 p rovide:

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 l evel 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

SO 2 from the State ’s EGUs as is discussed fu rther 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 SO 2 BART determinations, NDDH relied on worst case projections of sulfur content of the coal to be burned in justifying the SO 2 emission limits as BART. For example, for Leland Olds, which currently has an uncontrolled SO 2 rate exiting the boilers of 1.82 to 1.83 lb/MMBtu (2000

- 2004 average) 11 , NDDH assumed

an uncontrolled SO 2 emission rate of 3.02 lb/MMBtu 12 . Th ere is no justification for assuming such a high uncontrolled SO 2 emission rate. Similarly, Coal Creek Units 1 and 2 burned coal with a sulfur content of 0.61% during 2003

- 2004 13 , and yet NDDH relied on a worst case coal sulfur content of 1.1%, close to do uble the 2003

- 2004 average coal sulfur content, in proposing a BART SO 2 limit. 14

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

SO 2 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 SO 2 emission rate of 3.48 lb/MMBtu in proposing BART limits for SO 2

. 16 Although NDDH’s BART Determination for Unit 1

did not include an uncontrolled SO 2 emission rate, it also appears that NDDH assumed a higher

- than

- actual SO 2 rate for Unit 1. NDDH assumed 95% SO 2 removal would result in an emission reduction of 20,443 tpy. 17 Yet, the 2000

- 2004 average SO 2 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 SO 2 , which is an impossibility.

This shows that, not only did NDDH improperly rely on the worst case sulfur content coal in proposing BART lim its, NDDH also inflated the baseline actual emissions for some EGUs to reflect higher sulfur content coal, and then calculated SO 2 emission

reductions based on assumed levels of SO 2 removal from baseline emissions that never actually occurred. Thus, NDDH greatly overstated the emission reductions that would occur from implementation of SO 2 BART controls. Presumably

, this was also carried over into NDDH’s modeling conducted for the BART analyses as well.

In evaluating SO 2 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 BA RT 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 lignit e, NDDH did not rely on worst case coal. Instead, it used the average of the annual SO 2 emission rate from 2001

- 2004, applied its assumed SO 2 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 SO 2 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 wi th 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 SO 2 control than the 95% control assumed by NDDH, as is disc ussed 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 SO 2 removal to meet a SO 2 BART emission limit that is set based on the coal currently burned a t 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

SO 2 BART limits on the ultimate worst case sulfur content coal to be burned at these

units.

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

Achievable with the Best SO 2 Controls

All but one 23 of NDDH’s SO 2 BART determinations requires the use of new or upgraded wet scrubbers, a technology capable of reducing SO 2 emissions by 99% or more. Despite this achievable control efficiency, NDDH simply proposed EPA’s presumptive BART limits for SO 2 : either 95% control or an emission limit of 0.15 lb/MMBtu. While wet scrubbers can routinely achieve the highest levels of SO 2 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% SO 2 removal even with low sulfur coal. 24 For example, the Chiyoda’s bubbling jet reactor has consistently ac hieved >99% SO 2 removal during long

- term operation at the Shinko

Kobe power plant in Japan. This facility consists of two 700

- MW coal

- fired utility boilers. The wet FGD was designed to achieve 0.014 lb SO 2 /MMBtu (9 ppmv at 3% oxygen) on an

instantaneous b asis and has consistently exceeded this level of control while treating gases with

inlet SO 2 concentrations of 1.78 lb/MMBtu. 25 Based on actual SO 2 emissions data, the North

Dakota BART

- eligible EGUs have inlet SO 2 concentrations of this level or higher. This technology has been guaranteed by Chiyoda to achieve 99% SO 2 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 Yates 27 , Dayton Power & Lig ht’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 Powe r & 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 SO 2 removal efficien cies 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 Bl ack&Veatch/Chiyoda Wet Flue Gas Desulfurization System in North America

Succ essfully 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/n one/1/Go

- Take

- a

- Bath/ , Ex. 9.

30 Chiyoda Licenses Its Flue Gas Desulfurization Technology in USA Newly for 5 Coal

- Fired Generation Units,

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

Power Owned 4 FG D Units, January 26, 2005, Ex. 1 1

.

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

Facilit y of MHI Singl e Tower FGD, Ex. 13

.

33 Mitsubishi Hi gh SO2 Removal Experience, Ex. 14

.Page 12 of 34

technologies could achie ve 99.5% control for $1,240 to $2,875 per ton of SO 2 removed. Ex. 1 5

. 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 SO 2 BART determinations. 35

3. The Proposed SO 2 BART Limits Should Be Expressed Multiple Ways

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

efficienc y. 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 SO 2 BART limits should be expressed both ways. Without a minimum required removal efficiency, the achievable SO 2 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 a s 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 practic e for compliance purposes, and also serves as an actual time

- based limit for modeling

purposes.

4. NDDH’s Proposed SO 2 Emiss ion Limits Fail to Reflect BART

Thus far, three general flaws have been noted in the NDDH SO 2 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 SO 2 emission rates from the EGUs

evaluated for BART. Table 1 below highlights this impact.

34 $10,000/ton in 200 1, 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 Com pany 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 an d 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‖ da ted November 13, 2009,

Ex. 1 8

.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

– 9 9% 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 SO 2 BART limits for each unit of either 95% removal

of the inlet SO 2 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% SO 2 removal at each unit based on the annual average of uncontrolled S O 2 emissions at

each unit. Such an SO 2 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 SO 2 removal that is achievable with a wet scru bber. Thus, at the minimum, the BART emission limit should be based on 95% removal from the annual average of the uncontrolled SO 2 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% SO 2 removal will not ensure 95% removal is required until the uncontrolled SO 2 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 SO 2 control efficiency of a wet scrubber.

Indeed, based on the discussion above regarding the SO 2 removal capabilities of a wet

scru bber, a more appropriate BART limit would reflect 98

- 99% SO 2 removal. Even assuming

the worst case uncontrolled SO 2 emissions identified by NDDH of 3.20 lb/MMBtu, 98% removal

would reflect an emission limit of 0.064 lb/MMBtu. This SO 2 emission limit base d on worst

case coal and an achievable level of SO 2 removal would reflect 96.5% SO 2 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 eq uate to a SO 2 emission limit of 0.03 lb/MMBtu. With current coal, this would reflect 98.4% removal. This emission level and SO 2 removal efficiency has been shown to be achievable and has been achieved in practice.

The attached National Park Service sp readsheet of best available control technology (BACT) determinations for coal

- fired power plants shows that BACT limits as high as the 0.15

lb/MMBtu SO 2 BART limits proposed for the Leland Ol ds units are unheard of. Ex. 1 9 . The proposed permit for the Pl ant Washington facility requires as part of the facility’s BACT limits a

97.5% SO 2 removal efficiency requirement that would apply on a 30

- day rolling averagePage 14 of 34

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

Centra l Appalachian coal or a combination of the two. The Desert Rock facility, which will burn low sulfur western coal, is subject to an SO 2 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

SO 2 . As Ex. 25 shows, there are numerous coal

- fired units that are achieving SO 2 emission rates

much lower than the 0.15 lb/MMBtu SO 2 BART limit proposed for the Leland Olds Units. The

lowest SO 2 emission rates being achieved are at the Pleasant Prairie units which are emitting SO 2 at 0.021 to 0.027 lb/MMBtu with wet scrubbers.

Thus, for all of the reasons discussed above as supported by the atta ched 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 SO 2 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

- d ay 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 SO 2 removal efficiencies and/or use of lower sulfur content coal. In addit ion 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 SO 2 removal efficiency is required regardless of the type of coal bur ned.

Thus, the proposed 0.15 lb/MMBtu SO 2 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 SO 2 BART limit would be in the range of 0.03 to 0.091 lb/MMBt u, 30

- day average, along with an SO 2 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 SO 2 BART limit of a 95% removal efficiency from the inlet SO 2 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 SO 2 emissions from Milton R . Young Unit 1. Instead, an SO 2 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 SO 2 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 re asoning provided

36 Proposed Pla nt 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 SO 2 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 SO 2 removal efficiencies are achievable. E ven using NDDH’s worst case

uncontrolled SO 2 emission rate for Milton R. Young Unit 1 of 3.48 lb/MMBtu, 98% SO 2 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% SO 2 removal efficiency requirement for Milton R. Young Unit 1 falls far short of reflecting the best syste m of continuous emission reduction at the unit. A much more appropriate SO 2 BART limit would be in the range of 0.035 to 0.094 lb/MMBtu, 30

- day average, along with a 95% or higher SO 2 removal efficiency requirement.

Milton R. Young Unit 2 is already equ ipped with a wet scrubber which, according to NDDH, achieves approximately 65% SO 2 control. NDDH has proposed requiring upgrades to

the scrubber to achieve 95% control or meet an SO 2 emission limit of 0.15 lb/MMBtu, 30

- day average, as BART for Milton R. Y oung 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 SO 2 control that is achievable with a wet scrubber

– up to 98

- 99% SO 2 removal.

Along with an SO 2 removal requirement, NDDH should also impose an emissions limit

as BART for Unit 2. Because the same coal is burned and the same control efficienci es 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 SO 2 emission limit in the range of 0.035

– 0.094 lb/MMBtu along with a high SO 2 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

SO 2 removal efficiencies than represented by this range of more appropria te 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 e mission limits are long term average emission limits, and peaks in emissions can be smoothed out with increased SO 2 removal efficiencies and/or use

of lower sulfur content coal.

c. Coal Creek

For Coal Creek Units 1 and 2, NDDH proposed SO 2 BART limit s for each unit of either

95% removal of the inlet SO 2 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% SO 2 removal efficiencies as claimed by NDDH, then the uncontroll ed SO 2 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% SO 2 removal based on the annual average of

uncontrolled SO 2 emissions at each unit. Suc h SO 2 removal efficiencies fall far short of what is achievable with a wet scrubber at the Coal Creek units. A removal efficiency of 95% controlPage 16 of 34

reflects the minimum level of SO 2 removal that is achievable with a wet scrubber. Thus, at the minimum, the B ART emission limit should be based on 95% removal from the annual average of

the uncontrolled SO 2 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% SO 2 removal will not ensure 95% removal is required until

the uncontrolled SO 2 emissions increase significantly, to about 2.8 lb/MMBtu. Thus, it is imperative that the lb/MMBtu limit reflect no less 95% contr ol off of current coal.

Indeed, based on the discussion above regarding the SO 2 removal capabilities of a wet scrubber, a more appropriate BART limit would reflect 98

- 99% SO 2 removal. Even assuming

the worst case uncontrolled SO 2 emissions identified by NDDH of 2.92 lb/MMBtu 38 , 98%

removal would reflect an emission limit of 0.058 lb/MMBtu. And this SO 2 emission limit based

on worst case coal and an achievable level of SO 2 removal would reflect at most 96.6% SO 2 removal from current coal

– a control eff iciency that is clearly achievable with a wet scrubber. Ninety

- nine percent removal off of worst case coal at Coal Creek would equate to a SO 2 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, SO 2 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 SO 2 removal efficiencies than represented by this range of more appropriate BART limits co uld 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 ar e long term average emission limits, and peaks in emissions can be smoothed

out with increased SO 2 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 SO 2 removal efficiency is required regardless of the type of coal burned. Therefore, a

SO 2 control efficiency requirement should also be imposed as BAR T, no less than 95% control.

d. Stanton Unit 1

For Stanton Unit 1, NDDH proposed as BART for SO 2 the use of a spray dryer with a

fabric filter and an SO 2 emission limit of 0.24 lb/MMBtu or an SO 2 removal efficiency of 90%,

both on a 30

- day rolling aver age basis. This emission limit was derived assuming 90% removal from the highest calendar year average SO 2 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 f

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

uncontrolled SO 2 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 U nit 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 SO 2 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% SO 2 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 SO 2 BACT limits than 0.23 lb/MMBtu.

Those facilities include the Newmont Nevada TS power plant, the proposed White Pine power plant 39 , Toquop, and the Dry Fork power plant. The Newmont Nevada power plant is subject to

a minimum 95% SO 2 removal efficiency requirement when burning coal with a sulfur content equal to or greater t han 0.45% and is subject to a minimum 91% SO 2 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 SO 2 BACT limit of 0.065 lb/MMBtu when burning coal with less than 0.45% sulfur content. The proposed Toquop permit included an SO 2 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 SO 2 BACT limit of 0.07

lb/MMBtu. 42 Other examples of low SO 2 emission limits and high SO 2 removal rates being required as BACT can be found in the National Park Servi ce’s spreadsheet of BACT

determinations for coal

- fired ele ctrical generating units, Ex. 1 9

.

Regardless of whether NDDH underestimated the effectiveness of a spray dryer, a wet scrubber can remove an even greater amount of SO 2 than a spray dryer. Althou gh 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 SO 2 removed would not provide that much of a visibility improvement. The cost effec tiveness of the wet scrubber at 95% removal for Stanton Unit 1 was actually quite reasonable at $1,480 per ton of SO 2 removed. Stanton BART Determination at 5. As shown in the National Park Service spreadshee t of BART determinations (Ex. 1 8 ), there are s everal instances where wet scrubbers were required to meet

SO 2 BART requirements with similar or even higher costs on a $/ton of SO 2 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 SO 2 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 ($1,8 48/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 SO 2 . Given that North D akota is far from meeting reasonable progress goals in remedying existing visibility impairment, NDDH must require as

BART the most effective SO 2 control

– especially when it is as cost effective as a wet scrubber

would be at Stanton Unit 1.

39 In March 2009, LS Power ―indefi nitely 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. 2 7

.

41 See Section V.A.2..a.(8) of draft Toquop perm it, 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% SO 2 removal. If a proper

SO 2 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 SO 2 emissions to a much g reater extent than a dry scrubber, NDDH must require the use of a wet scrubber as BART for SO 2 at Stanton Unit 1.

Along the same lines as our previous comments, the SO 2 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% SO 2 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. SO 2 emission limits of no hi gher 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 SO 2 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 SO 2 removal efficiencies and/or with the use of

lower sul fur 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 SO 2 removal efficiency is required regardl ess 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 SO 2 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 SO 2 BART Limits t hat
NDDH Must Take Into Account

Along with providing for improved visibility, there are also other environmental benefits to higher SO 2 removal requirements. Speci fically, very low SO 2 emission rates, on the order of single digit parts per million (ppm) concentrations, will be needed for the effective removal of carbon dioxide ( CO 2 ) from the gas stream. Many of the amine

- based CO 2 control methods currently under de velopment are very sensitive to sulfur and thus require very low SO 2 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 Performan ce Capability, Mega 2008, Ex. 2 9

.Page 19 of 34

It is well recogni zed that it is not a matter of if but when Congress and/or EPA will

mandate CO 2 reductions from industrial sources such as EGUs. Thus, if a more effective SO 2 control technology and more stringent control requirements will better prepare North Dakota’s

EG Us to be able to effectively remove CO 2 in the future, that must be taken into account in the BART analysis as another environmental benefit of a lower SO 2 emission limit. Indeed, as described above, there are wet scrubber technologies available that can remove 99+% of the SO 2

.

Further, lower emissions of SO 2 that are achievable with wet scrubbers also equate to

lower PM 2.5 concentrations since there will be less SO 2 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 SO 2 emissions from North Dakota’s EGUs, the result should be less sulfate deposition which should dec rease methylization of mercury.

All of the above must be taken into account by NDDH in proposing SO 2 BART limits for

the State ’s BART

- eligible EGUs. NDDH must require the best designed and most effective SO 2 controls on its BART

- eligible EGUs

– i.e., w et scrubbers designed to achieve 98

- 99% SO 2 removal

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

areas.

B. NO

x BART Comments

The following comments are provided with respect to the proposed NO

x BART levels in

the dra ft RH SIP proposed by NDDH. At the outset, it must be noted that technical issues pertaining to NO

x BART for the various coal

- fired electric utility units, which are the major NO

x sources affecting visibility and regional haz e 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 NO

x BART in the allowed 30

- day time period for public comment. This is particularly so given that the public c omment 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 s uch, 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

considerat ion; (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 Experime ntal Wetland, Environ. Sci. Techn ol., 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, an d Dissolved Organic Carbon, available at http://sofia.usgs.gov/projects/me rc_carbon/hgmeso_geer03abs.html

, Ex. 31.Page 20 of 34

The net result of rejection of SCR of any desi gn at the coal fired units is that otherwise large NO

x 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 comme nts on these and related topics at a later date:

(a) The process by which North Dakota selected the NO

x 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 s ignificantly 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 NO

x control options. F or 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 cost

ineffectiveness 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 redu ced) as a cap in this regard is fatally flawed. Numerous BART determinations in other states RH SIPs have accepted NO

x controls at levels higher than this level. 45

(e) The improper use of incremental cost

- effectiveness, as a tool to reject technologies (such

a s TESCR and HDSCR) which are otherwise cost

- effective, even under the flawed and

worst

- case analyses presented by the utilities (and accepted by the S tate). EPA has noted the error in relying on this metric in its comments. However, such direct and expre ss 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 cost

effectivene ss for North Dakota sources with those from other sources in other states subject to RH NO

x 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 deta ils 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 dura tions. (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 Co ntrols‖ dated November 13, 2009

, Ex. 32.Page 21 of 34

Finally, it should be noted that there was insufficient tim e to properly critique NO

x BART for the other NO

x sources (other than the utility boilers).

1. High Dust SCR (HDSCR) is Technically Feasible

As noted earlier, the applicability of SCR as NO

x control

– universally agreed to by all parties as being the techno logy with the highest degree of NO

x reduction potential (upwards of 90%, after consideration of in

- boiler NO

x controls such as low NO

x burners or over

- fire air etc.)

– has been the subject of technical discussion in North Dakota since at least 2006. Not o nly 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 techn ical infeasiblity grounds, the S tate 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 S tate 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 S tate’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 S tate’s position is an amalgam of all of the arguments that have been pushed consistently by t he 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 j udgment on the part of

th e S tate. An important secondary issue seems to be the S tate’s rejection of technical arguments and support from a most important source

– namely the vendors of SCR catalysts themselves.

The S tate’s technical infeasibility rejection of HDSCR boils down to a circ ular argument. Basically, the S tate 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) sub

bitumi nous 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 S tate’s view, it is so unique that there are no other s imilar 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 c an be used successfully.

The circ ular 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 onl y those) which are the subject of its analysis. This is akin to saying that a control technology will not work at a parti cular facility because it

has not been tried there yet.

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

- time applic ability 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 BART 46 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 coal

fired 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 bo iler 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, HDS CR 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 facto rs 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 bel ieve 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, en gineering 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 app lied 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, excl uding 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 te chnical concerns raised b y the S tate in attempting to support its position that HDSCR is not technically feasible.

a. Variability of Fuel Composition

The S tate 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 d esigner/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 e quipment 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 H D SCR shows the weakness of the S tate’s argument.

b. Results of the Coyote Pilot Testing

The S tate 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 n oted as a central point in the S tate’s determination that HDSCR cannot be successf ul. Yet, in key respects, the S tate intentionally or o therwise misrepresents these tests and their conclusions. This is puzzling because the S tate correctly notes that "the pilot testing....in hind

- sight, was ill

designed for a unit combusting North Dakota lignite..." In fact, it is undisputed that this test wa s 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 unknow n. 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

i nfluences 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 t herefrom should be rejected. It is a simple data validation issue. In particular, any conclusions relating to catalyst blinding or plugging etc., which depend on cat alyst geometry, from these flawed tests, should definitely be rejected. Knowing these fla ws and purposely choosing to ignore them while relying on these tests points to poor technic al judgment on the part of the S tate.

In fact, as the S tate 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 pro per guarantees for HDSCR. The S tate 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 deposi t 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..." T he 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 t he expected operating temperatures, such sodium compounds will generally not condense, this mechanism is speculative and unlikely. At under conditions where such condensation is an issuePage 25 of 34

(such as during shutdown), proper design such as by

- pass, can be use d. 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 HDSC R 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

- ca se 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 S tate 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, guarante e 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 guaran tees 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 th e 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

H DSCR.

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 NO

x limits proposed as BART ar e 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 p rocess; (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 NO

x reduced and $/deciview of visib ility 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 NO

x BART analysis and, therefore, the analysis should be redone.

Sepa rately from that, although the S tate 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 cost

estimates 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 associat ed 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 cos t

- effectiveness metrics by the S tate.

We bel ieve 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 A s

47 See National Park Service Spreadsheet ―EGUs with Proposed BART NOx Controls‖ and ―EGUs with Proposed BART SO2 Controls‖ dated November 13, 2009, Ex. 3 2 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 Ge nerating 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, A pril 2002, p. 17 , Ex. 16 ; Memorandum of John S. SeitzPage 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 hi gher 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 cost

effective at this metric, we stand by our comment on the lack of transparency. We also note that

at this level of cost

- effectiveness, other NO

x control technologies that were incorrectly rejected (such as SNCR) are also cost

- effective.

Thus, there is no justification for rejecting TESCR or LDSCR as NO

x BART. Therefore, the proposed BART limits are flawed and the analysis should be rejected.

3. Specific Comments on Each NO

x BART Analysis

Our additional comments on the seven specific BART utility boil ers NO

x 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 pre sented 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 Sargen t 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 l ow NO

x 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 bas ic 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 t hat 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 t o 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 NO

x 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 lim it is to be achieved by the use of the existing low NO

x 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 subbitumino us coal and lignite coal. The existing nitrogen oxides control equipment is low NO

x 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 install ation of low NO

x 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 cons idered technically feasible, was improperly rejected given its cost

- effectiveness of $6,475 is in the range of appropriate cost

effectiveness 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 containe d 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 anal ysis.

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 Natura l 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 additiona l 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 limit ed 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 achi eved 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 rea sonable 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 require ments. 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 me et 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 eva luated a wet scrubber that could achieve 95% SO 2 removal even though, as we have shown above, wet scrubbers can achieve 98

- 99% SO 2 removal. Further, NDDH did not conduct any modeling to show the visibility improvement from use of a wet scrubber at the Ant elope Valley units because it found the costs to be too high. As shown in the National Park Service

SO 2 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 SO 2 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 especiall y 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 oth er 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 cost s 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 Dak ota’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 SO 2 emission s and, to a lesser extent, NO

x 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 n atural 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 SO 2 Emissions in Order to Ensure Protection of the SO 2 Increments of the State’s Class I Areas

The SO 2 emission reductions that North Dakota has proposed as BART for the State ’s

BART

- eligible EGUs should greatly help the State address the SO 2 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 Are a 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 p rotocol 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 SO 2 emission reductions proposed to meet BART in its new periodic assessment of SO 2 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 E GUs 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 SO 2 BART limits are based on worst case sulfur cont ent 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 comp ly with EPA policies for increment consumption have shown that violations of the 3

- hour and 24

- hour average SO 2 increment are occurring in the State ’s Class I areas, it is imperative that North Dakota harmonize the SO 2 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 SO 2 increments. Thus, North Dakota must impose short term average SO 2 emission limits reflective

of the SO 2 contro ls 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 SO 2 Class I increments.

Such emission limits must be reflective of the capabilities of the SO 2 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 qua lity 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 S tate’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

s et limits consistent with the maximum degree of emission reductions that is achievable with the

BART SO 2 controls and that reflect operation of the SO 2 controls on a continuous basis. Without such short term average emission limits, NDDH cannot rely on th e planned SO 2

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 SO 2 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 o f 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 model ing techniques and approaches 50 , 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 SO 2 increments in the State ’s Class I areas, it is imperative that NDDH conduct a new assessment of

SO 2 increment consumption following EPA policy and consistent with the PSD mandates of the Clean Air Act. And, for NDDH to rely on the BART SO 2 reductions in such an analysis, t he

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 conditio ns 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 i s 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 calcu lations 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 EP A 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. Hesket t 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, S uite 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, Suit e 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

- 9288Page 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 5540 1

612

- 333

- 5424