100 First Street SW 

Cedar Rapids, Iowa 52404 

Tel. 319-362-2120 

Fax 866-484-2373 

info@plainsjustice.org 

http://www.plainsjustice.org 

July 30, 2008 

Terry O'Clair, Director 

Division of Air Quality 

North Dakota Department of Health 

918 East Divide Avenue, 2nd Floor 

Bismarck, ND 58501-1947 

RE: Comments on the Preliminary Best Available Control Technology 

Determination for Control of Nitrogen Oxides for M.R. Young Station Units 1 and 2 

Plains Justice and Sierra Club are submitting these comments. The North Dakota 

Department of Health (NDDH) proposes best available control technology (BACT) 

emission limits for nitrogen oxides (NOx) for the two units at the M.R. Young Station 

(MR Young). The BACT Determination made by NDDH does not follow the Top-Down 

BACT Analysis; selective catalyst reduction (SCR) was deemed “technically infeasible” 

by NDDH, and was not included in the full BACT Analysis. 

MR Young, located near Center, North Dakota is made up of two lignite-fired cyclone 

boilers, located adjacent to a lignite mine. This North Dakota lignite feeds the two 

boilers. BACT Determination, at 1. Unit 1 is owned by Minnkota Power Cooperative 

(Minnkota) and is 250 MW. Unit 2 is owned by Square Butte Electric Cooperative 

(Square Butte) and has a rating of 744 MW. Id. Minnkota operates both units. 

In April 2006, the United States and the State of North Dakota filed a complaint for 

injunctive relief and civil penalties pursuant to sections 113(b)(2) and 167 of the Clean 

Air Act (CAA), 42 U.S.C. §§ 7413(b)(2) and 7477. The Complaint alleged Minnkota 

and Square Butte violated the Prevention of Significant Deterioration provisions of CAA, 

as well as North Dakota’s State Implementation Plan by undertaking construction of a 

major emitting facility. Because of the complaint, the U.S. District Court of North 

Dakota ordered a Consent Decree for Civil Action No. 1:06-CV-034. The Consent 

Decree required Minnkota to install and operate control technology for the emission of 

NOx.

1

 The Decree sets out a two-step process for limiting NOx emissions. 

 

1

 The Consent Decree also requires the installation and operation of control technology for the emission of 

sulfur dioxide and particulate matter. 
Phase 1 requires both units to “install and commence continuous operation of Over-fire 

Air” or a technology equivalent that will achieve a NOx rate of no more than 0.36 

lb/MMBtu based on a 30-day rolling average. Consent Decree, at 19. Minnkota has until 

December 31, 2009 to install Over-fire Air to both units. Id. Phase 2 requires Minnkota 

and Square Butte to perform BACT analyses for their respective boilers. Id. The 

analyses must follow the BACT Top-Down approach that is laid out in the “New Source 

Review Workshop Manual—Prevention of Significant Deterioration and Nonattainment 

Area Permitting” (Draft October 1990) (NSR Manual), and must include any additional 

information requested by the Environmental Protection Agency (EPA) and NDDH. Id. 

Additionally, the BACT analyses must “include an evaluation of Selective Catalytic 

Reduction, Selective Non-Catalytic Reduction, Over-fire Air, and Rich Reagent 

Injection, as well as other NOx control technologies.” Id. Under Phase 2, NDDH must 

review the BACT analyses and make a BACT determination, which must include specific 

control technologies to be installed and a specific 30-day rolling average NOx emission 

limitation for each unit. Id. at 20. 

In accordance with the Consent Decree, Minnkota and Square Butte submitted BACT 

Analyses and NDDH made its draft BACT Determination. NDDH preliminarily 

determined the BACT limit for Unit 1 is 0.36 lb/MMBtu, except during startup or 

shutdown, when the limit shall not exceed 2070.2 lb/hr on a 24-hour rolling average 

basis. BACT Determination, at 69. For Unit 2, the proposed limit is 0.35 lb/MMBtu, 

with startup/shutdown period not to exceed 3995.6 lb/hr on a 24-hour basis. Id. The 

proposed control technology for both units is selective noncatalytic reduction (SNCR) 

operated in conjunction with advanced separated overfire air (ASOFA). Id.

 BACT determinations are required for Prevention of Significant Deterioration permits, 

and is defined as: 

An emission limitation (including a visible emission 

standard) based on the maximum degree of reduction for 

each pollutant subject to regulation under Act which would 

be emitted from any proposed major stationary source or 

major modification which the Administrator, on a case-bycase basis, taking into account energy, environmental, and 

economic impacts and other costs, determines is achievable 

for such source or modification through application of 

production processes or available methods, systems, and 

techniques, including fuel cleaning or treatment or 

innovative fuel combustion techniques for control of such 

pollutant. 

40 C.F.R. § 52.21(b)(12).2

 There is a five-step top-down procedure for determining 

BACT limits. The top-down approach requires all available control technologies to be 

ranked in descending order of control effectiveness. NSR Manual, at B.2. The most 

 

2

 North Dakota has adopted 40 C.F.R. § 52.21 by reference, with express exceptions not at issue here. N.D. 

Admin. Code 33-15-15-01.2 (2008). 
stringent technology is BACT, unless there is a showing that the technology is not 

achievable. Id. The five-steps are as follows: 

1. Identify all control technologies 

2. Eliminate technically infeasible options 

3. Rank remaining control technologies 

4. Evaluate most effective controls and document results 

5. Select BACT 

Id. at B.6. A technology is considered technically feasible if it has either been 

successfully installed and operated on the type of source that is under review, or is 

available and applicable to the permitted source. Id. at B.17. A pollution control is 

available if “it can be obtained by the applicant through commercial channels or is 

otherwise available within the common sense meaning of the term.” Id. A pollution 

control is applicable if it “can reasonably be installed and operated on the source type 

under consideration.” Id. The fact that the option has been permitted for a similar source 

means the option is presumptively applicable. If not permitted for a similar source, the 

control is still applicable if an “examination of the physical and chemical characteristics 

of the pollutant-bearing stream and comparison to the gas stream characteristics of the 

source types to which the application has been applied previously” shows the two gas 

streams to have “similar... characteristics.” Id. at 18. 

In other words, if the control option has already been applied in practice, it is feasible. 

Even if a technology has not been applied in practice, it is still feasible unless the 

permittee demonstrates that the control option is not commercially available and/or 

sufficient unusual circumstance exist with the application of the technology to the 

particular emission source, compared to other gas streams to which the technology has 

been applied previously. Id. at B.19. If the difficulties with the technology are a matter 

of cost, the technology is technically feasible, and must still be considered in the BACT 

analysis. Id. Therefore, if the pollution control option could be applied to the permitted 

source if modifications were made to the gas stream or source operations, the option is 

technically feasible and the additional costs and collateral impacts need to be assessed. 

The economic, energy and environmental impacts of a particular control technology are 

assessed under step 4 of the BACT analysis. 

I. NDDH consistently misapplies the “technically feasible” analysis set forth in 

the NSR Manual and thus, the review of the BACT Analysis is flawed. 

Of the 70 pages of discussion, NDDH has used 56 pages, 80% of the BACT 

Determination, to disqualify the use of SCR to the coal-fired units at MR Young. 

NDDH’s review of the BACT Analysis repeatedly cites but misapplies the NSR Manual 

in reference to the term “technically feasible.” 

The NSR Manual states that the technical infeasibility analysis is straightforward: 

• “If the control technology has been installed and operated successfully on the type 

of source under review, it is demonstrated and it is technically feasible.” 
• A technology that has not been installed and operated on the type of source being 

permitted is nevertheless technically feasible if it is available and applicable. 

• A technology is available if it can be obtained through commercial channels or is 

otherwise “available” within the common sense meaning of that term. 

• A technology is applicable if it has been permitted for a similar source or if it has 

been applied to a source that has an exhaust gas stream with similar relevant 

qualities to the permitted source’s. 

 

Id. at B.17-B.19. Nothing more is required under this step. Here, all applicable 

technologies are technically feasible and have been applied to a similar source. The type 

of source under review here is utility boiler. While the two units at MR Young are 

cyclone boilers, the overarching category involved is “utility boiler.” See e.g., 42 U.S.C. 

§ 7479(1); 40 C.F.R. § 52.21(b)(1)(i)(a) (defining “major stationary source” as “Fossil 

fuel-fired steam electric plants of more than 250 million British thermal units per hour 

heat input,” as a category); Requirements for Preparation, Adoption, and Submittal of 

Implementation Plans; Approval and Promulgation of Implementation Plans, 45 Fed. 

Reg. 52676, 52694-95 (Aug. 7, 1980) (stating that a “major emitting facility” is defined 

by its two digit classification code from the Standard Industrial Classification Manual); 

SIC Major Group 49: Electric Services (including all power plants in the same SIC 

category). Therefore, the BACT Analysis should begin with the presumption that SCR is 

a technically feasible technology, as it has been successfully installed and operated on 

utility boilers worldwide. 

NDDH consistently excuses the disqualification of SCR with assertions like “has not 

been demonstrated to be technically feasible for North Dakota lignite-fired cyclone 

boilers,” and “SCR is not technically feasible for North Dakota lignite-fired cyclone 

boilers.” BACT Determination, 5 and 4, respectively. NDDH incorrectly applies the 

NSR Manual and the applicable law by assuming that a pollution control technology 

must have been demonstrated in practice on an identical facility burning an identical fuel 

from the identical geographical region. Technological feasibility is not so narrow. First, 

similar sources are boilers with generally the same flue gas properties. See e.g., Revision 

of Standards of Performance for Nitrogen Oxide Emissions From New Fossil-Fuel Fired 

Steam Generating Units, 63 Fed. Reg. 49442 (September 16, 1998) (categorizing 

boilers by general, not specific categories); 70 Fed. Reg. 9706 (Feb. 28, 2005) 

(same). Second, the NSR Manual allows for technology transfers. This includes 

technologies that have not been demonstrated on full-scale similar sources, but are 

“commercially available” and technologies transferred from sources with similar, but not 

exact flue gas characteristics. NSR Manual, at B.17. The NSR Manual is very clear that, 

even if a technology has not been applied to a similar source before, an analysis must be 

conducted of the physical properties of the flue gas streams. Id. at B.19. 

Third, even if a physical or operational modification is required to overcome technical 

obstacles, those modifications do not “justif[y]... eliminating the control technique on the 
basis of technical infeasibility.” Id. at B.20. “The cost of such modification can be 

considered in estimating the cost and economic impacts which, in turn may form the 

basis for eliminating a control technology.” Id. A cost analysis is done in step 4 of the 

BACT Top-Down approach, not step 2. Id. at B.8. 

In short, the draft BACT Determination looks to be a justification for a pre-determined 

technology in an effort to favor a specific company or to give preferential treatment to 

facilities burning a dirty, low-quality in-state fuel (North Dakota lignite). As EPA states, 

“there are many tools in the toolbox” for reducing NOx emissions from coal-fired units. 

BACT Determination, at 6. Here, however, those tools were not used and, instead, 

NDDH seems to have invented new tools to avoid reducing NOx through the most 

effective method: application of an SCR, a technically feasible technology. 

II. NDDH and Minnkota have not adequately supported the decision to 

disregard fuel switching/blending as technically infeasible. 

NDDH offers three reasons why fuel switching/blending is technically infeasible: (1) the 

nearest rail line is 10 miles away; (2) the 2005 national average NOx emission rate is 0.83 

lb/106 Btu, higher than the emission rates for MR Young; and (3) switching to Powder 

River Basin (PRB) subbituminous coal would increase, not decrease NOx emissions. Id.

at 14. Each reason is erroneous, and/or irrelevant, as discussed below. 

A. Lack of railroad access to MR Young does not make fuel 

switching/blending technically infeasible. 

Lack of a direct railroad access is a technical difficulty, not a technical infeasibility. As 

the NSR Manual states: 

Where the resolution of technical difficulties is a matter of 

cost, the applicant should consider the technology as 

technically feasible. The economic feasibility of a control 

alternative is reviewed in the economic impacts portion of 

the BACT selection process. 

NSR Manual, at B.19. Here, additional transportation of a cleaner fuel for blending (if 

that were necessary to operate an SCR) should be addressed as a transportation cost 

(indirect capital cost) under a cost or economic impact analysis. For fuel 

switching/blending to be technically infeasible, pursuant to the NSR Manual, there must 

be a showing that the boilers at MR Young are physically incapable of burning a 

different type of fuel. A discussion of transportation costs does not support the disregard 

of fuel switching/blending in the BACT Determination. 

According to NDDH, the nearest rail line is 10 miles away from MR Young. BACT 

Determination, at 14. A review of the Department of Energy’s Energy Information 

Administration (EIA) website indicates that coal can be trucked from a rail line to a plant 
location; a rail line to the plant is not required.3

 In fact, the EIA website states that the 

average distance coal is trucked from a rail line is 17.35 miles, with the minimum

distance being 13.5 miles.4

 These distances are well below the 10 mile distance 

necessary to blend fuel at MR Young. “Multimode transportation” distances, i.e., truck 

and rail as would be the case with MR Young, have been as much as 1596 miles.5 As 

indicated in Table 1, below, there are mines of subbituminous coal in Montana as near as 

275 miles from Oliver County, North Dakota. 

County Distance from Oliver County, North 

Dakota (miles) 

McCone 275.24 

Powder River 355.16 

Garfield 320.73 

Musselshell 415.05 

Rosebud 438.16 

Big Horn 405.2 

Table 1. Distances (miles) from Oliver County, North Dakota to Montana County Mines of SubBituminous Coal 

The distances to available subbituminous coal, to the extent blending is necessary for 

operation of an SCR, is well below the maximum distance of 1596 miles provided by 

EIA for multimode transportation of coal in this region. In short, delivery of a cleaner 

fuel for blending is physically possible at the plant, even if by truck rather than rail. 

Therefore, fuel blending is a matter of cost and not technical feasibility. 

B. Using the average annual NOx emission rate is not acceptable for labeling 

fuel switching/blending as technically infeasible. 

NDDH reviewed EPA’s Acid Rain Database to determine the annual average NOx

emission rate. BACT Determination, at 14. This is an important step in establishing a 

BACT limit since the Acid Rain Database contains significant data showing the emission 

rates that other plants have achieved. However, NDDH looked at the wrong data and 

reached an unrepresentative conclusion. A review of average NOx emission rates during 

ozone season given by the EPA Acid Rain Database (see Appendix 2), more specifically 

referred to as the “Clean Air Markets Data and Maps,”6

 for all NOx trading programs 

reveals that the average 30-day NOx emission rate for coal-fired units is more closely 

approximated at 0.30 lb/MMBtu. Clean Air Markets Data and Maps. This average is far 

less then the current levels at which MR Young emits: Unit 1 at 0.849 lb/MMBtu and 

 

3

 Energy Information Administration, “Average Distance Shipped Per Ton for Utility Contract Coal by 

Supply Region and Transportation Mode, 1979, 1987, 199 and 1997 (Miles),” available at 

http://www.eia.doe.gov/cneaf/coal/ctrdb/tab48.html. Accessed on 07/23/08. 4 Id. 

5 Id. 

6

 Environmental Protection Agency, “U.S. EPA Clean Air Markets Data and Maps,” available at 

http://camddataandmaps.epa.gov/gdm/index.cfm?fuseaction=emissions.wizard. Accessed on 07/08/08. 
Unit 2 at 0.785 lb/MMBtu. BACT Determination, at 14. Furthermore, a review of the 

same Clean Air Markets data reveals that 98% of the units in the U.S. emit less NOx on a 

30-day rolling average then MR Young’s Unit 2. See Appendix 3 and 4. In other words, 

contrary to NDDH’s suggestion that the existing MR Young plant is controlled to the 

same degree as other existing plants, MR Young has much higher NOx emissions. 

C. The combustion of PRB coal would result in lower NOx emissions. 

The Clean Air Act and applicable regulations require 

consideration of cleaner fuels in a top-down BACT 

analysis. 42 U.S.C. § 7479 (defining BACT as “an 

emission limitation based on the maximum degree of 

reduction of each pollutant... which the permitting 

authority, on a case-by-case basis... determines is 

achievable for such facility through... techniques, 

including ... clean fuels...”). The phrase ‘clean fuels’ was 

added to the definition of BACT in the 1990 Clean Air Act 

amendments. EPA described the amendment to add ‘clean 

fuels’ to the definition of BACT at the time the Act passed, 

‘as * * * codifying its present practice, which holds that 

clean fuels are an available means of reducing emissions to 

be considered along with other approaches to identifying 

BACT level controls.’ EPA policy with regard to BACT 

has for a long time required that the permit writer examine 

the inherent cleanliness of the fuel.

In re Inter-Power of New York, 5 E.A.D. 130, 134 (EAB 1994)(emphasis added, internal 

citations omitted); In re Old Dominion Electric Cooperative, 3 E.A.D. 779, 794 n.39 

(EAB 1992) (“BACT analysis should include consideration of cleaner forms of the fuel 

proposed by the source.”); In re Hibbing Taconite Co., 2 E.A.D. 838, 842-43, PSD 

Appeal No. 87-3, Slip Op. 8-10 (EAB 1989)(remanding a permit because the permitting 

agency failed to consider burning natural gas as a viable pollution control strategy). 

However, NDDH rejects a switch to PRB coal, even though it is technically feasible, 

because NDDH believes that such a switch would have little effect on NOx emissions. 

BACT Determination at 14. This is erroneous. Switching or even blending 

subbituminous coal with North Dakota lignite would result in a decrease of NOx

emissions by increasing the overall efficiency of the boilers and by enabling the direct 

use of SCR. Either one, alone, can justify the switch. Together, the increased efficiency 

and ability to use SCR would vastly reduce the NOx emissions. 

Uncontrolled NOx emissions are a function of both combustion temperature and the 

quantity of fuel (coal) available to release fuel-bond nitrogen. Emission factors for NOx

emissions are often expressed on a pound-per-ton-of-coal-burned basis. As a result, total 

emissions are directly related to both the emission factor and the total amount of fuel 

burned. While it is true that there is a slight increase (a factor of 1.13) in the pounds of 

uncontrolled NOx from subbituminous coals per ton of coal burned (17 pounds of NOx
per ton coal consumed as opposed to 15 lb/ton from lignite), subbituminous coal contains 

more heat content and, therefore, less coal is required for the same energy production. 

North Dakota lignite has a low heat content compared to other coals. The average heat 

content of the coal used at MR Young is reported to be approximately 6647 Btu/lb 

(average from U.S. Geological Survey is approximately 6265 Btu/lb), whereas the 

average heat content of Montana subbituminous coals are approximately 8124 Btu/lb 

with maximum heats of combustions reported at as much as 10, 898 Btu/lb. At the rated 

heat inputs of the two units at MR Young, the use of Montana PRB coal translates into an 

average reduction of as much as 1,083,956 tons of coal. 

When higher-heat-content subbituminous coal is substituted for low-quality, low-heatcontent North Dakota lignite, the fuel usage decreases by factor of 1.22. Therefore, the 

benefit of usage reduction (1.22) outweighs any increase in nitrogen content found in 

subbituminous coals versus lignite coals (1.13). As a result, total uncontrolled emissions 

of NOx are reduced, notwithstanding an increase in emissions per ton of coal. 

Furthermore, to the extent NDDH contends that SCR cannot be used on lignite (a 

contention that is incorrect, as set forth below), a switch to PRB/subbituminous coal 

allows significant emission reductions over the baseline, uncontrolled, rates. Even at a 

worst-case NOx removal efficiency of only 75 % using SCR, the reduction in NOx

emissions associated with using the combination of fuel switching/blending with SCR 

increases by a factor of 1.83. Since typical SCR performance is over 90%, the NOx

emission reduction is much higher. Therefore, a switch to subbituminous coal (or even 

blending subbituminous coal with lignite) results in a significant NOx reduction that far 

exceeds any slight increase in the fuel NOx concentration of PRB coal. 

III. The BACT Determination does not adhere to the guidelines set forth in the 

Consent Decree 

In its BACT Determination, NDDH interprets and applies a Seventh Circuit opinion as a 

reason for not considering fuel switching/blending as technically feasible options for MR 

Young. BACT Determination, at 15. In Sierra Club v. EPA, 449 F.3d 653 (7th Cir. 2007) 

(hereinafter the Prairie State case), it was determined that the mine mouth power plant 

did not have to consider low sulfur subbituminous coal as part of its BACT analysis. 

This case leads NDDH to conclude, 

Fuel switching is not required for a mine mouth power 

plant such as M.R. Young Station. Therefore, Minnkota is 

not required to consider switching coal or bringing in other 

types of coal for blending to address the characteristics of 

Center lignite that would affect any of the control 

technologies. 
BACT Determination, at 15. However, the Consent Decree explicitly addresses the 

parameters that must be followed when developing the BACT Analyses and the BACT 

Determination. Nothing within the Consent Decree permits the use of court rulings made 

subsequent to the entered Decree. Additionally, the Prairie State case pertained to a 

proposed coal-fired plant seeking a Prevention of Significant Deterioration permit. It is 

inappropriate to apply this decision to retroactive reviews necessitated by violations of 

the CAA, due to constructions or modification made to an existing power plant. 

Additionally, NDDH reads too much into the Prairie State decision and ignores the 

Seventh Circuit’s warning not to apply its holding to excuse facilities from the clear 

statutory mandate to consider clean fuels. In that case, the court held that the proposed 

plant would be forced to undergo significant modifications to its fundamental design to 

burn alternative fuels. Sierra Club v. E.P.A., 499 F.3d 653, 655 (7th Cir. 2007). It is 

apparent from the Prairie State case, that the exception to clean fuels, base on the 

“redefining” policy, is narrow. In Prairie State, the state agency considered pollution 

control options that would have required fundamental changed in design from a 

traditional coal power plant to a gasification and combined cycle plant. The 

Environmental Appeals Board noted that the fact that the state agency looked beyond the 

applicant’s preferences to other types of power plants indicates that the “redefining the 

source” policy is not so narrow as to cut off consideration of pollution control options 

that would necessitate significant changes from the applicant’s preferred strategy. The 

Prairie State case was therefore a narrow exception, based entirely on the unchallenged 

“fact” assumed by the Environmental Appeals Board and the Seventh Circuit, that the 

plant in that case was a specific “type”: a mine-mouth plant intended to burn a specified 

coal deposit. Here, while MR Young is a mine-mouth plant, it is not “designed” in such a 

way that prohibits combustion of cleaner fuels. In other words, it is not unchallenged 

here, as it was in Prairie State, that the plant’s “type” is a mine-mouth plant. Rather, the 

plant type is a solid-fuel cyclone boiler. 

Further, to the extent that considering cleaner, subbituminous, fuel would require an 

alternative technology, Plains Justice and Sierra Club hereby formally request that 

NDDH consider that alternative in accordance with 42 U.S.C. § 7475(a)(2). 

Additionally, by virtue of this comment Plains Justice and Sierra Club hereby requests 

that during its 45-day review period, EPA also consider fuel switching/blending and the 

combination of such with SCR as a technically feasible control technology in accordance 

with 42 U.S.C. § 7475(a)(2). 

IV. Other reviewing authorities, including EPA and the Texas Commission on 

Environmental Quality, have found SCR to be technically feasible for 

lignite. 

For years, organizations and stakeholders, including the Lignite Energy Council and the 

East Texas Electric Generating Facilities, have asserted that SCR is technically 

infeasible. Arguments against the use of SCR as a technically feasible control option on 

lignite-fired boilers have included the following: 
• The cost of installing SCR and converting from lignite to another fuel source 

would be excessive 

• The use of SCR would cause large price increases for electricity 

• The lignite mining industry would be destroyed7

In the case of MR Young, NDDH and Minnkota have cited the following reasons for the 

technical infeasibility of SCR: 

• “SCR has not been demonstrated to be technically feasible for North Dakota 

lignite-fired cyclone boilers (i.e., SCR hasn’t been applied to this source type).” 

BACT Determination, at 5. 

• “[The] difference in the flue gas characteristics will preclude the successful 

application of SCR technology to the M.R. Young Station.” Id. at 51. 

• SCR in the presence of lignite combustion is prone to decreased catalyst life and 

increased catalyst replacement, and while the specified emission reduction can be 

achieved, SCR is still technically infeasible due to the more frequent replacement 

of the catalyst as compared to the combustion of other fuels. Id. at 50; 55-57. 

• Lack of pilot testing of SCR on a plant firing North Dakota lignite. Id. at 53. 

• No vendor guarantee on SCR performance with North Dakota lignite. Id. at 54. 

These off-the-shelf excuses for favoring low-quality lignite fuel are mistaken and largely 

irrelevant. SCR is a technically feasible option for lignite-fired boilers. In the final rule 

amendments to New Source Performance Standards for steam generating units, EPA 

responded to comments raised regarding SCR feasibility for lignite-fired units by stating 

that: “[t]here is considerable experience in the industry to show that use of SCR on lignite 

is technically feasible.”8

 For example, SCR use has been achieved in full scale in Europe 

and Japan and has been permitted (i.e. “commercially available”) in Texas. 

Moreover, the NSR Manual requires the applicant to “survey the range of potentially 

available control options.” NSR Manual, at B.11. This includes “technologies in 

application outside the United States to the extent that the technologies have been 

successfully demonstrated in practice on full scale operations.” Id. This also includes 

technologies that have been permitted for full-scale operations, even if not yet operating. 

Id. Therefore, a determination of technical feasibility or infeasibility should include 

control technologies that have been demonstrated abroad and those that have been 

permitted in the United States or abroad. 

Furthermore, the Texas Commission on Environmental Quality found SCR to be 

technically feasible for the control of NOx from lignite combustion. Unit 3 of the Sempra 

Generation, Twin Oaks Power Plant, burns lignite from the Walnut Creek Mining 

 

7

 East Texas Electric Generating Facilities Stakeholder Meeting Summary, available at 

http://www.tceq.state.tx.us/assets/public/implementation/air/sip/miscdocs/ETXEGFstakeholders/20051118-

stakeholder_mtg_summary.pdf, pp.2. Accessed on 07/07/2008 

8

 U.S. EPA, “Final Rule Amendments,” Docket ID. No. EPA-HQ-OAR-2005-0031: FR-RIN 2060-AM80, 

6560-50-P. 
Company, located between Calvert and Bremond near the Tidwell Prairie Community.9

 

Statistical analysis of U.S. Geological Survey data10 on the coal from the Calvert Bluff 

mine shows that the coal has an average calcium oxide percentage of 15%. This calcium 

oxide percentage is 2% higher than the calcium percentages for historic Center lignite 

provided in the BACT Determination to support the claim of technical infeasibility of 

SCR. BACT Determination, at 21. With a similar (or less favorable) calcium percentage 

in its lignite, the Twin Oaks Power Plant has addressed the erosion, plugging, and 

deactivation concerns expressed by Minnkota and NDDH. Thus, the permitting of SCR 

at Twin Oaks presumptively establishes SCR as a technically feasible control on lignite 

plants. Moreover, Twin Oaks has been able to achieve NOx emission rates of 0.158 and 

0.156 lb/MMBtu in practice, much lower then the BACT emission rates proposed by 

NDDH. 

As noted above, a demonstration of technical feasibility does not require that SCR be 

demonstrated in full scale on coal from a specific state and specific mine. For BACT 

top-down analysis, it is enough that SCR is commercially available (i.e. permitted) for 

lignite combustion in cyclone boilers, regardless of the origin of the lignite. This “if no 

one else does it, I don’t have to do it” approach is contrary to the NSR Manual and to the 

Congressional purpose to drive pollution control advances through BACT emission 

limits. 

Moreover, EPA has stated that Minnkota has not provided enough information to show 

SCR to be technically infeasible for MR Young: 

Minnkota has not provided information that ‘shows that . . . 

[deposition] and deactivation of the SCR catalyst is an 

unresolvable technical barrier and/or the ability of an SCR 

to control NOx would be so limited that SCR would be an 

ineffective control option.’ 

BACT Determination, at 48. 

To the extent that Minnkota and NDDH have concerns regarding the potential need to 

replace the SCR catalyst frequently at MR Young, such concerns must be analyzed in the 

fourth step of the BACT analysis with cost/economic impacts. NSR Manual, at B.31. In 

other words, frequent catalyst replacement is a cost of making the SCR technology 

feasible—not an indication that it is infeasible. EPA agrees with this assessment: “There 

are engineering challenges with operating an SCR system at [MR Young], . . . these 

would largely be a matter of cost and should be examined under step 4 of the Top-Down 

BACT analysis.” BACT Determination, at 49. “SCR maintenance and downtime do not 

‘render the technology technically infeasible.’” Id. 

 

9

 Energy Information Administration, “Table 24. Origin of Coal Received By Electric Utility and Plant 

(2000)”, available at http://www.eia.doe.gov/electricity/cq/t24p26.html. Accessed on 07/23/2008. 10 U.S. Geological Survey, “US COALQUAL Database,” available at 

http://energy.er.usgs.gov/products/databases/CoalQual/index.htm. Accessed 07/08/08. 
V. NDDH and Minnkota have not considered engineering solutions that would 

facilitate the use of SCR, rendering the BACT top-down analysis incomplete. 

The problems associated with SCR use, according to NDDH, include the gas stream 

qualities that result in “unique catalyst deposition, erosion, poisoning, blinding (or 

fouling or surface masking) and plugging.” Id. at 5. NDDH asserts that these problems 

“are irresolvable barriers in the ability of known SCR technologies to control NOx stack 

emissions.” Id. NDDH goes on to say that “there is no known in-reactor engineering 

solution to: (a) reduce deactivation rates caused by heterogeneous reaction that form the 

particles that cause pore blinding and plugging. . . .” Id. at 46. The excuses provided by 

Minnkota and acquiesced by NDDH include: 

1. High carryover of fly ash containing alkaline metals such as sodium, calcium, and 

potassium 

2. High exhaust temperature 

3. High moisture content of the lignite 

4. Deactivation of the catalysts 

5. Frequent catalyst replacement 

Id. at 43. 

A few commercially available solutions to facilitate the use of SCR are set forth below. 

These options were not considered by NDDH in its BACT Determination but are 

available, applicable, and must be considered in a top-down analysis. 

1. Fuel blending/switching in conjunction with SCR, as discussed above. 

2. Injection of a fluxing agent to increase melting of the solid combustion byproducts, creating less fly ash to be portioned and re-injected into the exhaust gas 

to poison the catalysts. Culligan, et al, 2005. 

3. Sootblowing and screens to minimize fly ash and prevent plugging of catalysts. 

Blankenship. 

4. Catalyst improvement by surface and edge coating to minimize deactivation from 

alkaline metals, silicates, and sulfates has been shown to maintain. Hitachi Zosen 

Engineering. Catalyst coatings have successfully maintained 80% catalytic 

activity in similar process for 2 years (>15,000 hours) in Japan and Pensacola, 

Florida. This catalyst replacement frequency is within the range cited by NDDH 

on page 32 of the BACT Determination as indicative of normal operation. 

5. Conventional Coal Cleaning – Wet process to remove ash, sulfur, moisture, and 

mercury. 

6. Coal Cleaning with Drying – Testing using dry cleaning with the Allair Jig 

Process followed by coal drying was completed in 2006. The results submitted to 

the North Dakota Industrial Commission indicate that “Coal cleaning in 

combination with low cost drying will produce a product that is comparable to 
Powder River Basin subbituminous coal,” “resulting in a lignite yielding 8900 

BTU” thereby decreasing coal usage and NOx emissions.11 Also, K Fuel® and K 

Direct® remove moisture (and mercury) thereby “upgrading lignite to 

performance levels approaching that of bituminous coal” by increasing heat 

content by as much as 52% and decreasing NOx emissions.12 K Fuel® and K 

Direct® are being applied commercially in Ohio and Indiana and tested at a 

Wyoming utility. 

7. Coal Beneficiation – Consists of sizing, handling, and washing. Removes 

moisture, mercury, and sulfur. Full-scale demonstrations using power plant waste 

heat expected in 2008 at Great River Energy’s Coal Creek Station.13 

VI. NDDH has not reviewed add-on controls nor combinations of controls that 

may overcome the challenges associated using SCR and have proved more 

efficient reduction of NOx than SNCR. 

The BACT Determination does not address the following technologies or combinations 

of technologies for the control of NOx emissions: 

1. Deep staging-Rich Reagent Injection-SNCR System or Advanced Layered 

Technology Approach (ALTA) 

a. 4-week full-scale test by Reaction Engineering, Inc. and Fuel Tech funded 

by the Department of Energy using Illinois #6 and PRB coals established 

NOx emission rates below 0.15 lb/MMBtu (60/40 Blend), 0.165 

lb/MMBtu (100% Illinois #6, a high sulfur coal). 

b. The test conducted at the AmerenUE Sioux Plant, Unit #1 near St. Louis, 

MO. The unit is a 540 MW cyclone boiler—the same type of source as 

MR Young 

c. Other test have been conducted by members of a consortium of power 

plants called the Cyclone NOx Control Interest Group (CNCIG) and have 

resulted in several design and operational changes to existing cyclone 

boilers.14

2. Deep staging-Overfire Air (OFA)-Continuous Corrosion Monitoring, Combustion 

Control-Oxygen Injection 

 

11 Dr. Richard Weisnstein, Falkirk Mining Company, “Lignite Fuel Enhancement: Dry Process Coal 

Cleaning,” available at http://www.nd.gov/ndic/lrc/lrcinfo/fy05-li-132.pdf. Accessed 07/27/08. 12 Evergreen Energy Inc., available at http://www.evgenergy.com/documents/Release-Indonesia-EvergreenFINAL.shtml, accessed on 07/23/08. 

13 “One Year of Operating Experience With a Prototype Fluidized Bed Coal Dryer at Coal Creek 

Generating Station,” available at http://www.netl.doe.gov/technologies/coalpower/cctc/ccpi/pubs/GRE/ 

GRE%20Clean%20Coal%20Conf%20Sardinia%20Paper%20May%202007_1.pdf. Accessed 07/07/2008. 

14 Bradley R. Adams, John Boyle, Andrew P. Chiodo, Marc A Cremer, “Demonstration of NOx Emissions 

Below 0.15 in a Cyclone Boiler Using In-furnace NOx Controls,” available at 

http://www.ftek.com/pdfs/TPP-574.pdf. Accessed 07/26/08. 
a. The layered process includes three zones: main combustion, reburn, and 

burnout. Developed by Babcock & Wilcox.15 

3. Gas Reburning with Low NOx Burners 

Tests conducted by Babcock & Wilcox on a 110 MW cyclone boiler at Wisconsin Power 

and Light’s Nelson Dewey Plant, Cassville, WI saw a 50% reduction in NOx emissions.16 

4. Amine-Enhanced Gas Injection (AEGI) 

a. Demonstrated in practice at the Public Service Electric and Gas 

Company’s Mercer Station, Lamberton Road, Trenton, New Jersey as an 

upgrade to SNCR.17

b. Minnkota’s BACT Analysis indicates that “to the Department’s 

knowledge” only one permanent application of conventional gas reburn or 

FLGR and SNCR are known. BACT Determination, at 59-60. To be 

“technically feasible,” a technology does not have to be used for long 

periods. Rather, it just has to have been demonstrated in practice—which 

AEGI has undeniably been. NDDH improperly attempts to further 

eliminate this technology by suggesting that based on size, fuel type, and 

firing configuration the technology is not demonstrated in practice on units 

like those at MR Young, and is therefore not technically feasible. This is 

insufficient unless NDDH undertakes a technical analysis and comparison 

between the gas streams from MR Young and the plants where the 

technology has been demonstrated and determines that sufficient 

differences regarding relevant gas properties prevent the technology’s 

feasibility. This was not done. 

5. Flue Gas Recirculation (FGR) 

a. While FGR may be associated with operating and maintenance concerns 

such as dust build up and erosion, it reduces NOx by reducing thermal NOx

generation.18 

 

15 Bruce W. Lani, Thomas J. Feeley, III, Charles E. Miller, Barbara A. Carney and James T. Murphy, 

“DOE/NETL’s Advanced NOx Emissions Control Technology R&D Program,” available at 

http://pepei.pennnet.com/display_article/278447/6/ARTCL/none/none/DOE/NETL%E2%80%99sAdvanced-NOx-Emissions-Control-Technology-R&D-Program/. Accessed 06/24/08. 16“Clean Coal Technology: Reburning Technologies for the Control of Nitrogen Oxides Emissions from 

Coal-fired Boilers,” available at: http://www.osti.gov/energycitations/ 

product.biblio.jsp?osti_id=679921. Accessed on 06/24/08. 

17 Alexander S. Daindoff, Andres F. Gomez, John O’Leary and Robert A. Schreckengost, “First 

Commercial Installation of Amine Enhanced Gas Reburn On Units 1 and 2 at Public Service Electric and 

Gas Mercer Station.” 

18 Black and Veatch, “Best Available Retrofit Technology Engineering Analysis: Revision 3: Project 

145983 and File Number 40.0000” pages 3-7 and 3-6, Submitted on Behalf of Arizona Public Service 

Company Four Corners Generating Units 1-5, December 04, 2007. 
b. NDDH’s assertion that FGR is “not expected to reduce NOx” is inaccurate. 

See BACT Determination, at 62. 

c. Numerous prior case-by-case determinations for control and retrofit 

control analyses have addressed FGR as a control technology for NOx. 

This technology should not be eliminated without a cost, energy, or 

environmental impact analysis. 

6. Hybrid Selective Reduction 

a. Can achieve an overall efficiency of up to 65% or more. This control 

option favors applications where temperatures are too low for optimum 

reduction using SNCR alone, but provides superior control while 

decreasing ammonia slip and the required catalyst size for SCR. These 

benefits make this option a more economical choice from a catalyst 

replacement cost standpoint.19

7. OxyFuel® or Oxygen Enhanced Combustion, developed y Praxair, Inc.20 

a. Reduces NOx by eliminating the use of air, which contains nitrogen, using 

pure oxygen as the combustion gas. 

b. Reached commercial licensing stage; is offered by the Northeast 

Generation Services Company (i.e., “available”) 

c. Demonstrated at the City Utilities of Springfield’s Saint James River 

Station Unit #3 (i.e., “applicable”) 

d. A similar technology has been demonstrated and permitted in the 

metallurgical industry for several years. 

8. The Activated Coke Process 

a. Simultaneously removes NOx, sulfur dioxide, and mercury. 

b. Commercially available in Europe and Japan. 

9. Chemical Oxidation/Chemical Reduction 

Tri-Mer’s TriNOx® or BOC Gases LoTOxTM systems are resistant to catalyst plugging, 

can handle varying NO/NO2 ratios, with efficiencies, according to TriMer, as high as 

99.95%21

 

19 V. Albanese, J. Boyle, W. Sun, and R. Abrams, “Hybridization of Urea –SNCR with SCR: A Fit for the 

Future.” Presented at the ICAC’s Clean Air Clean Air Technologies & Strategies Conference,” March 7-

10, 2005 Baltimore, Maryland, available at http://www.ftek.com/pdfs/TPP-566.pdf. Accessed 07/26/08. 20 “Carbon Sequestration: Capture Project Descriptions,” available at http://www.netl. 

doe.gov/technologies/carbon_seq/core_rd/capture/41147.html. Accessed 07/24.2008. See also Black and 

Veatch, supra note 13. 
10. Mitsui Babcock (now Doosan Babcock Energy) NOxStarTM

a. Can reduce NOx by 70%. 

b. Installed at Tennessee Valley Authority’s Colbert 4 Plant.22

11. Mitsui Babcock Combined Non-catalytic NOx Reduction System23 

a. Consists of SNCR - Low NOx Burners - Deep Furnace Staging -Boosted 

OFA-Coal and Gas Reburn 

b. Capable of producing a 70% reduction 

12. RJM Layered System24

a. Burner modifications such as: 

 (l) Balancing the secondary air between the burners through air 

distribution analysis 

(2) Utilizing NOx tempering or injection of micronized water 

droplets into high-NOx production zones in the near-burner 

region to reduce NOx incrementally by as much as 30% 

(3) Amine reagent injection in the primary combustion zone, using 

combustion turbulence for complete dispersion of the reagent 

and targeting specific zones where optimum chemical 

b. Can achieve up to 70% NOx reduction 

c. Demonstrated at Connectiv’s B.L. England Station in New Jersey 

In addition to controlling NOx, many of these system are reported to control sulfur 

dioxide and mercury as well. These collateral control benefits should be considered in 

any future cost, energy, or environmental impact analysis of these additional 

technologies. 

VII. The startup and shutdown (SU/SD) periods at Minnkota are excessive and 

do not reflect the reported plant design at Minnkota. 

 21 Tri-Mer® Corporation. “Scrubber FAQ,” available at http://www.trimer.com/q&a/scrubbers.htm. 

Accessed on 06/24/08. See also Black and Veatch, supra note 13. 22 “NOxStarTM Plant Demonstration,” available at 

http://www.netl.doe.gov/publications/proceedings/03/scr-sncr/Final_Morris.pdf. Accessed on 07/08/08. 23 “NOx – Emissions and Controls,” available at http://www.ieacoal.org.uk/catalogues/coalonline/ 

81423/6029/html/6029_219.html. Accessed on 07/08/08. 

24 Id. See also Power Engineering International, “Layer Upon Layer,” March 2002; RJM, “RJM Adds New 

Technology Layer to Existing System Achieving a 90% NOx Reduction,” available at 

http://www.rjm.com/pdf/New_Layer.pdf. Accessed on 07/08/08. 
The startup period for MR Young, according to Minnkota, is 2.5 days for Unit 1 and 4.8 

days for Unit 2. BACT Determination, at 68. This time is excessive, as according to 

Power Engineering Magazine, Minnkota has invested in process control technology to 

reduce this time. The Emerson SmartProcess® Unit Response Optimization technology, 

installed on Unit 1 in Fall 2007, aids in quicker stabilization after demand changes to the 

system.25 It is reported that the SmartProcess® reduced the historical time to reach 

stabilization on Unit 1 by 70%. 

The BACT Determination makes no mention of this control system. NDDH should 

require that this technology be installed on both units as a monitoring system pursuant to 

BACT and should establish SU/SD definitions either based on duration of SU/SD or 

output level to avoid excessive or lengthy startup and shutdown periods from these units. 

Such definitions are considered work practice standards under the NSR Manual. 

VIII. The exclusion of SU/SD from the “30-day rolling average” and 

establishment of a separate SU/SD limit violates the Consent Decree. 

The Consent Decree requires NDDH to establish a “30-day rolling average emission rate” 

for the emission of NOx. The Consent Decree states, “Each 30-day Rolling Average 

Emission Rate shall include all start-up, shutdown and Malfunction periods within each 

Operating Day.” Consent Decree, at 4 (emphasis added). See also, “A new 30-day 

Rolling Average Removal Efficiency shall be calculated for each new Operating Day, 

and shall include all start-up, shutdown and Malfunction periods with each Operating 

Day.” Id. at 5 (emphasis added). 

Minnkota suggested BACT limits of 0.041 lb/MMBtu for Unit 1 and 0.102 lb/MMBtu for 

Unit 2 based on 30-day rolling average, adjusting for startup. BACT Determination, at 

68. However, NDDH “believes the adjustment of a 30-day rolling average emission rate 

for each boiler startup is not appropriate.” Id. NDDH continues, stating that a 24-hour 

emission limit is “more appropriate and easier to enforce,” instead setting limits of 

2070.2 lb/hr for Unit 1 and 3995.6 lb/hr for Unit 2 for SU/SD. Id. However, as noted 

above, the Consent Decree requires the 30-day rolling average emission rate to include 

SU/SD. Therefore, the BACT limits of 0.36 lb/MMBtu and 0.35 lb/MMBtu are not in 

accordance with the Consent Decree. 

If NDDH seeks to use its enforcement discretion during periods of SU/SD in regards to 

the “30-day rolling average” and the “30-day rolling average control efficiency” referred 

to in the Decree, this can be accomplished through simple recording of the beginning and 

ending of an SU/SD event and the proposed 24-hour NOx limit. However, explicit 

exclusion of such events from the 30-day BACT limit violates the Consent Decree. 

 

25 Emerson Process Management. “Emerson’s SmartProcess® Unit Response Optimization Technology 

Helps Young Unit 1 Improve Ram Rate by 70%,” available at: http://www.emersonprocesspowerwater.com/news/pr/Minnkota_URO.htm. Accessed on 07/08/08. 
IX. The control efficiency proposed by NDDH and Minnkota does not represent 

BACT. 

NDDH is only requiring 41% removal efficiency from SNCR with ASOFA and implies 

that this is due to expected variation in temperature, namely low temperatures during 

SU/SD. Id. at 67. However, NDDH admits that SNCR can achieve efficiencies as high 

as 95% as a function of temperature. Id. Moreover, NDDH exempts SU/SD—to the 

excuse of low temperatures at those times is clearly an excuse for poor pollution control 

with no reasonable basis. 

Notably, the excuses for poor pollution control are not consistent. While NDDH argues 

that low temperatures prohibit maximum efficiency from SNCR, NDDH also argues 

against the use of a SCR system because temperatures of the two units have, at times, 

exceeded 800oF. Id. at 34-35. The optimum temperatures for SCR range from 480oF to 

800oF. Id. at 35. NDDH then argues that optimum efficiencies of SNCR cannot be 

achieved because the flue gas temperature is below 1200oF. Id. at 67. NDDH needs to 

be clear about what temperature it expects the flue gas to be, and its basis for that 

expectation. Without this, it appears that NDDH’s draft findings are simply tailored to fit 

the excuse needed by Minnkota. 

NDDH also does not mention or consider the use of the Emerson SmartProcess® to 

stabilize operating parameters as a possible remedy to unstable temperature and low 

efficiencies expected for SNCR. Nor did NDDH review heating the flue gas stream as a 

means to improve SNCR control efficiencies. Generally, heating the flue gas stream is 

reviewed as part of the economic, environmental, and energy impact assessment under 

step 4 of the Top-Down BACT Analysis. 

Furthermore, NDDH does not consider engineering solutions that would enable higher 

efficiencies associated with the use of a SCR system. Nor does NDDH consider 

combinations of technologies that would improve the overall efficiency associated with 

SNCR. NDDH should review the SmartProcess®, flue gas heating, and the technologies 

identified in Comment VI to improve the proposed BACT efficiency. 

X. The proposed NOx emission limit associated with the proposed BACT is not 

consistent with other emission rates achieved across the United States. 

The emission limits resulting from the selection of SNCR with ASOFA as “best 

achievable control technology” far exceeds the BACT limits for and operation of similar 

sources across the country. A review of the “Clean Air Markets Database” indicates that 

The Red Hills Power Project owned by Tractebel Power Inc. Choctaw Generation in 

Choctaw, Mississippi, a Mississippi lignite-fired facility, is achieving 0.13 lb/MMBtu on 

a 30-day rolling average during ozone season. The Stanton Station Units 1 and 10 in 

North Dakota, both North Dakota lignite-fired, can achieve an average NOx concentration 

of 0.23 and 0.28, respectively. See Clean Air Markets Database. In fact, at the BACT 

emission limits proposed by Minnkota and accepted by NDDH, 65% of the coal-fired 

units in the U.S. achieve lower NOx emissions. See Figures 3 and 4 of the Appendix. An 
emission rate being met at another plant is presumptive proof that the emission rate is 

achievable as BACT at the permittee source. BACT Determination, at B.24. Thus, here, 

even if the less-effective SNCR and ASOFA are the basis for BACT, the BACT limit 

must be much lower. 

Furthermore, NDDH and Minnkota should investigate other technologies and work 

practices, including those listed in Comments VI, VII, and VIII that would achieve NOx

emission limits closer to those achieved by other coal and lignite-fired units. 

CONCLUSION 

For the foregoing reasons, Plains Justice respectfully requests that the Preliminary Best 

Available Control Technology Determination for Control of Nitrogen Oxides for M.R. 

Young Station Units 1 and 2 be withdrawn and remanded to Minnkota and Square Butte 

for further analysis under the BACT Top-Down approach. 

Dated this 30th day of July 2008. 

Respectfully Submitted 

On Behalf of Plains Justice and Sierra Club, 

Nicole Shalla