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 Be st Available Control Technology Determination for Control of Nitrogen Oxid es 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 be st available control technology (BACT) emission limits for nitrogen oxides (NO x ) 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 owne d 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 St ate of North Dakota filed a complaint for injunctive relief and civil pena lties 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 Deteriorati on provisions of CAA, as well as North Dakota’s State Implementa tion 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 Civ il Action No. 1:06-CV-034. The Consent Decree required Minnkota to install and operate control technology for the emission of NO x . 1 The Decree sets out a tw o-step process for limiting NO x 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 NO x 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 perf orm BACT analyses for th eir respective boilers. Id . The analyses must follow the BACT Top-Down appr oach that is laid out in the “New Source Review Workshop Manual—Prevention of Si gnificant 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 evalua tion of Selective Catalytic Reduction, Selective Non-Catalytic Reducti on, Over-fire Air, and Rich Reagent Injection, as well as other NO x 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 a nd a specific 30-day rolling average NO x emission limitation for each unit. Id. at 20.

In accordance with the Consent Decree, Mi nnkota 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 Prev ention 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 re gulation 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 cost s, determines is achievable for such source or modification through application of production processes or availa ble methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion tec hniques 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 require s 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 th e 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 c ontrols and document results 5. Select BACT

Id. at B.6. A technology is considered tech nically feasible if it has either been successfully installed and operated on the type of sour ce 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 obta ined by the applicant through co mmercial channels or is otherwise available within the comm on 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 appli cable if an “examinati on of the physical and chemical characteristics of the pollutant-bearing stream and comparis on to the gas stream characteristics of the source types to which the application has b een 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 b een applied in prac tice, it is still f easible unless the permittee demonstrates that the control opti on is not commercially available and/or sufficient unusual circumstance exist with the application of the technology to the particular emission source, compared to ot her 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 techni cally feasible, and must still be considered in the BACT analysis. Id. Therefore, if the pollu tion control option could be applied to the permitted source if modifications were made to the ga s stream or source operations, the option is technically feasible and the additional costs and collateral impacts ne ed to be assessed. The economic, energy and environmental impact s of a particular control technology are assessed under step 4 of the BACT analysis.

I. NDDH consistently misapplies the “tec hnically 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 SC R 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 inf easibility analysis is straightforward:

• “If the control technology has been instal led and operated successfully on the type of source under review, it is demonstrat ed 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 obt ained through commercial channels or is otherwise “available” within the co mmon 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 e xhaust gas stream with similar relevant qualities to the permitted source’s.

Id. at B.17-B.19. Nothing more is required under this step. He re, all applicable technologies are technically feas ible and have been applied to a similar source. The type of source under review here is utility boile r. While the two units at MR Young are cyclone boilers, the over arching category involved is “utility boiler.” See e.g. , 42 U.S.C. § 7479(1); 40 C.F.R. § 52.21(b)(1)(i)(a) (defin ing “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 Pr omulgation 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 th e Standard Industrial Classification Manual); SIC Major Group 49: Electric Services (inclu ding all power plants in the same SIC category). Therefore, the BACT Analysis should be gin 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 feas ible for North Dakota lignite-fired cyclone boilers,” and “SCR is not technically feasib le for North Dakota lig nite-fired cyclone boilers.” BACT Determination, 5 and 4, respectively. NDDH incorrectly applies the NSR Manual and the applicable law by assu ming that a pollution control technology must have been demonstrated in practice on an identical facility bur ning an identical fuel from the identical geographical region. Technologi cal 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 cate gories); 70 Fed. Reg. 9706 (Feb. 28, 2005) (same). Second, t he NSR Manual allows for technology transfers. This includes technologies that have not been demonstrat ed on full-scale similar sources, but are “commercially available” and technologies tran sferred 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 propertie s of the flue gas streams. Id. at B.19.

Third, even if a physical or operational modi fication is required to overcome technical obstacles, those modifications do not “justif[y ]... eliminating the control technique on thebasis 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 Dete rmination looks to be a justif ication for a pre-determined technology in an effort to favor a specific co mpany or to give preferential treatment to facilities burning a dirty, low-quality in-state fu el (North Dakota ligni te). As EPA states, “there are many tools in the toolbox” for reducing NO x 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 NO x through the most effective method: application of an S CR, 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/b lending is technically infeasible: (1) the nearest rail line is 10 miles aw ay; (2) the 2005 national average NO x emission rate is 0.83 lb/10 6 Btu, higher than the emission rates for MR Young; and (3) switching to Powder River Basin (PRB) subbituminous coal would increase, not decrease NO x 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 acce ss 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 econom ic feasibility of a control alternative is reviewed in the economic impacts portion of the BACT selection process.

NSR Manual, at B.19. Here, additional transp ortation of a cleaner fuel for blending (if that were necessary to operate an SCR) s hould be addressed as a transportation cost (indirect capital cost) unde r a cost or economic impact analysis. For fuel switching/blending to be techni cally 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 di scussion 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 De partment of Energy’s Energy Information Administration (EIA) website indi cates that coal can be trucke d from a rail line to a plantlocation; a rail line to th e 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, No rth 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 th is 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 NO x emission rate is not acceptable for labeling fuel switching/blending as technically infeasible.

NDDH reviewed EPA’s Acid Rain Databa se to determine the annual average NO x emission rate. BACT Determination, at 14. Th is is an important step in establishing a BACT limit since the Acid Rain Database c ontains significant data showing the emission rates that other plants have achieved. However, NDDH looked at the wrong data and reached an unrepresentative conc lusion. A review of average NO x emission rates during ozone season given by the EPA Acid Rain Data base (see Appendix 2), more specifically referred to as the “Clean Air Markets Data and Maps,” 6 for all NO x trading programs reveals that the average 30-day NO x emission rate for coal-fired units is more closely approximated at 0.30 lb/MMBtu. Clean Air Mark ets 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 Di stance 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.wi zard. 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 NO x 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 pl ants, MR Young has much higher NO x emissions.

C. The combustion of PRB coal would result in lower NO x emissions.

The Clean Air Act and applic able 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 BA CT in the 1990 Clean Air Act amendments. EPA described th e amendment to add ‘clean fuels’ to the definition of BACT at the time the Act passed, ‘as * * * codifying its presen t practice, which holds that clean fuels are an available me ans of reducing emissions to be considered along with othe r 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 s hould 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 switc h would have little effect on NO x emissions. BACT Determination at 14. This is erroneous. Switching or even blending subbituminous coal with North Dakota lign ite would result in a decrease of NO x emissions by increasing the overall efficiency of the boilers and by enabling the direct use of SCR. Either one, alone , can justify the switch. Toge ther, the increased efficiency and ability to use SCR would vastly reduce the NO x emissions.

Uncontrolled NO x emissions are a function of both combustion temperature and the quantity of fuel (coal) availa ble to release fuel-bond nitr ogen. Emission factors for NO x emissions are often expressed on a pound-per-ton-of-coa l-burned basis. As a result, total emissions are directly related to both the em ission 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 NO x from subbituminous coals per ton of coal burned (17 pounds of NO xper ton coal consumed as opposed to 15 lb/t on 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 h eat 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 M ontana 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 mu ch 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 NO x 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 NO x removal efficiency of only 75 % using SCR, the reduction in NO x emissions associated with using the combin ation of fuel switching/blending with SCR increases by a factor of 1.83. Since typical SCR performance is over 90%, the NO x emission reduction is much higher. Therefor e, a switch to subbituminous coal (or even blending subbituminous coal with li gnite) results in a significant NO x reduction that far exceeds any slight increase in the fuel NO x concentration of PRB coal.

III. The BACT Determination does not a dhere 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/ble nding as technically feasible options for MR Young. BACT Determination, at 15. In Sierra Club v. EPA , 449 F.3d 653 (7 th 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 Stat ion. Therefore, Minnkota is not required to consider switchi ng 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 exp licitly addresses the parameters that must be followed when de veloping 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 Significan t Deterioration permit. It is inappropriate to apply this de cision to retroactive reviews necessitated by violations of the CAA, due to constructions or modificat ion 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 ho lding 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 gasifi cation and combined cycle plant. The Environmental Appeals Board not ed that the fact that the state agency looked beyond the applicant’s preferences to other types of power plants i ndicates that the “redefining the source” policy is not so narrow as to cut o ff consideration of pollution control options that would necessitate signifi cant changes from the applican t’s preferred strategy. The Prairie State case was therefore a narrow excepti on, 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-m outh plant, it is not “designed” in such a way that prohibits combustion of cleaner fuel s. 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 here by formally request that NDDH consider that alternative in acc ordance 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 fu el 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, incl uding 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 S CR as a technically feas ible control option on lignite-fired boilers have included the following:• The cost of installing SCR and converti ng from lignite to another fuel source would be excessive

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

• The lignite mining industr y would be destroyed 7

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 combusti on is prone to decreased catalyst life and increased catalyst replacement, and while the specified emission reduction can be achieved, SCR is still technically infeasib le 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 performa nce with North Dakota lignite. Id. at 54.

These off-the-shelf excuses for favoring low-qua lity lignite fuel are mistaken and largely irrelevant. SCR is a technically feasible opti on for lignite-fired boilers. In the final rule amendments to New Source Performance St andards for steam generating units, EPA responded to comments raised regarding SCR fe asibility for lignite-fired units by stating that: “[t]here is considerable experience in th e 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. “co mmercially available”) in Texas.

Moreover, the NSR Manual requires the app licant to “survey the range of potentially available control options.” NSR Manual, at B.11. This includes “technologies in application outside the United States to th e 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 E nvironmental Quality found SCR to be technically feasible for the control of NO x 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 St akeholder Meeting Summary, available at http://www.tceq.state.tx.us/assets/public/implement ation/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 Brem ond near the Tidwell Prairie Community. 9 Statistical analysis of U.S. Geological Survey data 10 on the coal from the Calvert Bluff mine shows that the coal has an average calci um 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 suppor t the claim of techni cal infeasibility of SCR. BACT Determination, at 21. With a si milar (or less favorable ) calcium percentage in its lignite, the Twin Oaks Power Plan t 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 NO x emission rates of 0.158 and 0.156 lb/MMBtu in practice, much lower th en 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 sp ecific state and specific mine. For BACT top-down analysis, it is enough that SCR is co mmercially 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” appro ach is contrary to th e NSR Manual and to the Congressional purpose to dr ive pollution control advan ces through BACT emission limits.

Moreover, EPA has stated that Minnkota ha s not provided enough in formation to show SCR to be technically in feasible for MR Young:

Minnkota has not provided informa tion that ‘shows that . . . [deposition] and deactivation of the SCR catalyst is an unresolvable technical barrier a nd/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 c oncerns regarding the potential need to replace the SCR catalyst frequent ly 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 replaceme nt 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 techni cally infeasible.’” Id

.

9 Energy Information Administration, “Table 24. Or igin of Coal Received By Electric Utility and Plant (2000)”, available at http://www.eia.doe.gov/elect ricity/cq/t24p26.html. Accessed on 07/23/2008.

10 U.S. Geological Survey, “US COALQUAL Database,” available at http://energy.er.usg s.gov/products/databases/CoalQual/i ndex.htm. Accessed 07/08/08.V. NDDH and Minnkota have not consid ered engineering solutions that would facilitate the use of SCR, rendering the BACT top-down analysis incomplete.

The problems associated with SCR use, acco rding to NDDH, include the gas stream qualities that result in “uni que catalyst deposition, er osion, 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 NO x 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 acquiesce d by NDDH include: 1. High carryover of fly ash containing alkali ne 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 facili tate 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 conjuncti on with SCR, as discussed above.

2. Injection of a fluxing agent to increas e melting of the solid combustion byproducts, creating less fly ash to be portio ned and re-injected into the exhaust gas to poison the catalysts. Culligan, et al, 2005.

3. Sootblowing and screens to minimize fly as h and prevent plugging of catalysts. Blankenship.

4. Catalyst improvement by surface and edge coating to minimize deactivation from alkaline metals, silicates, and sulfates ha s been shown to main tain. 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 freque ncy is within the range cited by NDDH on page 32 of the BACT Determinati on as indicative of normal operation.

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

mercury.

6. Coal Cleaning with Drying – Testing us ing 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 toPowder River Basin subbituminous coal,” “resulting in a lignite yielding 8900 BTU” thereby decreasing coal usage and NO x emissions. 11 Also, K Fuel® and K Direct® remove moisture (and mercur y) thereby “upgrading lignite to performance levels approaching that of bituminous coal” by increasing heat content by as much as 52% and decreasing NO x 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 Ri ver Energy’s Coal Creek Station. 13

VI. NDDH has not reviewed add-on contro ls nor combinations of controls that may overcome the challenges associat ed using SCR and have proved more efficient reduction of NO x than SNCR.

The BACT Determination does not address th e following technologies or combinations of technologies for the control of NO x emissions:

1. Deep staging-Rich Reagent Injectio n-SNCR System or Advanced Layered Technology Approach (ALTA)

a. 4-week full-scale test by Reaction E ngineering, Inc. and Fuel Tech funded by the Department of Energy using Il linois #6 and PRB coals established NO x 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 bo iler—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 NO x Control Interest Group (CNCIG) and have resulted in several design and ope rational changes to existing cyclone boilers. 14

2. Deep staging-Overfire Air (OFA)-C ontinuous 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/lr c/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.do e.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 NO x Emissions Below 0.15 in a Cyclone Boiler Using In-furnace NO x 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 NO x Burners

Tests conducted by Babcock & Wilcox on a 110 MW cyclone boiler at Wisconsin Power and Light’s Nelson Dewey Plant, Cassv ille, WI saw a 50% reduction in NO x 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 indicate s that “to the Department’s knowledge” only one permanent applicat ion of conventional gas reburn or FLGR and SNCR are known. BACT Determination, at 59-60. To be “technically feasible,” a technology do es 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 suggesti ng that based on size, fuel type, and firing configuration the t echnology 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 t echnical analysis and comparison between the gas streams from MR Young and the plants where the technology has been demonstrated a nd determines that sufficient differences regarding relevant ga s 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 NO x by reducing thermal NO x 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/displ ay_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 NO x ” is inaccurate. See BACT Determination, at 62.

c. Numerous prior case-by-case determ inations for control and retrofit control analyses have addressed FGR as a control technology for NO x . This technology should not be elim inated 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 prov ides superior control while decreasing ammonia slip and the requir ed 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 NO x 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 Comp any (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 NO x , sulfur dioxide, and mercury.

b. Commercially available in Europe and Japan.

9. Chemical Oxidation/Chemical Reduction

Tri-Mer’s TriNOx ® or BOC Gases LoTOx TM systems are resistan t to catalyst plugging, can handle varying NO/NO 2 ratios, with efficiencies, a ccording 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://w ww.ftek.com/pdfs/TPP-566.p df. Accessed 07/26/08.

20 “Carbon Sequestration: Capture Project Desc riptions,” available at http://www.netl. doe.gov/technologies/carbon_seq /core_rd/capture/4 1147.html. Accessed 07/24.2008. See also Black and Veatch, supra note 13.10. Mitsui Babcock (now Doosan Babcock Energy) NOxStar TM

a. Can reduce NO x by 70%.

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

11. Mitsui Babcock Combined Non-catalytic NO x Reduction System 23

a. Consists of SNCR - Low NO x Burners - Deep Furnace Staging -Boosted OFA-Coal and Gas Reburn

b. Capable of producing a 70% reduction

12. RJM Layered System 24

a. Burner modifications such as:

(l) Balancing the secondary ai r between the bu rners through air distribution analysis

(2) Utilizing NO x tempering or injecti on of micronized water droplets into high-NO x production zones in the near-burner region to reduce NO x incrementally by as much as 30%

(3) Amine reagent injection in th e 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% NO x reduction

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

In addition to controlling NO x , many of these system are reported to control sulfur dioxide and mercury as well. These collatera l control benefits should be considered in any future cost, energy, or environmenta l 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 “NOxStar TM Plant Demonstration,” available at http://www.netl.doe.gov /publications/proceedings/03/scr-sncr/Fin al_Morris.pdf. Accessed on 07/08/08.

23 “NO x – 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% NO x Reduction,” available at http://www.rjm.com/pdf/N ew_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 in vested in process control technology to reduce this time. The Emerson SmartPro cess® Unit Response Op timization technology, installed on Unit 1 in Fall 2007, aids in quicker stabilization after demand changes to the system. 25 It is reported that the SmartProce ss® 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 shutdow n 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 establis h a “30-day rolling average emission rate” for the emission of NO x . The Consent Decree states, “Each 30-day Rolling Average Emission Rate shall include all start-up , shutdown and Malfunction peri ods 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/M MBtu for Unit 1 and 0.102 lb/MMBtu for Unit 2 based on 30-day rolling average, adjus ting 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-da y rolling average emission rate to include SU/SD. Therefore, the BA CT 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 discreti on during periods of SU/SD in regards to the “30-day rolling average” and the “30-day ro lling average control efficiency” referred to in the Decree, this can be accomplished th rough simple recording of the beginning and ending of an SU/SD event and the proposed 24-hour NO x limit. However, explicit exclusion of such events from the 30-da y 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% re moval 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 SN CR 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 contro l 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 temp eratures 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 opt imum 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 uns table temperature and low efficiencies expected for SNCR. Nor did NDDH review heati ng 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, environm ental, and energy impact assessment under step 4 of the Top-Down BACT Analysis.

Furthermore, NDDH does not consider engineer ing solutions that w ould enable higher efficiencies associated with the use of a SCR system. Nor does NDDH consider combinations of technologies that would impr ove the overall efficiency associated with SNCR. NDDH should review the SmartProcess® , flue gas heating, and the technologies identified in Comment VI to impr ove the proposed BACT efficiency.

X. The proposed NO x emission limit associated with the proposed BACT is not consistent with other emission rate s 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 Tract ebel Power Inc. Choctaw Generation in Choctaw, Mississippi, a Mississi ppi lignite-fired facility, is achieving 0.13 lb/MMBtu on a 30-day rolling average duri ng ozone season. The Stanton Station Units 1 and 10 in North Dakota, both North Dakota lignite -fired, can achieve an average NO x concentration of 0.23 and 0.28, respectively. See Clean Air Markets Database. In fact, at the BACT emission limits proposed by Minnkota and ac cepted by NDDH, 65% of the coal-fired units in the U.S. achieve lower NO x emissions. See Figures 3 and 4 of the Appendix. Anemission 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 inve stigate other technologies and work practices, including those listed in Comments VI, VII, and VIII that would achieve NO x emission limits closer to those achieve d by other coal and lignite-fired units.

CONCLUSION

For the foregoing reasons, Plains Justice resp ectfully requests that the Preliminary Best Available Control Technology Determination fo r 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 30 th day of July 2008.

Respectfully Submitted On Behalf of Plains Justice and Sierra Club,

Nicole Shalla