Best Available Control Technology
Determination
for Control of Nitrogen Oxides

for M.R. Young Station
Units 1 and 2

April 2010

Division of Air Quality ND Department of Health
918 E. Divide Avenue Bismarck, ND2 Table of Contents

I. Introduction

II. Step 3: Rank Remaining Control Technologies by Con trol Effectiveness

A. Baseline Emissions
B. Control Alternatives Effectiveness

III. Step 4: Evaluate Most Effective Controls and Docum ent Results

A. Cost/Economic Analysis
B. Energy Impact Analysis
C. Environmental Impacts
D. Consideration of Emissions of Toxic or Hazardous Ai r Pollutants

IV. Step 5: Select BACT

References

Appendix A Selective Catalytic Reduction (SCR) Technical Feasibility for M.R. Young Station Appendix B Minnkota’s Cost Estimate and Supporting Data Appendix C Supplemental Information Appendix D Excerpts from Confidential Vendor Propos als3

I. Introduction

In June of 2008, the North Dakota Department of Hea lth (Department) provided for public comment a preliminary Best Available Control Techno logy (BACT) determination for the control of nitrogen oxides at both units of the M.R . Young Station. That preliminary determination indicated that selective catalytic re duction (including high dust SCR, low dust SCR and tailend SCR) was not technically feasible f or the units at the M.R. Young Station. The preliminary determination was that BACT was rep resented by selective non-catalytic reduction (SNCR) plus advanced separated overfire a ir (ASOFA).

The Department received comments suggesting that al l three types of SCR (HDSCR, LDSCR and TESCR) were technically feasible. Based on the comments, the Department reevaluated the technical feasibility of SCR (see Appendix A). Bas ed on the information available at the time, the Department maintained its position that HDSCR w as not technically feasible; however, the Department determined that LDSCR and TESCR were tec hnically feasible. On June 15, 2009, the Department asked Minnkota Power Coop (Minnkota) to submit a cost estimate and complete the BACT analysis for LDSCR and TESCR. Minnkota, i n submittals dated November 12, 2009, December 11, 2009 and February 11, 2010, provided t he cost estimates and supporting documentation (see Appendix B).

This document provides the Department’s evaluation of LDSCR and TESCR as a BACT control technology and provides a determination of BACT.

II. STEP 3: Rank Remaining Control Technologies by Con trol Effectiveness

A. Baseline Emissions

EPA’s Draft New Source Review Workshop Manual (NSR Manual Section IV.D.2.b) states “The baseline emissions rate repre sents a realistic scenario of upper bound uncontrolled emissions for the source.” The NSR Manual goes on to state “Estimating realistic upper-bound emissions d oes not mean one should assume the emissions represent the potential emissi ons.” Also, the NSR Manual states “In addition, historic upper bound operating data, typical for the source or industry, may be used in defining baseline emission s in evaluating the cost effectiveness of a control option for a specific so urce.” Minnkota has estimated their baseline emissions based on the following cri teria:

Table 1 Predicted Operating Data Operating Data Unit 1 Unit 2

Baseline Emission Rate (lb/10 6 Btu/hr) 0.849 0.786 Heat Input (10 6 Btu/hr) 2744 4885 Availability 97.3% 93.9%
Baseline NO
x Emissions (tpy) 9,934 15,7934 The Department evaluated the historical operating d ata from M.R. Young Station
to determine if Minnkota’s baseline emission rates were reasonable. Based on the maximum 2-year period (may be different for each pa rameter) in the last 5-years (2003-2007), the results are:

Table 2

Historical Operating Data Operating Data Unit 1 Unit 2 Actual Emission Rate (lb/10 6 Btu/hr) 0.840 0.835 Heat Input (10 6 Btu/hr) 2,728 4,691 Availability a 96.4% 92.2%
Calculated Maximum Emissions (tpy) b 9,676 15,818

Historical NO
x Emissions (tpy) c 9,081 14,858

a Based on actual hours of operations.

b Based on actual emission rate (lb/10 6 Btu/hr), heat input (Btu/hr) and availability.

c Based on the average of the highest two years in th e last five years.

Minnkota’s calculated baseline emissions are somewh at higher than the historical emissions; however, it appears their calculated bas eline emission rates are reasonable. Using historical baseline emissions wo uld increase the cost
effectiveness value for SCR and make it less attrac tive as a BACT control technology as shown in Table 5.

B. Control Alternatives Effectiveness

Table 3
Emissions Reductions

Unit Technology a Expected Efficiency (%) Controlled Emission Rate Annual Average
lb/10 6 Btu Tons/yr 1 LDSCR + ASOFA (A) 93.8 0.053 586 1 LDSCR + ASOFA (B) 93.8 0.053 533 1 TESCR + ASOFA (A) 93.8 0.053 589 1 TESCR + ASOFA (B) 93.8 0.053 536 1 SNCR + ASOFA 58.1 0.355 4,025 1 Gas Reburn + ASOFA 56.0 0.374 4,275 1 Lignite Reburn + ASOFA 54.6 0.385 4,343 1 FLGR + ASOFA 45.9 0.460 5,260 1 ASOFA 39.5 0.513 5,874 1 Baseline --- 0.849 9,934 2 LDSCR + ASOFA (A) 93.8 0.049 931 2 LDSCR + ASOFA (B) 93.8 0.049 913 2 TESCR + ASOFA (A) 93.8 0.049 936 2 TESCR + ASOFA (B) 93.8 0.049 8135 Table 3
Emissions Reductions

Unit Technology a Expected Efficiency (%) Controlled Emission Rate Annual Average
lb/10 6 Btu Tons/yr 2 SNCR + ASOFA 58.0 0.330 6,421 2 Gas Reburn + ASOFA 55.4 0.350 6,882 2 Lignite Reburn + ASOFA 54.2 0.360 6,964 2 FLGR + ASOFA 45.0 0.432 8,490 2 ASOFA 37.7 0.489 9,621 2 Baseline --- 0.786 15,793

a Scenario (A) based on a catalyst replacement sched ule of 16,000 hours. Scenario (B) based on catalyst replacement during scheduled outa ges. For Unit 1 this is every 4 months and for Unit 2 this is every 3 months.

III. STEP 4: Evaluate Most Effective Controls and Docum ent Results

A. Cost/Economic Analysis

The NSR Manual (Section IV.D.2.a) states “Total cos t estimates of options developed for BACT analyses should be on the order of plus or minus 30 percent accuracy.” Minnkota has developed costs estimates that are site specific. The cost estimates are based on information supplied by design engineers and vendors. The estimates appear to be within ± 30% for the des ign presented.

Minnkota has supplied four different cost estimates for LDSCR and TESCR. Two cost estimates are based on each unit operating as a stand-alone facility and two estimates are based on Unit 1 and Unit 2 having shared facilities. The other cost parameter that varies is the catalyst replacem ent schedule. Minnkota included two schedules, every 16,000 hours or every scheduled shutdown of the unit (3-4 months depending on the unit). The 3-4 m onths (approximately 2,200 – 2,900 hours) catalyst replacement would represent a catalyst life which the Department considers to be unsuccessful application of SCR technology and thus SCR would be technically infeasible. However, the lack of a vendor guarantee and statements made by the vendors (as discussed in Step 5) provides some justification for submitting such an estimate. The Department has included both estimates in this analysis.

Minnkota believes the BACT determination should be based on the estimate provided for the stand-alone facilities. Their rea soning is that BACT, by definition, is determined on a case-by-case basis ( i.e. seperate for each unit). Paragraph 65 of the Consent Decree requires a BACT analysis for each unit and Minnkota has supplied a separate analysis for each unit.

Unit 1 and Unit 2 at the M.R. Young Station are bot h cyclone-fired units burning lignite from the Center Mine. The likely outcome i s that BACT will be the same6 for both units. Therefore, the design of the syste ms would logically share facilities such as the natural gas pipeline for reh eat fuel and urea storage facilities. This would be the least expensive system to build a nd would better represent the true cost of the systems. Therefore, the Departmen t has only included in its analysis the shared facilities cost estimate.

Table 4
Costs
Minnkota’s Baseline Emissions

Unit Technology NO

x Reduction (tons/yr) Levelized

Annualized Cost ($) Cost

Effectiveness ($/ton) Incremental

Cost
Effectiveness ($/ton) 1 LDSCR + ASOFA (A) 9,348 33,526,000 3,586 7,576 a 1 LDSCR + ASOFA (B) 9,401 45,244,000 4,813 10,817 a 1 TESCR + ASOFA (A) 9,345 39,307,000 4,206 9,265 a 1 TESCR + ASOFA (B) 9,398 50,937,000 5,420 12,458 a 1 SNCR +ASOFA 5,909 7,472,000 1,265 2,697 b

1 Gas Reburn + ASOFA c 5,659 37,334,000 6,597 --- 1 Lignite Reburn + ASOFA c 5,591 11,383,000 2,037 ---
1 FLGR + ASOFA c 4,674 16,990,000 3,635 --- 1 ASOFA 4,060 2,489.000 613 --- 2 LDSCR + ASOFA (A) 14,862 57,351,000 3,859 8,330 a 2 LDSCR + ASOFA (B) 14,980 86,542,000 5,777 13,360 a 2 TESCR + ASOFA (A) 14,875 66,506,000 4,476 10,007 a 2 TESCR + ASOFA (B) 14,980 96,268,000 6,426 15,095 a 2 SNCR +ASOFA 9,372 11,618,000 1,240 2,263 b

2 Gas Reburn + ASOFA c 8,910 63,982,000 7,181 --- 2 Lignite Reburn + ASOFA c 8,829 19,475,000 2,206 ---
2 FLGR + ASOFA c 7,303 29,317,000 4,014 --- 2 ASOFA 6,172 4,376,000 709

a Incremental cost between given technology and SNCR + ASOFA.

b Incremental cost between SNCR + ASOFA and ASOFA.

c Inferior options.

Table 5
Costs
Historical Baseline Emissions

Unit Technology NO

x Reduction (tons/yr) Levelized

Annualized Cost ($) Cost

Effectiveness ($/ton) Incremental Cost

Effectiveness ($/ton) 1 LDSCR + ASOFA (A) 8,518 33,526,000 3,936 8,036 a 1 LDSCR + ASOFA (B) 8,518 45,244,000 5,312 11,645 a 1 TESCR + ASOFA (A) 8,518 39,307,000 4,615 9,820 a 1 TESCR + ASOFA (B) 8,518 50,937,000 5,980 13,407 a 1 SNCR + ASOFA 5,276 7,472,000 1,416 2,950 b

1 Gas Reburn + ASOFA c 5,085 37,334,000 7,342 1 Lignite Reburn + ASOFA c 4,958 11,383,000 2,2957 Table 5
Costs
Historical Baseline Emissions

Unit Technology NO

x Reduction (tons/yr) Levelized

Annualized Cost ($) Cost

Effectiveness ($/ton) Incremental Cost

Effectiveness ($/ton)

1 FLGR + ASOFA c 4,168 16,990,000 4,076 1 ASOFA 3,587 2,489,000 694 2 LDSCR + ASOFA (A) 13,937 57,351,000 4,115 8,598 a 2 LDSCR + ASOFA (B) 13,937 86,542,000 6,210 14,086 a 2 TESCR + ASOFA (A) 13,937 66,506,000 4,772 10,319 a 2 TESCR + ASOFA (B) 13,937 96,268,000 6,907 15,915 a 2 SNCR + ASOFA 8,618 11,618,000 1,348 2,400 b

2 Gas Reburn + ASOFA c 8,231 63,982,000 7,773 2 Lignite Reburn + ASOFA c 8,053 19,475,000 2,418
2 FLGR + ASOFA c 6,686 29,317,000 4,385 2 ASOFA 5,601 43,760,007 781

a Incremental cost between given technology and SNCR + ASOFA.

b Incremental cost between SNCR + ASOFA and ASOFA.

c Inferior options.

Because of lack of a vendor guarantee without pilot scale testing and statements made by the vendors (see Step 5), 16,000 hours betw een catalyst change out may not be possible. The following represents an avera ge for the two catalyst changeout scenarios presented by Minnkota.

Table 6 Average Costs
Minnkota’s Baseline Emissions

Unit Technology NO
x Reduction Levelized

Annual
Cost b Cost

Effectiveness ($/ton) Incremental

Cost
Effectiveness ($/ton) 1 LDSCR + ASOFA 9,375 39,385,000 4,201 9,207 a 1 TESCR + ASOFA 9,372 45,122,000 4,815 10,872 a 1 SNCR + ASOFA 5,909 7,472,000 1,265 2 LDSCR + ASOFA 14,921 71,947,000 4,822 10,872 a 2 TESCR + ASOFA 14,919 81,387,000 5,455 12,578 a 2 SNCR + ASOFA 9,372 11,618,000 1,240

a Incremental cost of selected technology versus SNCR + ASOFA.

b Average cost for the two scenarios.

B. Energy Impact Analysis

Minnkota has evaluated the energy impacts associate d with each control option. TESCR would have the highest power usage followed c losely by LDSCR. The power usage by TESCR is approximately 100 times tha t of SNCR. Although8 there is a large discrepancy in the power usage, th e amount of power used, by itself, would not preclude the use of LDSCR or TESC R. However, it is a consideration in determining BACT for the source.

C. Environmental Impacts

The installation of either SCR or SNCR at M.R. Youn g will increase ammonia emissions to the atmosphere due to ammonia slip. H owever, it is expected that the ammonia slip can be limited to 2-5 ppmvd at 3% O 2 . No adverse environmental impacts are expected from this amount of ammonia slip. Use of a SCR catalyst may lead to increased formation of amm onium bisulfate and/or ammonium sulfate. The Department believes these ai r contaminants will not be emitted in a quantity that adversely affect the env ironment. Catalyst disposal will
be another environmental issue for SCR. The relati vely small volume of catalyst that must be disposed will not present any signific ant effects.

The increased power usage by LDSCR and TESCR will r esult in additional air pollutants being emitted to the atmosphere. The in crease in CO 2 emissions for
SCR versus SNCR are as follows:

Table 7
CO 2 Increase

Unit Control Alternative CO 2 Increase (Tons/yr) 1 TESCR (A) 78,300 1 TESCR (B) 71,500 1 LDSCR (A) 64,700 1 LDSCR (B) 58,800 2 TESCR (A) 114,600 2 TESCR (B) 99,400 2 LDSCR (A) 94,900 2 LDSCR (B) 82,800

Based on the information presented, there appears t o be no environmental impacts that would preclude the selection of SCR or SNCR as BACT. However, the environmental impacts are considered in the BACT se lection process.

D. Consideration of Emissions of Toxic or Hazardou s Air Pollutants

As discussed in the previous section, the Departmen t believes any additional emissions of air contaminants, including toxic or h azardous contaminants, will not have a significant adverse effect on the public or the environment.9

IV. STEP 5: Select BACT

Minnkota maintains that SCR, no matter where it is located (i.e. HDSCR, LDSCR or TESCR), is not technically feasible for the units at the M.R. Young Station. Based on the information provided through June 2009, the Department made a d etermination that HDSCR was not technically feasible; however, LDSCR and TESCR were technically feasible. This determination was based, in part, on assurances by SCR and catalyst vendors that a catalyst life guarantee could be obtained without pilot-scale tes ting. Two of these vendors were CERAM Environmental, Inc. (CERAM) and Haldor Topsoe, Inc. Despite their concerns about technical feasibility, Minnkota worked with CERAM and Haldor Topsoe to develop a cost estimate for both LDSCR and TESCR. As part of the process to de velop the cost estimate, Minnkota supplied both vendors with detailed information abo ut the flue gas characteristics of the M.R. Young Station (see Microbeam Technologies report, J uly 1, 2009). Based on their review of the data, both vendors have refused to provide a cataly st life guarantee for either LDSCR or TESCR without pilot-scale testing. This is in direct con trast to earlier statements by both companies.

In their proposals to Minnkota, both companies have made statements that bring into question the technical feasibility of both LDSCR and TESCR ( see Appendix D). CERAM has stated that it is unaware of any SCR application experience in the industry with the level and form of sodium in the M. R. Young Station ash. Haldor Tops oe has stated that the potential exists that physical deactivation due to catalyst blinding and plugging could be severe enough to make SCR a non-viable option for controlling NO
x emissions.

Several times statements have been made by commente r’s that sodium and potassium aerosols are not a catalyst poison unless the temperature of the reactor is below the dew point (i.e. moisture carries the sodium and potassium to the ac tive sites). CERAM has stated in their proposal that small aerosol particles can penetrate and neutralize active catalyst sites even in dry
conditions . In addition, CERAM states that catalyst installe d even in low dust and tailend locations are poisoned from the exposure to the flu e gas and the high levels of phosphorous, sodium and potassium found in the mineral analyses at M.R. Young Station will increase
deactivation rates. This is consistent with the fi ndings of Kling, et.al. 1 and Zheng, et.al. 2

EPA’s New Source Review Workshop Manual (Section IV .B) states “A control technique is considered available, within the context presented above, if it has reached the licensing and commercial sales stage of development. A source wo uld not be required to experience extended time delays or resource penalties to allow research to be conducted on a new technique. Neither is it expected that an applicant would be required to experience extended trials to learn how to apply a technology to a totally new and dissimilar source type. Consequently, technologies in the pilot-scale testing states of development would not be considered available for BACT review.” CERAM’s statement that they are unaware o f any SCR application experience in the industry with the level and form of sodium in the a sh at M.R. Young Station indicates this is a new and dissimilar source type based on the flue ga s characteristics.

Vendors’ statements that they will not provide a ca talyst guarantee without pilot-scale testing indicate SCR (HDSCR, LDSCR or TESCR) for use on a b oiler firing North Dakota lignite could be considered in the pilot-scale testing stages of development. The lack of vendor guarantees10

and statements from the vendors regarding physical deactivation (plugging and masking) indicate successful application of SCR technology i s not assured.

The NSR Manual (Section IV.D.2.c) states “...if the c ost of reducing emissions with the top control alternative, expressed in dollars per ton, is on the same order as the cost previously borne by other sources of the same type in applying that control alternative, the alternative should initially be considered economically achievable, an d therefore acceptable as BACT.” The Department has gathered information from recent BAC T determinations that required SCR to
determine the estimated cost at these sources. The results in Table 8 show a pattern of significantly higher costs at M.R. Young Station th an at other recently permitted sources. Unfortunately, SCR is the most efficient NO
x removal technology. Many BACT analyses do not contain cost data because it is the top technology. If the top control technology is selected as BACT, a cost estimate is not required (as allowed by the NSR Manual Section III.C). Where a cost for SCR was provided and SCR was selected at B ACT, the costs were probably not verified by the reviewing agency. This leads to uncertainty regarding the actual cost effectiveness for
sources where SCR was selected as BACT.

Table 8
BACT Costs

Source Cost Effectiveness ($/ton) Estimated Efficiency M.R. Young Unit 1 4,201 93.8 M.R. Young Unit 2 4,822 93.8 Dry Fork 1,511 83 Wygen 3 a 4,037 89 Norborne 2,600 85% Turk 2,439 74% TS Power Plant 2,047 66%

a 110 MWe Plant – LNB + OFA + SCR

In order to gather more data about the cost of SCR, the Department reviewed the Best Available Retrofit Technology (BART) analyses that were submi tted to surrounding states. The results in Table 9 show a much higher expected annualized cost ($/kw) and cost effectiveness at M.R. Young Station than sources subject to BART requirem ents.

Table 9
BART Costs

Source NO
x Controls Expected Efficiency (%) Annualized

Cost ($/kw) Cost

Effectiveness ($/ton) a M.R. Young 1 d ASOFA + SCR 93.8 153.25 4,201 M.R. Young 2 d ASOFA + SCR 93.8 150.82 4,822 Colstrip 1 & 2 LNB + SCR 57 23.74 2,272 Dave Johnson 3 LNB + OFA+ SCR 90 42.17 1,401 Laramie River 1 SCR 74 23.22 2,828 Laramie River 2 SCR 74 24.07 2,84411 Table 9
BART Costs

Source NO
x Controls Expected Efficiency (%) Annualized

Cost ($/kw) Cost

Effectiveness ($/ton) a Laramie River 3 SCR 74 24.07 2,772 Nebraska City
Station #1 LNB + OFA + SCR 86 32.77 2,633

PGE Boardman b LBN + OFA + SCR 84 47.81 3,096
Sherco #1 c CC + LNB + SOFA +

SCR 76 25.82 2,500

Sherco #2 c CC + SCR 60 21.99 4,600 J.E. Corette SCR 42-54 23.52 4,354 Big Stone SCR + SOFA 80-90 27.81 825 Boswell Energy
Center #3 LNB + OFA + SCR 81 33.33 3,201

GGS 1 & 2 LBN + OFA + SCR 82 41.94 2,297 Healy SCR --- 35.90 3,374 Jim Bridger 1 LNB + OFA+ SCR 84 29.43 1,736

a Consultant’s estimate except as noted.

b ERG, working for the Oregon DEQ, estimated the capi tal cost to be 27% less than the PGE consultant. The ERG estimate would yield a cost of approximately $39.78/kw and $2,600/ton.

c Baseline emission rate is 0.20 lb/10 6 Btu. CC = combustion optimization system.

d Based on LDSCR and average of Scenarios A and B.

The cost effectiveness in Tables 8 and 9 can be mis leading since the calculated values are dependent on the projected efficiency of the NO
x combustion controls and add on controls. Minnkota has used the highest efficiency (93.8%) of any analysis reviewed. This leads to a
lower cost effectiveness. As noted in the NSR Manu al (Section IV.D.2.b), unrealistically low estimates of the emission reduction potential of a certain technology could result in inflated cost effectiveness figures.

The NSR (Section IV.D) also states “The determinati on that a control alternative is inappropriate
involves a demonstration that circumstances exist a t the source which distinguish it from other sources where the control alternative may have been required previously, or that argue against the transfer of technology or application of new te chnology”. Minnkota has claimed that the flue gas characteristics, even for SCR in a low dust or tailend position, are different from any other facility were SCR has been applied. This claim has been corroborated by CERAM which indicated they were unaware of any SCR experience w ith a source that has similar flue gas characteristics. The lack of a vendor guarantees a nd Haldor Topsoe’s statement that LDSCR and TESCR might not be a viable option for NO
x control at M.R. Young appears to distinguish M.R. Young Station from other sources where SCR has been applied.

The average cost effectiveness (excluding M.R. Youn g Station) from Table 8 is $2,527/ton and $2,664/ton from Table 9. The expected cost effecti veness at M.R. Young is significantly higher12

than these values (54% - 91%). The cost effectiven ess of SCR at M.R. Young Station is higher than any other facility in Table 7. The cost effec tiveness at M.R. Young Station is higher than any BART facility in Table 8 except Sherco No. 2 an d J.E. Coretta. However, the cost
effectiveness at Sherco No. 2 was based on 60% remo val efficiency and 42-54% at Corette. Had 93.8% removal efficiency been used, the cost effect iveness would be substantially less than at M.R. Young Station.

The Department has also considered the incremental cost of SCR (TESCR or LDSCR) versus SNCR. The incremental cost varies from $7,576/ton to $10,817/ton for LDSCR at Unit 1 based on Minnkota’s calculation and $8,330/ton to $13,360 /ton at Unit 2. The Department considers this incremental cost to be very high. The State o f Pennsylvania rejected wet scrubbing at the River Hill Power company facility which had an incr emental cost of $5,000/ton. The State of Georgia rejected wet scrubbing at the Long Leaf Ene rgy Station which had an incremental cost of $8,964/ton. The State of Nebraska rejected SNCR achieving 0.05 lb/MMBtu based on an incremental cost of $5,600/ton at an ADM facility i n Columbus, Nebraska and limestone injection with an incremental cost of $6,700/ton. The State of Nebraska also rejected dry scrubbing at a Cargill, Inc. facility in Blair, Neb raska which had an incremental cost of $5,900/ton. The State of Texas rejected wet limest one scrubbing at the Sandy Creek Station which had an incremental cost of $5,000/ton. EPA, Region 8 rejected limestone injection and a
wet scrubber at the Deseret Power Plant based on an incremental cost of $10,540/ton. The State of Wyoming rejected an SCR operating at 0.043 lb/10 6 Btu at the Dry Fork Plant based on an incremental cost of $10,300/ton.

In summary, the Department has significant concerns whether LDSCR and TESCR are technically feasible for the M.R. Young Station. S election of SCR as BACT will increase CO 2 emissions up to 193,000 tons per year (Units 1 and 2 combined) over SNCR. The expected cost effectiveness is higher than other plants where SCR has been applied as BACT. It is significantly higher than the average cost effectiv eness values for sources subject to BART. Table 8 shows the disproportional annualized costs that Minnkota would have to bear. The incremental cost of SCR versus SNCR is very high. Incremental costs that are less than at M.R. Young Station have lead to rejection of BACT altern atives by other states and EPA.

The Department has determined that HDSCR is not tec hnically feasible. Based on concerns regarding technical feasibility of LDSCR and TESCR, the high cost effectiveness, the high incremental cost and increased greenhouse gas emiss ions, the Department has determined that neither LDSCR nor TESCR represent BACT at M.R. You ng Station. The Department affirms its June 2008 proposal that BACT for both units is represented by SNCR + ASOFA.13 References

1. Kling, Asa; Anderson, Chester; Mryinger, Ase; Es kilsson, David; Jaras, Sven G; Alkali deactivation of higher dust SCR catalysts used for NO
x reduction exposed to flue gas from 100 MW-scale biofuel and peat-fired boilers: Influence of flue gas composition; Applied Catalysis; 2007.

2. Zheng, Yuanjing; Jensen, Anker Dega; Johnsson, J an Erik; Thogersen, Jaokim Reimer; Deactivation of V205 – W03 – Ti02 SCR catalyst at b iomass-fired power plants; Elucidation of mechanisms by lab – and pilot-scale experiments; Applied catalysis; 2008.

3. EPA, 1990 New Source Review Workshop Manual, Pre vention of Significant Deterioration and Nonattainment Area Permitting, Of fice of Air Quality Planning and Standards, Research Triangle Park, NC 27711.