UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 8 1595 Wynkoop Street DENVER, CO 80202-1129 Phone 800-227-8917 http://www.epa.gov/region08

Ref: 8ENF-L Via Email and UPS Overnight

Mr. Terry O'Clair Director, Division ofAir Quality North DakotaDepartment ofHealth 918 E. Divide Avenue Bismarck, ND 58501-1947 Re: EPA's Comments on the NorthDakota Department ofHealth's April 2010 Draft BACT Determination for NOx for the Milton R. Young Station DearMr. O'Clair: This lettertransmits the United States Environmental Protection Agency's (EPA's) comments on the North DakotaDepartment ofHeaIth's (NDDH's) April 2010, Draft Best Available Control Technology (BACT) Determination for Nitrogen Oxides (NOx) for Milton R. Young Station (MRYS), Units 1 and 2 (Draft BACT Determination). The Draft BACT Determination concludes that low-dust and tail end Selective Catalytic Reduction (SCR) are not cost effective NOx controls at MRYS. The Draft BACT Determination found that low-dust SCR (LDSCR) would be more cost effective than tail-end SCR (TESCR), and evaluated the cost effectiveness ofLDSCRbased upon NDDH's conclusion that the average cost effectiveness for LDSCR is $4,201 perton forUnit 1 and $4,822 perton for Unit 2. 1 NDDH's DraftBACT Determination also concludes that LDSCRwas not cost effective because ofthe incremental costs ofthese controls. The DraftBACT Determination is not supportedby the record and is not reasonable in light ofapplicable statutory and regulatoryprovisions for two reasons. First, the DraftBACT Determinationrelied upon unreasonable assumptions and factors not authorized by law to determine the cost effectiveness ofSCR at MRYS. This resulted in a significant overestimate of

1. Since NDDH found that LDSCR was more cost effective than TESCR, these comments are focused on LDCSR, but most ofthe comments also apply to TESCR.EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
the cost ofthese controls. Second, even NDDH's unreasonably inflated cost estimates are on the same order as costs previouslyborne by other sources and must be considered cost effective. I. 

### SCRis CostEffective Based upon 

### NDDH's Inflated 

### Cost Estimates The Consent Decree that EPA and NDDH entered into with Minnkotarequires NDDH to conduct its BACT analysis in accordance with the applicable federal and state statutes, and the provisions ofChapterB ofEPA's "New Source Review Workshop Manual---Prevention of Significant Deterioration and Nonattainment Area Permitting," (October 1990) (NSR Manual).2 The NSR Manual is used nationwide in PSD permitting decisions and provides that, "ifthe cost ofreducing emissions with the top control alternative, expressed in dollars per ton, is on the same order as the costpreviouslyborne by other sources ofthe same type in applying that control alternative, the alternative should initiallybe considered economically achievable, and therefore acceptable as BACT.,,3 The NSR Manual further provides that "costestimates used in BACT are typically accurate to ± 20 to 30 percent. Therefore, control cost options which are within ± 20 to 30 percent ofeach other should generally be considered to be indistinguishable when comparing options.,,4 According to the NSR Manual, the economic impacts component ofa BACT analysis may include an examination ofboth the average cost effectiveness and the incremental cost effectiveness ofa control option.5 The Manual defines the "average cost effectiveness" as the "total annualized costs ofcontrol divided by annual emission reductions, orthe difference between the baseline emission rate and the controlled emission rate
...,,6 NDDH's Draft BACT Determination failed to conduct an adequate comparison ofthe average cost effectiveness ofSCR at MRYS with other sources. NDDH onlyreviewed the cost effectiveness ofa small select group offacilities with SCRs in nearby states, ignoring the costs borne by facilities that installedNOx controls throughout the country. The Clean AirAct, the PSD regulations, and the NSR Manual do not allow a permitting authority to restrict its comparative review to a subset ofthe whole ofthe sources that have undergone BACT review for NOx• This review should have beennationwide, and the dollars perton removed ofNOx can be compared to sources undergoing PSD review across the country. Although a permitting authority may considerunique circumstances relating to the location ofa facility in determining the total costs ofa BACT control technology at that facility, itmaynot ignore the cost effectiveness determinations from otherparts ofthe country and choose to allow

2 Seehttp://www.epa.gov/ttn/nsr/gen/wkshpman.pdf. 3. SeeNSR Manual at B.44. 4. /d. 5. SeeNSR Manual at B.4l. 6. /d. atB.36. 

### -2-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
facilities to avoidthe installation ofBACT level controls by setting unreasonable low cost effectiveness thresholds. The DraftBACT Detennination is also deficientbecause it compared the calculated cost effectiveness ofLDSCR at MRYS with the average ofthe costs ofcontrols from the facilities within the small group selectedbyNDDH, instead ofcomparing the MRYS costs with individual costs at the other facilities. NDDH's comparison ofthe cost effectiveness ofLDSCR at the MRYS with the average costs ofa small group offacilities is inconsistent with the NSR Manual and frustrates the technology-forcing function ofthe BACT process because it ignores the higher costs that other sources had to bearto install the same controls. Since the NSRprogram is designed to maximize the use ofimproved technologies and requires controls that will achieve the maximumreductions, the BACT analysis cannotjust compare the cost effectiveness of proposed controls with the average costs borne by other sources, but should favor consideration ofthe highest control costs borne by other sources. The requirement inthe Clean AirAct is for the "Best" available controls, not the"Average" available controls. Even the select group ofcontrol costs that NDDH used in the DraftBACT Detennination demonstrates that the cost effectiveness ofLDSCR at MRYS was on the same order as the costs borne by other facilities. NDDH's Draft BACT detennination concludes that the cost effectiveness for NOx controls at Wygen 3 was $4,037 perton. This is within 4% ofNDDH's conclusions regarding the cost effectiveness ofLDSCR at Unit 1 ($4,201 perton) and within 19 % ofNDDH's conclusions regarding the cost effectiveness ofLDSCR at Unit 2 ($4,822 per ton). NDDH also compares the cost effectiveness ofLDSCR at MRYS with the BART cost analysis conducted for a number ofunits. Although EPA is not clearwhy NDDH relied upon these cost analyses, the cost ofinstalling LDSCR at MRYS would also be on the same order as the cost ofinstalling SCR at these units, evenbased uponNDDH's inflated cost estimates. NDDH also had infonnation in the record relating to the cost effectiveness ofat least two units that were on the same order as the cost effectiveness as LDSCR at MRYS, but did not include any discussion ofthese units in the Draft BACT Detennination. On May 4,2010, in response to a request from EPA, NDDH sentEPA "two files which contain excerpts from the BACT analyses we reviewed."? These files contained aPennitApplication Analysis from the Wyoming Department ofEnvironmental Quality (WDEQ) with infonnation regarding the cost estimates for Wygen 2. This document shows that the cost effectiveness ofinstalling SCR at Wygen 2 to meet a rate of0.06 lbs/MMBtu was $4,156 perton. WDEQ stated "[t]he BACT analysis indicates that 0.06 lb/NIMBtu is technically feasible and the Division considers the total and incremental cost effectiveness to be reasonable."g The files also contained documents from the NDDH record with infonnation from the RACT BACT LAER Clearinghouse relating to

7. See Enclosure 1. 8. See Enclosures 1 & 2. 

### -3-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
Wisconsin Public Service Company's Weston 4 coal fired powerplant. This information indicates that $6,116 perton for installing SCRwas considered cost effective by Wisconsin.9
Since the NSR Manual provides that "control cost options which are within ± 20 to 30 percent ofeach other should generallybe considered to be indistinguishable when comparing options," even the data from NDDH's record indicates that the cost ofLDSCRs at MRYS is on the same order as the cost effectiveness ofother sources and should, therefore, be presumed to be cost effective. The Draft BACT Determination states that the cost effectiveness ofsome ofthe facilities that it used for its comparison canbe misleading because Minnkota used the highestremoval efficiency ofany analysis reviewed. As NDDH points out, the NSR Manual does state that an unrealistically low assessment ofthe emission reduction potential ofa certain technology could result in inflated cost effectiveness figures. The NSR Manual explains that the emissions reductions mustbe considered reasonable, and supportable assumptions regarding control efficiencies shouldbe made. Since the emissions reductions that were used in the cost estimates in this case wereproposed by Minnkota and are consistent with current industry trends, itis reasonable to expect the LDSCRs at MRYS to achieve this removal efficiency. Furthermore, the discrepancy in assumed control efficiency can likelybe attributed to MRYS's highbaseline emission rate and thus, ahigherpotential for emission reduction. For example, the baseline emission rate noted in the NDDH determination for Sherco #2 is 0.20 Ib/MMBtu compared to 0.85 Ib/MMBtu for MRYS Unit 1. As such, the SCRtechnology canbe expected to have a higherpercentremoval at MRYS Unit 1 compared to Sherco #2 when the baseline emissions at MRYS are over four times higherthan the baseline emissions at Sherco #2. AfterEPA received NDDH's Draft BACT Determination, it conducted areview ofthe cost effectiveness ofNOx controls at other facilities and areview ofrelevant literature and policy documents related to the cost effectiveness ofNOx controls. The determination ofBACT is based on the pollutant that triggered PSD, in this case NOx, and therefore the cost effectiveness (in dollars perton removed) ofany BACT control for NOx for any type ofsource canbe compared to the cost effectiveness ofany other source ofNOx.' The results ofthis review, which are describedbelow, make it clear that LDSCRis cost effective at MRYS, evenbased upon the inflated cost estimates used byNDDH:

• In 2001, EPA issued guidance related to presumptive BACT for NOx atrefineries being modified to meetEPA's low sulfur gasoline regulation. This guidance used a cost effectiveness threshold of$10,000 perton ofNOx controlled in 2001 dollars. 1o

9. See Enclosure 1. 

### -4-EPAComments onNDDH Preliminary NOx BACTDetermination for MRYS

• The cost effectiveness threshold used for NOx reduction by several California air pollution control districts are substantiallymore than the threshold in this EPA guidance document, ranging from $9,700 to $24,500 perton. I I

• Nebraska, Utah, Alabama, and Oklahomahave each stated that costs below $5,000 per ton will bepresumed to be cost effective. 12

• EPA Region 5 sent letters to Ohio and Indiana finding controls that were more expensive than LDSCR at MRYS to be cost effective. 13

• EPA Region 4 sent letters to Alabama finding controls that were more expensive than LDSCR at MRYS to be cost effective. 14 • A paperpresented at the June 2002 Air and Waste Management meeting reported the results ofa survey ofthe threshold for economic feasibility in the BACT determinations and in the LAER determinations separatelyby state. This surveyreported that Connecticut's BACT Determination average costperton was $9,000, Arkansas's was $5,108, and Michigan's was $22,000. 15

10. See Memorandum fromJohn S. Seitz, Director, OAQPS, to Air Division Directors regarding BACT and LAER for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier 2/Gasoline SulfurRefinery Projects., available athttp://www.epa.gov/ttn/caaaltl/memorandalbactguid.pdf. See also, Delaware Air Regulation Development Committee Meeting #2 Minutes, April 19, 2006, available at http://www.regulations.gov/searchlRegs/home.html#documentDetail?R=09000064807b7424. 11. See SanJoaquin Valley UnifiedAirPollution Control District, Final StaffReport: Update to BACT Cost Effectiveness Thresholds, May 14,2008 available at, http://www.valleyair.orgibusindiptolbactlMaY%202008%20BACT%20cosfl1020effectiveness%20threshold%20upda te%20staff%2Oreport.pdf, See also San Joaquin Valley UnifiedAirPollution Control District, Draft BACT Control Technology Policy, March 1, 2010, (proposing to change BACT threshold for NOx form $9,700 to $24,500), available at http://7l.6.68.10IWorkshops/postingsI2010/03-01-10IDraft%20BACT%20policYOIo20- %20Mar%2020l0%20_2_.pdf. 12. See Nebraska DepartmentofEnvironmental Quality BACT Guidance Document, available at http://www.deq.state.ne.us/Publica.ns£.c4afc76e4e077el1862568770059b73£,0949822f884b8ce1862573bd007daOe 9?OpenDocument, Utah Department ofEnvironmental Quality, BestAvailable Control Technology Summary, available athttp://www.airquality.utah.govlPermits/FORMSlFormOlb.pdf, and Energy and Environmental Analysis, Inc's Regulatory Requirements Database for Small Electricity, available athttp://www.eeainc.comlrrdbIDGRegProjectiStates/AL.htrnl, andhttp://www.eea-inc.comlrrdbIDGRegProjectiStates/OK.htrnl. 13. These letters are set forth in Enclosure 3. Note that the cost effectiveness outlined in these letters should be adjusted to 2006 dollars for an accurate comparisonto LDSCR atMRYS. 14. These letters are set forth inEnclosure 4. Note that the cost effectiveness outlined in these letters shouldbe adjusted to 2006 dollars for an accurate comparison to LDSCR at MRYS. 15. See Enclosure 5. "Comparison ofthe Most Recent BACT/LAERDeterminations for CombustionTurbines by State AirPollution Control Agencies, Paper#: 42752, AWMA Meeting June 2002. Enclosure 4 also contains an email fromthe state ofFlorida explaining that the reportedresults for Florida in this survey reflect the average actual cost effectiveness during the relevant time period, and does notreflect Florida's view ofthe cost effectiveness thresholds. 

### -5-EPA Comments on NDDH Preliminary NOx BACTDetermination for MRYS

• In 2001, EPA and the States ofArkansas, Nebraska, and Utah entered into a Consent Decree withNuCor that stated thatpollution control projects that are demonstrated to cost $5,000 or less perton reduced are presumptively economically feasible. 16

• Wyoming Department ofEnvironmental Quality's Permit Application Analysis for Mountain Cement Company's Laramie Cement Plant considered an average cost effectiveness of$4,540 perton to be cost effective. I? • A review ofinformation in the RACT BACT LAER Clearinghouse revealed at least fourteen facilities in twelve states that identifiedNOx controls that were more expensive than NDDH's estimates ofthe cost effectiveness ofLDSCR at MRYS.18

• The Environmental Appeals Board noted in a 1989 decision that the range ofcosts normally expended for NOx removal was $3,000

- 6,500/ton. After adjusting for inflation, these costs are at least on the order ofNDDH's cost estimates for LDSCR at MRYS. See In the MatterofColumbia GulfTransmission Company, PSD Appeal No. 88-11 (EAB, lun 21, 1989) at 825. Ifapermitting authority compares the cost effectiveness ofa BACT determination today with the cost effectiveness ofaBACT determination from past years, it must considerthe effects ofinflation to properly compare the olderproject to the one under consideration. As more fully set forth in EPA's previous comments to NDDH, anumber ofnational rulemakings, including the Clean Air Interstate Rule (CAIR), the Best Available Retrofit Technology (BART) Guidelines, and revisions to the New Source Performance Standards (NSPS) for Electric Utility Steam Generating Units all supportthe position that SCRis not only technically feasible, but also cost effective for controlling NOx emissions from North Dakota Lignite. NDDH's DraftBACT Determination concluded that "[t]he expected cost effectiveness [ofLDSCR at MRYS] is higher than otherplants where SCRhas been applied as BACT.,,19 The information set forth above clearly demonstrates that even NDDH's inflated cost estimates are on the same order as costs previouslyborne by other sources and mustbe considered cost effective. NDDH's DraftBACT Determination also considered the incremental costs ofLDSCR. The incremental cost effectiveness calculation compares the costs and emissions performance level ofacontrol option to those ofthe next most stringent option. The incremental cost

16. See Enclosure 6. 17. See Enclosure 7. 18. See Enclosure 8. 19. See NDDH's Draft BACT Determination at p. 12. 

### -6-BPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
effectiveness is then determined by the difference in total annual costs between two contiguous options dividedbythe difference in emissions reduction. 20 In In re GeneralMotors, 10 E.A.D. 360, (EAB 2002), the Environmental Appeals Board explained the interplaybetween average and incremental cost. The Board explained that "the DraftNSRManual, while allowing forboth average and incremental cost effectiveness analysis, places primary stress on the average cost measure. See DraftNSRManual at B.31 (BACT cost effectiveness analysis turns on the average and, where appropriate, incremental cost effectiveness ofthe control alternative). Moreover, the Draft Manual cautions that: [U]ndue focus on incremental cost-effectiveness can give an impression that the cost ofa control alternative is unreasonablyhigh, when, in fact, the cost-effectiveness, in terms of dollars pertotal tonremoved, is well within the normal range ofacceptable BACT costs. Id. at B.46. This caution against allowing incremental cost calculations to unjustifiably inflate the cost component ofthe BACT analysis is in keeping with the objective ofthe CAA that less effective control technologies be employed onlywhen the source-specific economic impacts or othercosts prevent a source from using a more effective technology. See generally Senate Debate on S. 252 (June 8, 1977) reprinted in 3 Senate Committee on Environmental and Public Works, A Legislative History ofthe Clean Air Act Amendments of1977, p. 729 (statement ofSen. Edmund Muskie, sponsor ofS. 252, stating thatBACT, while allowing for flexibility based upon source specific factors, is intended to "maximize the use ofimproved technology")." Id. at 370-378 Although it is not clear from the Draft BACT Determination how much emphasis NDDH placed on the incremental cost effectiveness ofLDSCR at MRYS, it is clearthat the incremental cost effectiveness ofLDSCR compared to SNCR is not a valid basis for rejecting SCR as BACT. Since the average cost effectiveness ofLDSCR at MRYS is well within the range ofacceptable BACT costs, it would be inconsistent with the NSR Manual to place undue focus upon the incremental cost effectiveness ofthese controls to reject LDSCR as BACT. Inits analysis, NDDH lists several projects where apermitting agency rejected amore stringent control option and the corresponding incremental cost effectiveness for the rejected technology. It is notpossible to tell from the DraftBACT Determinationhow much weight the permitting agency gave, ifany, to incremental cost effectiveness in the selection ofthe lessstringent option. As noted above, incremental cost effectiveness is not the primary criteriaused in a BACT determination. As such, it should notbe assumed that the permitting agency gave significant weight to incremental costs inthe determinations citedbyNDDH. Moreover, considering the relatively small amount ofemphasis that canbe given to incremental cost effectiveness, making any sort ofdirect comparison ofthe incremental cost effectiveness from oneprojectto the next is difficult atbest.
20. See NSRManual at B.43. 

### -7-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
The only three projects where NDDH states that the more stringentcontrol technology was rejected "based on" incremental cost are the Dry Fork Plant near Gillette, Wyoming (SCR at 0.043 Ib/MMBtu), the ADM facility in Columbus, Nebraska (SNCR achieving 0.05 Ib/MMBtu), and Deseret Powerin Uintah County, Utah (limestone injection and a wet scrubber). The other projects listed byNDDH simply state the incremental cost effectiveness for the rejected control option. NDDH does not state that incremental cost effectiveness was a significant factor in the determination. EPA examined the three BACT determinations that NDDH stated were based on excessive incremental costs. The Draft BACT Determination stated "[t]he State ofWyoming rejected an SCR operating at 0.043lb/l06Btu at the DryForkPlantbased on an incremental cost of$1 0,300/ton.,,21 This statement is incorrect. As more fully set forth above, NDDH sent EPA excerpts ofthe documents that it relied upon to compare the cost effectiveness ofLDSCR at MRYS with other facilities. One ofthese documents included excerpts from the WDEQ Permit Application Analysis for the Dry Forkcoal fired powerplant. EPA obtained a copy ofthe complete document. Page 7 ofthis document, which was not included in the excerpts from NDDH, directly contradicts NDDH's conclusion regarding incremental cost effectiveness, and states "[t]he Division considers the incremental cost effectiveness of$10,303/ton reasonable for an additional 117 tpy emission reduction but does not consider an incremental cost effectiveness of$23,744/ton reasonable for an additional 50 tpy emission reduction.,,22 EPA also reviewed the details ofNebraska's BACT determination for the ADM facility.23 While Nebraska states "$5600 per ofadditional NOx emissions reduction is excessive," itis clearthat incremental cost was not the onlyreasonNebraska eliminated SNCR at arate of0.05 lb/MMBtu and made aBACT determination ofSNCR at arate of0.07 Ib/MMBtu. In fact, Nebraska's analysis states that 0.05 Ib/MMBtu for SNCRis "not considered technically feasible due to the increased opacity and fabric filter plugging from high levels ammonia salt formation." Since the State ofNebraska concluded that it was nottechnically feasible for the facility to meet a 0.05 Ib/MMBtu rate, NDDH cannot conclude that Nebraska rejected this control optionbased upon the incremental cost effectiveness. Nebraska also stated that the reasons why SNCR at 0.05 Ib/MMBtu was rejected as BACT include "opacity increases by 10percentagepoints ormore, ammonia slip level increases above 10ppm increases condensable PM emissions, and the increases in fine particulate matter and ammonia emissions make the proposed BACT limitfor particulate matterunattainable." Even ifthe incremental cost was given significant emphasis by Nebraska, as noted above, $5,600perton is even less than whathas been considered to be cost effective for average costs. Therefore, Nebraska's citation
21. NDDH's DraftBACT Detennination at p. 12. 22. See Enclosure 9. Although itis not clear where NDDH obtained these excerpts orhow it reached a conclusion that is directly contradictedby the plainlanguage ofthe full document, we expectthatNDDH may have obtained these excerpts from EPA's administrative record inthe DeseretBonanzamatter. 23. See Nebraska PSD Pennit for ADM's Columbus, Nebraska facility, p. 148, available at http://www.epa.gov/region07/air/nsr/archives/2006/finalpermits/adm columbus final psd permit.pdf. 

### -8-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
of$5,600pertonbeing excessive for incremental cost effectiveness should be considered an outlier and reliance on this detennination as abasis for incremental cost effectiveness is unwarranted. NDDH's reliance upon Region 8's incremental cost analysis regarding the Deseret BonanzaWaste Coal-Fired Unit (WCFU) is misplaced for several reasons. First, the incremental cost analysis thatNDDH refers to relates to S02, andnotNOx• Second, EPA Region 8's elimination ofwet scrubbing with limestone injection in favor ofdry scrubbing plus limestone injection for S02 BACT at WCFU was not entirely "based on an incremental cost of $10,540/ton," as statedby NDDH. EPA Region 8 noted in its Final Statement ofBasis for the pennit that, in addition to the relatively higher H2 S04fonnation thatresults from a wet scrubber, "[w]etFGD systems also require significantly more water than the dry FGD system. This is an especially important consideration for Deseret's project, which will be located in an arid region ofUtah.,,24 The issue ofwateruse in wet versus dry scrubbing systems is generallyrecognized in S02 BACT detenninations in Region 8 states. While there havebeen someprojects thathave proposed wet scrubbers for largerpulverized-coal units, there have also beenpulverized-coal projects pennitted with dry scrubbing as BACT controls for S02. The issue ofwater use is often cited as why dry scrubbing is selected over wet scrubbing. This is significant in that for pulverized-coal facilities, there is no limestone injectionupstream ofthe control device removing substantial amounts ofS02, as there are with circulating fluidized bed (CFB) boilers, such as that being pennitted for the BonanzaWCFU project. Since there is no limestone injection upstream ofa scrubbing system (wet or dry) for apulverized-coal unit, the selection ofdry scrubbing, with lower S02 removal efficiencies compared to wet scrubbing, becomes even more critical because the difference in overall tons ofS02 removed wouldbe greaterfor pulverized coal units compared to CFB units. Nonetheless, there have been BACT detenninations in the West for pulverized coal fired units that have concluded dry scrubbing is BACT for S02. Dry scrubbing with limestone was the most stringent BACT control option found by Region 8 to havebeen selectedbypennitting agencies for CFB boilers at the time the Bonanza WCFUpennitwas issued,zs In fact, Region 8 stated in its Final Statement ofBasis for the pennitthat it was "not aware ofany CFB boilers equipped with a wet scrubbing system." However, Region 8 did find wet scrubbing to be a technically feasible control option for the BonanzaWCFD. Limestone injection to the CFB boiler with 85% control was assumed in the overall control efficiency ofall add-on control options presented.

24. See Final StatementofBasis for DeseretPowerElectric Cooperative Bonanza Power Plant, p. 96, available at http://www.epa.gov/region8/air/pd£'FinaIStatementOfBasis.pdf. 25. See Final Statement ofBasis for PermitNo. PSD-OU-0002-04.00 pages 97

- 100. Pennits with BACT determinations issued to AES Puerto Rico and Nevco Energy issued 8/10/04 and 10/12/04respectively. Pennit applications had also been submitted for CFB units proposing dry scrubbing (in addition to limestone injection) for Red Trail Energy LLC

- RichardtonEthanol Plant, MDU Co.

- Gascoyne Generating Station and GreatNorthern PowerDevelopment

- SouthHeart. 

### -9-EPA Comments on NDDH Preliminary NOx BACTDetermination for MRYS Finally, the overall control efficiencies listed in the Final Statement ofBasis for wet scrubbing and dry scrubbing (in combinationwith limestone injection) are 99.1 % and 98.8%, respectively. The difference in overall SOz reduction between wet scrubbing and dry scrubbing (in combinationwith limestone injection) was 63 tons per year. In contrast, the incremental NOx emissionreductions between ASOFA plus SCR and ASOFA plus SNCR calculated in the NDDH NOx BACT Determination are 3,439 tons per year for Unit 1 and 5,490 tons per year for Unit 2. This equates to an incremental difference in NOx emission reductions at MRYS compared to the SOz emissionreductions at Bonanza WCFU of55 times more for Unit 1, 87 times for more Unit 2, and 142 times more collectively.
In summary, while it is true that Region 8 did cite "unacceptablyhigh incremental SOz removal costs" in its reasoning for selecting dry scrubbing overwet scrubbing in the Bonanza WCFU SOz BACT determination, it cannotbe said that this decision was "based on" the incremental cost. As described above, there were otherimportant considerations (most notably water conservation in an arid location) that went into this determination. These other considerations were determined by Region 8 to outweigh the additional 63 tons per year reduction that wouldbe achievedby selecting a wet scrubber over a dry scrubber. It should be noted that Region 8's final BACT determination selected the most stringent control technology ofany CFB unit permitted at that time with apermitted level ofcontrol consistent with the most stringentBACT determinations. As such, the $10,540 ton per yearincremental cost cited in this determination shouldnot be viewed as an independent "bright line" value. As noted above, there are many significant differences between the BonanzaWCFU and MRYS projects. Furthermore, as explainedbelow, the non-standard cost methods used in the NDDH Draft BACT Determination undermine the ability to make meaningful comparisons between the incremental costs calculated for MRYS with other similarprojects. 

### II. NDDH's Draft BACT Determination Failed to Follow EPA's NSRWorkshop Manual NDDH was and is required to conduct its BACT determination in accordance with the NSRManual and OAQPS Control Cost Manual (Control Cost Manual). The Draft BACT Determination did not, however, follow the requirements inthese manuals. Rather, it used unauthorized cost methods, included costs for items that are not authorized, and relied upon unreasonably high estimates for anumberofcosts. As more fully set forth below, conservative revised cost estimates conducted in accordance with the NSRManual and Control Cost Manual andbased upon more realistic estimates for a numberofitems cause the cost effectiveness of LDSCR at MRYS to drop to approximately $2,000 perton. Since the significance ofcost effectiveness values is determined by comparing the costs for a given projectto costs at other sources, itis critical thatpermitting authorities throughout the United States follow a standardized approach for determining the cost effectiveness ofcontrols. The NSR Manual explains:

-10-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS Consistency in the approach to decision-making is aprimary objective ofthe top-down BACT approach. In orderto maintain and improve the consistency ofBACT decisions made on the basis ofcost and economic considerations, procedures for estimating control equipment costs are based on EPA's OAQPS Control Cost Manual and are set forth in Appendix B ofthis document. Applicants should closely follow the procedures in the appendix and any deviations shouldbe clearly presented andjustified in the documentation ofthe BACT analysis.26
The Control Cost Manual also emphasizes the importance ofusing a consistent approach to determining the cost effectiveness ofcontrols. The Introduction to the Control Cost Manual explains: The objectives ofthis Manual are two-fold: (1) to provide guidance to industry and regulatory authorities for the development ofaccurate and consistent costs (capital costs, operating and maintenance expenses, and othercosts) for airpollution control devices, and (2) to establish a standardized and peerreviewed costing methodology by which all airpollution control costing analyses can be performed.27
A. 

### Inflated Capital CostEstimates and CostMethods
SCR systems are being successfully applied to virtually every kind ofstationary source (utilityboilers, incinerators, cement plants, glass plants, etc.) and fuel type (coal, biomass, coke, etc.) worldwide. In meeting these varied and significant challenges for the widespread deployment ofSCR technology, system designers must always tailorthe specifics ofSCR application to the varied conditions at each facility and the most suitable location for installing the system. Although there are admittedly some unique aspects ofthe MRYS, almost all facilities that have installed SCRs have had unique design challenges. Capital costs for the installation ofSCR on a coal fired electric generating unit are commonly reported on a dollarperkilowatt ofcapacitybasis. Minnkota's BACT analysis, prepared by Bums & McDonnell (B&McD), which was usedby NDDH to determine the cost effectiveness ofLDSCR, states that the estimated capital cost for LDSCR at MRYS based upon a shared facilities approach was $543/kW for Unit 2 and $525/kW for Unit 1.28

26. See NSR Manual, atB-52 27. See Control CostManual, 2002, Chapter I, Section 1.1. 28. See November 2009 reportby Burns & McDonnell, "NOx BestAvailable Control Technology Analysis Study

- Supplemental Report for the Milton R. Young StationUnit 1, revised February 2010, p. 4-11, and November 2009 reportby Bums & McDonnell, "NOxBest Available Control Technology Analysis Study

- Supplemental Report for the MiltonR. Young Station Unit 2, p. 4-11. 

### -11-EPA Comments on NDDH Preliminary NOx BACTDetermination for MRYS
In its BACT analysis, B&McD stated that a costrange for conventional high-dust SCRwas reported as between $55 and $150/kW?9 On February 16,2006, PowerGen magazine reported the results ofsurvey ofSCR capital costs. The survey was conducted by the Electric Utility Cost Group, and included responses from 72 individual units totaling 41 GW (representing 39% of installed SCR systems inthe U.S. by MW at the time ofthe study). The results ofthis survey showed that costs were generallyreported to be in the $100 to $200/kW (in 2006 dollars) range forthe majority ofthe systems, with only three reported installations exceeding $200/kW.30 Although some studies have reported slightlyhighercosts, most have reported results that are generally within this range.3) Furthermore, two PSD permit applications submitted to NDDH in 2005 and 2006 for CFB utilityboilers contemplated SCRs downstream ofa dry scrubberand baghouse (TESCR) and included estimated capital costS.32 The estimated capital costs for these two projects ranged from $1 17/kW to $132/kW. Since these units were designed to bum North Dakota lignite and are very close in size to MRYS Unit 1, it is unclearwhy the estimated capital cost for MRYS Unit 1 are about fourtimes higher than what was reported in those permit applications.33
The fact that B&McD estimated capital costs for the LDSCRs at MRYS are so much higherthan the capital costs at otherfacilities calls the reliability ofthese cost estimates into question. The reliability ofthese estimates becomes more questionable in light ofthe fact that a numberofextremely complicated and challenging SCR installations have had capital costs well below the cost estimates for LDSCR at MRYS. There are at least two cold side SCRs that have recently been installed in the United States that should be considered as arelatively reasonable comparison. In 2007, Washington Group International prepared an "Emission Reduction Study" that evaluated what would be the most cost effective SCR configuration at the WE Energies South Oak CreekUnits 5, 6, 7 and 8. Thereport concluded that retrofitting the units with coldside LDSCRs was determined to be the least expensive option and predicted capital costs for the SCR systems of$190,500,000 total for all units. This comes outto approximately $168/kW for the SCR equipment alone onthe combined 1,135 MW at the facility.34

29. !d. 30. See M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. http://www.powermag.comlcoaVEstimating-SCR-installation-costs

_506.html. The reported range of$100

- $221/kW. 31. See Enclosure 10. 1. Edward Cichanowicz, Current Capital Cost and CostEffectiveness ofPower Plant Emissions Control Technologies, June 2007. 32. See Enclosure 11. August 18, 2005 Application to Permit to Construct

- South Heart Power Project, page 4-16 and June 2006 Gascoyne 500 Generating Station and Gascoyne Mine Application ForA PermitTo Construct And Air Quality Technical Analysis. 33. Although NDDH rejected TESCR for these projects due to high cost effectiveness, these examples illustrate how exceptionally high the B&McD estimates are for capital costs. 34. See Enclosure 12. WE Energies submitted informationto the Public Service Commission (PUC) ofWisconsin indicating that the cost ofits SCR system was higher than the costs identified in this study. Even ifthe costs from the PUC submittal are used to calculate the costperkW, however, these costs are significantly below Minnkota's estimated capital costs. -12-EPA Comments on NDDH Preliminary NOx BACTDetermination for MRYS

PSE&G also retrofitted its MercerUnits 1 and 2 with cold-side SCRs. The capital cost for these retrofits was about $120 million.35 This comes out to approximately $1 851kW. Although EPA and NDDH asked Minnkota to conduct a general comparison ofthe capital costs ofinstalling SCR at MRYS with the costs ofLDSCR at these units, Minnkota declined to conduct this comparison. Minnkotahas not explained the fact that the estimated capital costs for LDSCR and TESCR at MRYS are so muchhigherthan any other SCR systembuilt, including the LDSCR systems for Oak Creek and Mercer Stations. B&McD implies that the unique nature ofthe application ofSCR at MRYS creates a situationwhere seemingly no comparison to another SCR installation is appropriate. As noted above, even ifan SCR installation at MRYS would provide unique challenges because ofthe different fuel orboilertype, this would notresult in capital costs that are over one and ahalftimes as high as the upper end ofSCR installations with the highest degree ofretrofit difficulty. The differences for the basic capital cost equipment at MRYS would notbe expected to differ from other SCR installations on the scale estimatedby B&McD and no reasonable explanation has been providedbyMinnkota for the large disparity. As such, close examination ofthe stated costs mustbe conductedbyNDDH tojustifythe costeffectiveness in its BACT determination. EPA has examined these costs based onthe information available during the public notice period and believes that the B&McD analysis that NDDH relied upon included redundant costs, insufficientjustification for some ofthe cost estimates, and many components in the cost methodology used to calculate Total Capital Investment that are unauthorized, inappropriate, and inconsistent with the Control CostManual orotherEPA-approved methods. When these items are taken into account, it is clearthat the cost values submitted by Minnkota and adopted into the Draft BACT Determinationresult in a calculation ofcost effectiveness that is grossly inflated and ill-suited for comparisons with otherBACT determinations. First, as explained in detail inMr. Hans Hartenstein's April 2010 expert report36

, many of the assumptions and designparameters thatB&McD specified to SCR system and catalyst vendors resulted in excessive equipment components and sizing ofthe SCR system and the auxiliary/balance ofplant components, which drove up materials and labor costs. Ifthe system was designed to minimize capital costs, the general design would be different and the cost of materials and laborwould be much less. Furthermore, there appears to be redundancy for some items that were included as "SCR System Equipment" and "Auxiliaries/Balance ofPlant" costs.

35. See PSG&E press release at: http://www.pseg.com/media center/pressreleases/articles/200612006-11-30.jsp. EPA verified the capital costs with communications with the New Jersey Department ofEnvironmental Protection and Mr. Hans Hartenstein. 36. See Enclosure 13. Portions ofthis enclosure are subjectto a confidentialbusiness information claimand will be submitted separately and noted as CBI. 

### -13-EPA Comments on NDDH Preliminary NOx BACTDetermination for MRYS
Forexample, the "Auxiliaries/Balance ofPlant" costs include "SCRbypass ducts and isolation dampers." The SCR system vendor thatprovided apricing proposal, which appears to havebeen directly used by B&McD for the "SCR SystemEquipment" cost, included an SCR system with "gas bypass for maintenance." Although vendor information can be used instead ofthe capital cost equations detailed in the Control CostManual, Minnkotahas notprovided abasis for the "Auxiliaries/Balance ofPlant" costs, which are 80% ofthe "SCR System Equipment" costs. Perry's Chemical Engineering Handbook, 6th Edition (Table B2) uses factors related to total equipment costs which would be similarto the "SCR System Equipment" used in the B&McD analysis. Perry's adds 55% to equipment costs for auxiliaries compared to B&McD's 80%. The redundancies and comparatively high costs used for "Auxiliaries/Balance ofPlant" thatNDDH relied upon in the Draft BACT Determination are unreasonable and not supportedby the record without furtherjustification. Another major concern is the degree to which the B&McD capital cost analysis deviates from the Control Cost Manual methodology and includes numerous indirect cost and other accounting mechanisms that are not included inthe Control Cost Manual and not adequately justified. Minnkota's February 11,2010 submittal claims that, "Bums & McDonnell used standard estimatingpractices to estimate direct, installation, and indirect capital costs for MRYS Unit l's and Unit 2's hypothetical application oflow-dust and tail end technologies." While these estimatingpractices may be standard for use by B&McD orthe utility industry for internal justification or other accountingpurposes, they are not appropriate for use in the context ofthe BACT analysis. The standard approach is outlined inthe Control Cost Manual, so that comparisons ofcost-effectiveness canbe made with otherprojects nationally. B&McD's approach undermines the ability to make these comparisons. 37
For example, B&McD calculated total indirect capital costs that equal about 50% ofthe total direct capital costcompared to the Control Cost Manual which uses 20%. Ofthis 50%, approximately 15% is listed as a "scope contingency" and another 15% is listed as a "pricing contingency." The Control Cost Manual includes two contingencies for SCRs. The first is a "process contingency" that is calculated as 5% ofthe direct capital costs. The second is a 15% "projectcontingency" and is not considered to be part ofthe indirect capital costs. B&McD indicates that its "pricing contingency" is equivalent to the "projectcontingency" inthe Control Cost Manual. B&McD's "pricing contingency" will actually be somewhat lowerthan the Control Cost Manual's "project contingency" because, unlike the "project contingency" ofthe Control CostManual, the 15% is not appliedto the indirect capital costs. The "project contingency" ofthe Control Cost Manual is calculated as 15% ofthe total direct plus indirect
37 Enclosure 14 is an example ofa cost analysis submitted to NDDH as part ofa BART submittal that does not include many ofthe indirect capital costs and contingencies included in B&McD's analysis. Although EPA may not be in agreement with every aspect ofthe costanalysis inthe example, it does illustrate a case where the Control Cost Manual format is generally followed and the estimated capital costs are far less (by a factor ofalmost 4 for LDSCR onUnit 2, which is a smallerunit in comparison to the example and should cost less) than what was estimated for MRYS. 

### -14-EPAComments on NDDH Preliminary NOx BACTDetermination for MRYS capital costs. However, B&McD's "scope contingency" of 15% is significantly higher than the Control CostManual's 5% "process contingency." Assuming, as B&McD did, that the "project contingency" is part ofthe indirect capital costs, it would equal 18% ofthe direct capital costs and the total indirect capital costs for the Control CostManual would equal 38% ofthe direct capital cost compared to 50% ofthe capital costs in the B&McD.38 There are other discrepancies between B&McD's indirect costs and those in the Control CostManual. These differences are tabulated below.
39 

### COl C I&B&M DI dO IC M 

### fC T bi 1 C



### a e ° 

### ompanson 0 ontro ost anna c n Irect apIta osts Indirect Capital Costs Control CostManual B&McD Analysis Comparison (% ofDirectCap Cost"A") (% ofDirectCap Cost "A") General Facilities 0.05XA 0.04XA B&McD 1% Lower (Construction Mgt) Engineering & Home 0.10XA 0.15XA B&McD 5% Higher Office Fees Startup Expenses 0 0.02XA B&McD 2% Higher Process Contingency 0.05XA 0.15 X A B&McD 10% Higher (Scope Contingency) Project Contingency 0.18XA 0.15XA B&McD 3% Lower (Pricing Contingency)

.0- • ).Ai0ci":\' .. + \T

### 'JI~l\'IcI)lJ~ [";L O.3S:X:A 

### O.51··X.A,."

.**·;\;~;I** :i: .ili i:.;:

.:. !• :T.:;

..**Hjf!IJ..~i·** 

# ; While this difference of 13% is significant, B&McD then adds two more contingencies ("cost escalation during project" and "owner's costs

- other") and includes an allowance for funds during construction (interest) before calculating the total capital investment. The Control CostManual allows for "preproduction costs" of2% ofthe total direct, indirect capital costs, and the "project contingency." Table 2 below compares these "other" costs used by B&McD and the preproduction costs in the Control CostManual. To nonnalize these costs with those tabulated above, percentages were convertedbackto the direct capital costs ("A,,).40

38. Perthe Control CostManual, indirect capital costs = 0.2 times the direct capital costs. So, 15% ofthe total of direct capital costs plus indirect capital costs = (1.2 

### * direct capital costs) (0.15) = 18% ofdirect capital costs. 39. Although, B&McD stated in their December 11,2010 submittal that theirBACT cost estimates "followthe outline ofTable 2.5 in the SCRChapter ofEPA's Control CostManual," many items do not match in description, so some assumptions had to be made. Where there are differences, the B&McD cost is inparentheses. Also, as noted above, this comparison assumes that "projectcontingency" of 15% is part ofthe indirectcosts, so when applied exclusively to the direct capital costs only, itbecomes 18%. 40. Preproductioncosts are listed as being 2% ofthe total direct (A), indirect (B), and "project contingency" (C) costs. This becomes 3% ofthe total direct capital costs. (B = 0.20 

### *A; C = 0.18 

### *A; A + B + C = 1.38 A; 0.02 

### * 1.38 A = 0.03). -15-

### Table 2. Com EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS


### arison ofEPA Control CostManual & B&McD "Other" Ca ital Costs Other Costs Cost Escalation Control Cost Manual B&McD Analysis % ofDirect Ca (% ofDirect Ca Cost "A" 

## o 0.30 XA Comparison B&McD 30% Higher Allowance for Funds During Construction (Interest During Construction) Preproduction Costs Owners Cost

- Other (Owner 

## o

0.03A 

## o 0.20XA


## o 0.17X A B&McD 20% Higher

B&McD 3% Lower B&McD 17% Higher

Based on Tables 1 & 2 above, the B&McD cost analysis methodology results in capital costs that are higherby a factor ofabout 1.8 (0.13 

### + 0.64 higher) than what would be calculated using the Control Cost Manual, assuming the same base costs for total direct capital costs. As noted above, the total direct capital costs used by B&McD appears to be overestimated. A large portion ofthis discrepancy comes from the "other" costs added by B&McD (Table 2) that are not included in the Control CostManual. These appearto be strictly contingencies and accounting items which would not be at all unique to MYRS and, therefore, are notjustified in the analysis. These accounting items are unauthorized underthe Control Cost Manual, create an unlevel playing field for comparison with otherBACT analyses and alone account for an increase in .capital costs from the Control CostManual by a factor of 1.6. Although NDDH asked B&McD to provide a detailed explanationregarding its high indirect capital cost estimates, B&McD's February 11,2010, response to this request fails to justify why the B&McD cost methodology should be allowed for the MRYS BACT analysis, when it is not partofthe Control CostManual and is not the standardized methodology used by other sources. While the Control Cost Manual does contemplate some flexibility in some contingencies (such as degree ofretrofit difficulty), B&McD has not substantiated the need to go beyond standard contingencies applied through the Control Cost Manual. As stated in the Control Cost Manual, "[c]ontingencies is a catch-all category that covers unforeseen costs that may arise, such as possible redesign and modification ofequipment, escalation increases in cost ofequipment, increase in field laborcosts, and delays encountered in start-up."4l Thus, the contingency in the Control Cost Manual should already account forpossible changes in labor costs, and inclusion ofacontingency plus escalation ofcosts is redundant according to the Cost Manual Methodology. Escalation ofcosts should not be included as a separate estimate in the estimate ofTotal Capital Investment since it is included as part ofthe contingency estimate. In Table 2.5 ofthe SCR chapterofthe Control CostManual, the "Allowance for Funds During
41. See Control CostManual, 2002, Chapter 2, Section 2.3.1. -16-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
Construction" (inflation) is specifically listed as zero. It is unclear then why B&McD added what amounts to 20% ofthe direct capital costs to coverinflation. Including "owner's costs" and "owner's contingency" is also not consistent with the Cost Manual Methodology and appears to be redundant. B&McD mentions that it is anticipated that significant retrofit workwill be required which will affect the scope andprice oftheproject. However, there have beenmany SCR retrofits facing muchmore difficult challenges with space limitations and boilermodifications than MRYS can be expected to face installing a LDSCR orTESCR downstream ofthe ESP (or FGD) in arural location. The contingencies outlined in the Control Cost Manual (5% process contingency and 15% project contingency) are sufficient forpurposes ofthe BACT analysis. 

### B. Inflated Annual Cost Estimations & 

### CostMethods In addition to the inflated capital cost estimates and inappropriate costmethods used by B&McD in the MRYS "BACT analysis thatNDDH relied upon, B&McD also used inflated and unjustified cost estimates for annual costs and used costing methods that are unauthorized by the Control Cost Manual. Below are some ofthe issues identifiedby EPA. These are listed following the numbering scheme in the detailed itemized B&McD BACT cost analysis submitted December 11,2009 and updated February 11, 2010. (1) Annual Maintenance Costs: B&McD uses a factor of3% ofthe installed capital costs ofthe SCR equipment and auxiliary equipment. The Control Cost Manual uses a factor of1.5% oftotal capital investment. Nojustificationwas given by B&McD for using a cost factor that is twice as high. (2) Annual Reagent Costs: As stated inNDDH's January 11, 2010, letterto Minnkota and in Mr. Hartenstein's expert report, the choice to use urea instead ofanhydrous ammonia drives up annual costs. As also stated in Mr. Hartenstein's expertreport, the reasons given by B&McD in the February 11,2010, response to NDDH are not unique to MRYS and do not constitute justification for choosing the more expensive reagent. Since excessive cost is the main reason citedby NDDH for not selecting the top level ofcontrol as BACT and there is a less expensive option that is available, the analysis shouldbe redone using anhydrous ammoma.



### -17-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS (3) Annual Electricity Costs: In its February 11, 2010, response to NDDH, B&McD provided an explanation ofthe electricity costs associated with extended outage periods for catalyst replacements and ASOFA maintenance.42 In its analysis, B&McD estimates the following times for various stages ofcatalyst replacement: 1) Reactor Cool Down: 2) Installation into spare catalyst layer: 3) Removal ofspent catalyst and installation offresh catalyst: 4) Reactorheating for startup: Total (Items 1,2 & 4): 48-60 hours 128 hours (16 shifts

- one time event) 192 hours (24 shifts) 36-48 hours 276-300 hours Conservatively assuming that one spent catalyst is always removed when a fresh catalyst is added and disregarding the unreasonable assumption that only two shifts per day would be used to perform the work while the unitremains idle, the range oftotal outage time estimated by B&McD to cool down the reactor, exchange catalyst, and reheat the reactor is 276

- 300 hours, or 11.5

- 12.5 days. This does not include the 96 hours (or four days) ofregular scheduledboilercleaning downtime that shouldbe subtracted from these totals. When this is accounted for, there would be a maximum of204 hours for each catalyst exchange in excess ofnormal downtime for each unit. Evenunder B&McD's unwarranted "Scenario B" assumption that catalyst is replaced three times per year for Unit 1 and four times per year for Unit 2, this equates to a maximum of900 hours peryear ofcatalystreplacement time for Unit 1 and 1,200 hours peryear for Unit 2. This does not include the 96 hours (or four days) ofregular downtime that should be subtracted from these totals for each outage period. When this is accounted for, there would be a maximum of612 (900

- 288) hours peryear for Unit 1 and 816 (1,200- 384) hours peryear for Unit 2 under B&McD's worst case scenario. B&McD states that the excess downtime for SCRcatalystreplacements under "Scenario A" would be 213 and 256 hours for Unit 1 TESCR and LDSCRrespectively, and 206 and 247 hours for Unit 2 TESCR and LDSCRrespectively. It is unclearhow B&McD carne up with these values considering they are higher than the high end total ofwhat was outlined for each stage ofthe catalyst replacement once subtraction was made for normal boilercleaning (maximum of204 hours).

42. The NSRWorkshop Manual states: "Lostproduction costs are not included in the costestimate for anew or modified source." Appendix B, p.ll. Forthepurpose ofthis analysis, EPA is assuming lostproduction is included in the costestimate. -18-EPA Comments on NDDH Preliminary NOx BACT Detennination for MRYS

Furthennore, B&McD states that the excess downtime for SCR catalyst replacements under "Scenario B" would be 980 and 938 hours for Unit 1 LDSCR and TESCR respectively, and 1,234 hours for Unit 2 (LDSCR and TESCR). Again, it is unclearhow B&McD came up withthese values considering they are higherthan the high end total of what was outlined for each stage ofthe catalyst replacement, even ifno time ofthe outage was subtracted for nonnal boilercleaning (900 hours for Unit 1 and 1,200 hours for Unit 2). Whenthe subtraction for nonnal boilercleaning is made, there is an even largerdiscrepancy between B&McD's estimations and what was outlined for each stage ofthe catalystreplacement (612 hours for Unit 1 and 816 hours for Unit 2). While B&McD's additional outage times do not appear to correspond to the sum ofthe catalystreplacement steps outlined in their February 11,2010, submittal, they also do not appearto reflect the infonnation they received from SCR system and catalyst vendors and their consultants. The infonnation received from these sources is addressed below. Reactor Cool Down: Based on a September 29,2010, email from Babcock & Wilcox Construction Co. Inc., Minnkota was advised that "we typically see 36 to 48 hrs before entering the SCR." It is unclear why B&McD used 48-60 hours (although, as noted above, even using the high end oftheirrange, the additional outage times statedby B&McD seem to exceed what wouldbe calculated.) EPA believes 48 hours for reactor cool down would be a conservative estimate. Catalyst Exchange: According to a September 15,2009, email, B&McD's consultant Fuel Tech's, '''rule ofthumb' estimate for catalyst installation is thirty (30) minutes per module." This is based on conventional access, use ofhoists for module handling and transport, and atypical crew of4 to 6 people. With different system design and more personnel, the time period can certainly be reduced." As stated in Mr. Hartenstein's expert report, "[b]ased on the catalyst designs from HTI and CERAM submitted to Minnkota, the number ofmodules per layerranges from 96

- 104 for Unit 1 and 162

- 182 for Unit 2. Using the stated conservative 'rule ofthumb' estimate ofthirty minutes permodule, this equates to maximum time of2.2 days for Unit 1 and 3.8 days for Unit 2 to replace alayer ofcatalyst. As stated by Fuel Tech, this 'rule ofthumb' estimate could be further reduced through design and personnel." This equals amaximumof52 hours for Unit 1 and 91 hours for Unit 2. Based on B&McD's February 11, 2010, submittal the difference in time between removing spent catalyst (16 shifts) and the removal ofspent catalyst and installing fresh catalyst (24 shifts) is 64 hours.

-19-EPA Comments on NDDH Preliminary NOx BACTDetermination for MRYS So, the maximum total time for removing a layer ofspent catalyst and installing fresh catalyst is as follows: Unit 1: 64 hours 

### + 52 hours = 116 hours Unit 2: 64 hours 

### + 91 hours = 155 hours These are both lowerthan the time described inthe February 11, 2010, response for removing spent catalyst and installing fresh catalyst (192 hours) Again, even using the apparently inflated value of192 hours, the additional outage times statedby B&McD seem to exceedwhatwouldbe calculatedusing these values. Reactor Preheating for Startup: B&McD has stated this will take 36-48 hours. Based on the very conservative nature oftheir otherestimates and the comments in Mr. Hartenstein's expertreport on this subject, EPA believes 36 hours for reactor preheating would be a conservative estimate. Using the information supplied to B&McD andMinnkota from SCR system and catalyst vendors, and B&McD's consultants, EPA calculates that a conservative total estimate of excess downtime (subtracting the four days for normal cleaning downtime) from bringing the unitdown, to replacing spent catalystwith fresh catalyst, to bringing the SCRback online for one layerofcatalyst exchange is as follows:
T bl 3 EPA Eft C tit E h 

## r

a e 

# . sIma es or aa s xc ange Imes Replacement Step Time Unit 1 Time Unit 2 (hours) (hours) Reactor Cool Down 48 48 Spent CatalystRemoval and 116 155 Installing Fresh Layer ReactorPreheating for Startup 36 36 Subtract Scheduled Downtime -96 -96 EPA Total Estimate 104 143 B&McD Estimate (S, A) 213-247 206-247

•**'~,:;~J!: ';'~;;;;,;;;**  ":,;;;" .,,;;ii;';**t,""()9~143** 

## ' ;:Cc.""r,
..**"~;ii~L;'i;J0;'** ; .1:'1=:inA ii ',; ',:.;;;;, As canbe seen from Table 3 above, B&McD's estimates for catalyst exchange times are overtwice as high for Unit 1 and over 50% higher for Unit 2 when compared to EPA's estimates (which were based directly on the informationprovided to Minnkotaand B&McD by vendors and consultants). Furthermore, B&McD added an additional 181-188 hours peryear to the annual electricity costs for extra downtime due to advanced separated overfire air (ASOFA)
-20-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
maintenance. Even assuming these values are realistic and necessary, which shouldbe justifiedbyMinnkota, since the more realistic EPA estimates for catalyst exchanges for both Unit 1 and Unit 2 are less than the stated ASOFA maintenance times, it shouldbe assumed that the SCRmaintenance wouldbe performed at leastpartially within the same time allotted for ASOFA-related maintenance. B&McD gives no explanation as to why the outage times for ASOFA and SCR are cumulative and the work could not be scheduled and conducted concurrently. Onepossible reason wouldbe ifthere were short interruptions required for ASOFA maintenance that did not correspond with the normal unit cleanings. This seems unlikely (especially for 181

- 188 hours per year) and B&McD has not indicated that this wouldbe the case normally. Appendix C3 ofthe original 2006 NOx BACT Analysis provides the onlybasis that EPA can find for including any ASOFA downtime. Page C3-3 describes lost availability due to "forced or extended scheduledboiler outages thatmay result from problematic cyclone slag tapping operational conditions encountered during substoichiometric cyclone operation with SOFA." These times should bejustified, as well as the need to conduct this maintenance at a different time from the normal boilercleanings and/orthe SCR catalystreplacements. Ifit is found that ASOFA maintenance times can fall within the same normal boiler cleaning outages, B&McD's cost estimate must subtract all electricity costs attributed to extended outage times for catalystreplacements accordingly. Finally, it appears that for "Scenario A", B&McD did not take into account that the catalyst exchanges will not be occurring each year. Since they will be occurring approximately every otheryear, these costs need to be adjusted to an annual basis. (4) Annual Water Costs: No comments. (5) CatalystReplacement Costs: Based on Note 5 in the detailed itemized B&McD BACT cost analysis submitted December 11, 2010, and updated February 11, 2010, B&McD assumed acatalyst price of $7,500 per cubic meter (in 2006 dollars) in calculating annual catalystreplacement costs. This assumption appears to be significantlyhigher than either ofthe bids the two catalyst vendors provided to Minnkota. Furthermore, this value is also substantially higher than two ofthe three vendorbids received by Mr. Hartenstein's in response to his vendor inquiry. It is unclearwhy B&McD used aunit catalystprice higherthan any vendorbid theyreceived for their BACT analysis. While ahigherunitprice may bejustifiable for TESCR compared to LDSCR, it appears from Note 5 that B&McD used the sameprice for LDSCR and TESCR. Sufficient detail is notprovided on how adjustments were made for the different volumes required for each catalystreplacement in aLDSCR and TESCR application. -21-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS Furthennore, B&McD did not seem to considerthe use ofregenerated catalystin pricing catalystreplacements. Catalystregenerationhas been in practice in the utility industry for years to help save SCR maintenance costs and typically costs less thanhalfofwhat new catalyst would cost. Ifthere is some reason Minnkota cannot use regenerated catalyst at MRYS, this shouldbejustified. (6) Natural Gas for Flue Gas Reheating & Urea Conversion System: As noted above and inMr. Hartenstein's expertreport, EPA questions whethernatural gas needs to be used instead ofsteamto reheat flue gas and whetherurea needs to be used instead ofanhydrous ammonia at MRYS. See Mr. Hartenstein's expertreport for more infonnation. (7) Operating Laborfor SCR: EPA agrees that no operating labor (or supervisory labor) shouldbe included, consistent with the Control CostManual. (8) Annual Costs for Capital Recovery: Based on greatly inflated capital costs (addressed extensively above), the annual capital recovery cost is likewise greatly inflated. (9) Administrative Overhead, Insurance, Taxes, etc.: No comments. In addition to the above comments, the levelized total annualized cost approach usedby B&McD is inappropriate, as itis inconsistent with the Control CostManual. Based onNote 15 in the detailed itemized B&McD BACT cost analysis submitted December 

### 11,2010, and updated February 

### 11, 2010, B&McD increased the total direct annual costs (all annual costs with the exception ofcapital recovery) by a factor of1.25. While these estimatingpracticesmaybe standard for use by B&McD orthe utility industry for internaljustification orother accounting purposes, they are not appropriate for use in the context ofthe BACT analysis. The standard approach is outlined in the Control CostManual, so that comparisons ofcost-effectiveness can be made with otherprojects nationally. B&McD's approach undennines the ability to make these comparisons. The Control Cost Manual methodology provides estimates ofoperation and maintenance that do not change with interest rate and equipment life. The equivalentunifonnannual cost estimates from the Control CostManual are equal across the life ofthe equipment. Changing the interestrate and equipmentlife will change the annualized capital cost estimate, but should not 

### -22-.,. EPA Comments on NDDH Preliminary NOx BACTDetermination for MRYS change the annual operation and maintenance costs. The Control CostManual procedure provides real estimates ofcosts (that is, inflation-adjusted), and notnominal costs. C. EPA Corrected Cost Analysis Due to the inflated nature ofB&McD's cost estimates, EPA conducted an independent cost analysis for LDSCR and TESCR at MRYS. This analysis consisted oftwo parts. The first was to request budgetaryproposals from several catalystvendors on catalystperformance guarantees (NOx removal, initial catalyst life, and ammonia slip), catalystvolume and dimensions, catalyst exchange diagrams up to approximately 100,000hours, and catalystprice. The Request for Proposal (RFP) was based on what EPA believes to be representative flue gas characteristics and design specifications for a LDSCR on Unit 1 and a TESCR onUnit 2. Mr. Hartenstein was hiredby the Department ofJustice to perform this work onbehalfofEPA. The RFP was sentto three catalyst vendors (CERAM, Johnson Matthey Catalysts (JMC), and HaldorTopsoe) on March 3, 2010. While the facility inthe RFP was not identified as MRYS, the flue gas characteristics in the RFP were based on relevant actual flue gas parameters found at MRYS, including recent stacktest information for Unit 1 and Unit 2 and the 1983 Markowski data on particulate matter concentrations and compositions data for Unit 2. Furthermore, it was clearly stated in the RFP that the majority ofthe sulfates within the particulate matter are expected to be sodium and potassium sulfates. Upon request from two catalystvendors (CERAM and JMC), atypical coal composition ofCenterlignite was provided. Responses from all three vendors were receivedbetween March 12 and March 31,2010. As noted in Mr. Hartenstein's expertreport, all three catalyst vendors were able to provide an initial catalyst life guarantee of24,000 operating hours in response to the RFP, as well as providing catalyst size and price specifications at the guaranteedNOx and ammonia slip rates. More detail is provided in Mr. Hartenstein's expertreport. The RFP and the vendorresponses are also attached.43
The second part ofthe EPA's independent cost analysis was to calculate SCR cost effectiveness (dollars perton) based on the Control CostManual orother appropriate methods using the relevant cost information obtained from the vendor survey conductedby Mr. Hartenstein incombinationwith appropriate information in the B&McD cost analysis. For this effort, EPA hired ERG as consultants.

43. See Enclosure 15. Request for Proposal and Vendor Responses. Portions ofthis enclosure are subject to a confidentialbusiness infonnation claimand will be submitted separately and noted as CBI. -23-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
ERG first evaluated the cost factors and methodology used by Minnkota and made a comparisonwith the cost factors and methodology used inthe Control CostManual. To cross checkthe Control CostManual results, ERG also compared cost factors and methodology used by Minnkota to those used in Perry's Chemical Engineering Handbook 6th Edition (Perry's). To make these comparisons, ERG used the capital and annual costtables for shared facilities in Minnkota's December 11, 2009, submittal. Forthe capital costs, ERG back-calculatedthe cost factors B&McD used to escalate SCR equipment costs to a final capital cost number. This calculation showed that for the B&McD analysis:

• The cost for auxiliarieslbalance ofplant is approximately 80% ofthe SCR costs.

• Capital constructions costs are approximately 50% ofcapital equipment costs (SCRplus auxiliaries).

• Indirect capital costs are approximately 50% oftotal capital costs.

• B&McD added another47% to the capital plus indirecttotal to account for cost escalation, interest, and owner's costs. ERG then compared these cost factors withpercentages used in the Control CostManual, as well as Perry's. The comparison oftotal capital costs calculatedby B&McD andthe Control CostManual is described in detail above underthe capital cost analysis. Perry's uses costs factors that are applied to total equipment costs. These total equipment costs would be considered equivalentto the SCR system cost used by B&McD's methodology. Comparing the B&McD and Perry's cost factors shows:

• Perry's adds 55% to equipment costs for auxiliaries compared to B&McD's value ofapproximately 80%.

• Total direct costs in Perry's are 2.3 times the SCR system costs while the B&McD total direct costs are about 2.7 times the SCRcosts.

• Forthe indirect line items included in B&McD's cost table, Perry's adds 56% to the direct costs which is similarto Minnkota's value ofapproximately 50%.

• Perry's does not include the factors B&McD added to the capital plus indirectto account for cost escalation, interest, and owner's costs. Because B&McD's cost factors are higherthan boththe Control Cost Manual and Perry's factors, EPA calculated two additional capital cost cases for comparison. Both cases used the same format as in B&McD's estimate, butusedthe Control Cost Manual and Perry's cost factors, where available. ERG used the 2009 B&McD's SCR costs which were back-calculated from the 2018 costs provided by Minnkota.44 As can be seen from Table 4 and Figure 1, the capital costs estimatedby B&McD forMinnkota are much higher thanboth the Control Cost Manual and Perry's. The Control CostManual and Perry's methods compare favorably.

44. EPA strongly disagrees withB&McD assumption that the SCRinthis matter will notbe installed until 2018. 

### -24-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS

Table 4. Capital Cost Comparison Capital Costs (2009, 1,000$) Low Dust Ul Low Dust U2 Tail End U1 Tail End U2 Minnkota $146,753 $254,175 $192,830 $329,150 OAQPS $91,114 $162,999 $120,629 $212,529 Perry's $87,613 $147,699 $108,416 $196,954

Capital Costs (2009; 1,000$)
$350,000 -,-------------------------------,

$300,000**~-----------------------**

$250,000**~--------**

$200,000 +-----------

$150,000 +---==;-------

$100,000

$50,000

$0 • Minnkola .OAQPS o Perry's

Low Dust U1 Low Dust U2 Tail End U1 Tail End U2 Figure 1: Comparison ofCapital Costs Using Different Cost Methods ERG then perfonned a new cost analysis that calculated capital and annual costs using the Control Cost Manual methodology and factors where applicable along with B&McD's original SCR equipment costs and other cost data that could not be independently verified by EPA within the time allowed (auxiliaries/balance ofplant, construction costs, natural gas pipeline, reagent costs, natural gas costs), supplemented with other cost data and assumptions provided by EPA. While EPA could not independently verify many ofthese costs, they were included to produce an estimate that may overestimate actual costs, but is conservative in a manner favorable to Minnkota. EPA provided ERG with different infonnation regarding catalyst volume, catalyst cost, catalyst replacement frequency, and estimated additional outage time for 

### -25-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS replacing spent catalyst. A conservative value for catalyst cost of$6,000 per cubic meter was used. As noted above, this cost could be significantly reduced ifregenerated catalyst was used. Contingencies were calculated using the Control Cost Manual assumptions. The maintenance costs were adjusted using the cost factor in the Control Cost Manual and annual costs were not "levelized" as done in the B&McD analysis. ERG used the above information and calculated annual costs. ERG calculated four different catalyst replacement scenarios. Scenarios 1 through 3 assume catalyst replacement of one layerper year, one layer every two years, and one layer every three years. EPA believes Scenario 3 is the most appropriate, as it reflects the performance guarantees provided by three catalyst vendors in response to Mr. Hartenstein's RFP and the proposals provided to Minnkota by one vendor. No calculations were made for the "Scenario B" assumptions used by B&McD because, as EPAhas stated previously and is well-documented in Mr. Hartenstein's expert report, these assumptions are unsubstantiated and arbitrary. ERG's Scenarios 1-3 do not include downtime for ASOFA because this has not beenjustified by Minnkota. Scenario 4 was run as the "worst-case" scenario and assumes all ofthe additional outage time is based on the additional outage times estimated for ASOFA provided by B&McD. There would be no additional unit outage time (and associated electricity costs) for catalyst replacement, because all ofthis work could be completed within the time allocated for ASOFA maintenance. As noted above, EPA does not necessarily concur that these additional outage times for ASOFA are legitimate and believes they should bejustified by Minnkota. ERG modified the amount oftime required for each catalyst layer replacement from B&McD's assumptions, recalculated the unit availability using the revised downtime, and recalculated electricity costs and corresponding NOx emissions using the new availability. Table 5 shows the costs for each scenario. The annual costs in this table include the annual costs associated with capital recovery.
Table 5. Annual Cost Comparison Annual Costs (2009, 1,000$) Low Dust VI Low Dust V2 Tail End VI Tail End V2 Minnkota

- Scenario A $36,923 $63,162 $43,290 $73,245 Minnkota

- Scenario B $49,829 $95,310 $56,098 $106,022 OAQPS

- Scenario 1 $19,753 $34,114 $23,016 $39,345 OAQPS

- Scenario 2 $18,714 $30,837 $21,768 $36,464 OAQPS

- Scenario 3 $18,081 $30,524 $21,660 $36,287 OAQPS

- Scenario 4 $20,449 $33,370 $23,708 $38,598



### -26-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS

Annualized Costs (2009; 1.000$)
$120,000,----------------------------_

$100,0001-----------------------

$80,0001---------

$60,000 -/--------

$40,000

$20,000

$0 • Minnkola
- SCenario A

• Minnkola
- scenario B OOAQPS

- Scenario 1 OOAQPS

- Scenario 2 .OAQPS

- Scenario 3 Ie OAQPS

- Scenario 4

Low Dust U1 Low Dust U2 Tail End U1 Tail End U2 Figure 2: Comparison ofAnnual Costs Using Different Cost Methods Table 6 shows the costs in dollars per ton ofNOx removed in both 2009 and 2006 dollars. North Dakota averaged B&McD's Scenario A and B in their summary, which is also shown on the table. As can be seen from the table, when the Control Cost Manual cost factors are used in conjunction with baseline cost information provided by B&McD, supplemented with more reasonable cost data and assumptions on certain cost data, the cost-effectiveness is less than halfofthe "average" value ofthe two B&McD scenarios used by NDDH, even underthe assumption that a layer ofcatalyst is replaced is every year (Control Cost Manual Scenario 1). This assumption is three times higher than the catalyst exchange rate that was provided in proposals from one catalyst vendor to Minnkota and performance guarantees provided to Mr. Hartenstein from three catalyst vendors. ERG's analysis is attached.45

45. See Enclosure 16. 

### -27-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS

Table 6. Cost Comparison Dollar per Ton Removed 2009 Dollars (1,000$) Annual Costs Low Dust UI Low Dust U2 Tail End U1 Tail End U2 Mirmkota

- Scenario A $3,950 $4,250 $4,632 $4,930 Mirmkota

- Scenario B $5,300 $6,362 $5,969 $7,078 North Dakota $4,625 $5,306 $5,301 $6,004 OAQPS

- Scenario I $2,120 $2,301 $2,464 $2,654 OAQPS

- Scenario 2 $2,010 $2,081 $2,332 $2,461 OAQPS

- Scenario 3 $1,942 $2,061 $2,321 $2,451 OAQPS

- Scenario 4 $2,194 $2,188 $2,537 $2,531 2006 DoHars (1,000$) Mirmkota

- Scenario A $3,586 $3,859 $4,206 $4,476 Mirmkota

- Scenario B $4,813 $5,777 $5,420 $6,426 North Dakota $4,200 $4,818 $4,813 $5,451 OAQPS

- Scenario 1 $1,925 $2,089 $2,238 $2,410 OAQPS

- Scenario 2 $1,825 $1,890 $2,117 $2,235 OAQPS

- Scenario 3 $1,764 $1,872 $2,108 $2,225 OAQPS

- Scenario 4 $1,992 $1,987 $2,304 $2,298

Costs ($Iton removed)
$8,000**-,--------------------.-------~**

$7,000 +-----------------------

$6,000 +---------

$5,000

$4,000

$3,000

$2,000

$1,000

$0 • Minnkola • Scenario A

• Minnkota
- Scenario B o OAQPS

- Scenario 1 OOAQPS

- Scenario 2 .OAQPS

- Scenario 3

OAQPS

- Scenario 4

Low Dusl U1 LowDuslU2 Tail End U1 Tail End U2

Figure 2: Comparison ofCost-Effectiveness Using Different CostMethods 

### -28-EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS
III. Conclusions EPA requests thatNDDH reconsider its preliminaryBACT determination and find that SCR represents BACT controls at MRYS. Since SCR has been successfully applied worldwide to such a wide variety ofsources, there is apresumption that it is both technically and economically feasible at MRYS. Minnkota failed to produce sufficient evidence to overcome this presumption. Although NDDH identified some adverse energy and environmental impacts associated with the use ofSCR, it correctly concluded that these impacts would not preclude the selection ofSCR as BACT. As more fully set forth above, Minnkota's cost estimates were not conducted in accordance with the NSR Manual and the Control Cost Manual, and resulted in grossly overestimated SCR costs. NDDH relied upon Minnkota's faulty cost estimates to conclude that the cost effectiveness ofLDSCR at MRYS was $4,201 perton for Unit 1 and $4,822 per ton for Unit 2. Even these inflated and unreasonable cost estimates must result in a conclusion that LDSCR is cost effective at MRYS. 

### It is clear that many other sources have borne costs that are more than this.
NDDH is required to base its BACT determination on cost estimates that are consistent with the NSR Manual and the Control Cost Manual. IfMinnkota had followed the applicable methodology, it would have resulted in a determination that the cost effectiveness ofSCR at MRYS was about $2,000 per ton. For the reasons set forth above, NDDH should reject Minnkota's cost analysis and base its BACT determination on the application ofthe NSR Manual and the Control Cost Manual. An objective review ofthese results would show that SCR is cost effective. Ifyou would like to discuss any ofthese matters, please call Cynthia Reynolds at (303) 312-62006 orBrendaMorris at (303) 312-6891.

rew M. Gaydosh sistantRegional Administrator Office ofEnforcement, Compliance and

Environmental Justice Enclosures

-29-cc: David Glatt, NDDH (w/o Enclosures), Dean Haas, NDDH (w/o Enclosures), Jerry MacLaughlin, USDOJ (w/o Enclosures), JeffKodish, OECA, (w/o Enclosures), BrendaMorris, EPA (w/o Enclosures), Hans Buenning, EPA



### -30- EPA Comments on NDDH Preliminary NOx BACT Determination for MRYS