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

Ref: 8P-AR 

### JAN 0 8 

### 2010
Terry O'Clair, Director Division ofAir Quality Environmental Health Section North Dakota Department ofHealth 918 E. Divide Ave. Bismarck, NO 58501-1947
RE: EPA Region 8 Comments on December 2009 Draft Regional Haze SIP (Public Comment Version)
Dear Terry:
EPA has completed a preliminaryreview ofNorth Dakota's December 2009 draft Regional Haze State Implementation Plan (SIP), as provided by you with a December 3, 2009 letter. Our comments and questions on this public commentversion ofthe SIP are detailed in Enclosure 1to this letter. In addition, Enclosure 2 contains our detailed comments on the North DakotaDepartment ofHealth/Basin Electric cost analyses for selective catalytic reduction, and Enclosure 3 contains the referenced Institute ofClean Air Companies' May 2009 White Paper on Selective Catalytic Reduction (SCR) Control ofNOx Emissions from Fossil Fuel-Fired Electric Power Plants.
We understand that you intend to consider all comments received on this public comment version ofthe draft Regional Haze SIP priorto finalizing and adopting the documents for submission to EPA. We emphasize that we will only cometo a final conclusion regarding the adequacy ofNorth Dakota's Regional Haze SIP when we act on the North Dakota Regional Haze SIP revision, through ourown public notice and comment rulemaking.
We wantto acknowledge your efforts in developing this difficult SIPand in working with us overthe course ofits development as issues arose. This effort has helped to narrowthe issues significantly. However, important issues remain. Please note ourmost serious concerns are summarized at the beginning ofEnclosure 1.
As you are aware, North Dakotareceived a finding offailure to submit its Regional Haze SIP by the required deadline. As a result, a 2-year clock was initiated for EPA to fully approve a

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SIP orpromulgate a Federal Implementation Planby January 15,2011. Please do not hesitate to contact me with any concerns related to this timeline.
We look forward to continued communications with you to resolve the remaining concerns with this draft SIP. Ifyou have any questions onEPA's comments, please contact me at 303-312-6434, or have your staffcontact Amy Platt at 303-312-6449. 

# CJall**f~~**

Callie A. 

### Videtich,Qector Air Program
Enclosures

cc: Tom Bachman, NDDH Chris Shaver, NPS Sandra Silva, USFWS Thomas Dzomba, USFS John Mooney, EPA Region 5



### 2ENCLOSURE 1
EPA Region 8 Preliminary Comments on December2009 Draft Regional Haze SIP (Public Comment Version)
Summary ofMajor Concerns
- (see detailed comments for more information):

• In an October 23, 2009 letter, EPA provided commentsto the North Dakota Department ofHealth (NDDH) onthe Federal Land Managers (FLMs) consultation version ofthe draft North Dakota Regional Haze SIP. These comments included, among otherthings. concems regarding the modeling methodology used to exemptMontana Dakota Utilities (MDLJ) Heskett Station Unit 2 from the BARTrequirements. To address this issue, NDDH. EPA. MDU, and the FLMs negotiated a modeling protocol that involved rerUlming the model for BART applicability using the current EPA default model settings. MDUrecently completed the revised modeling and provided the results in a December 17,2009report. The revised modeling results showthe facility is exempt from the BARTrequirements. EPAhas obtained and is reviewing the modeling tiles to verify these results. Giventhat this updated modeling was completed afterthe start ofthe CUlTent public commentperiod onthe Regional Haze SIP, EPA will provide separate comments ifthe revised modeling fails to address our concems. Please note that NDDH will need to revise the SIP to include the updated modeling and yourrelated conclusions. The revision will need to follow North Dakota's public participationprocess for SIP revisions. See comments #3 and #21 below.

• We find that certain assumptions used inthe cost analysis ofselective catalytic reduction (SCR) for NO, control at Leland Olds and Milton R. Young are unsubstantiated and likely inappropriate. Ifmore reasonable assumptions are used, the analysis will likely show SCRto be cost eiTective onthe three cyclone units (M.R. Young Units 1& 2 and Leland Olds Unit 2). For further guidance. pleaserefer to EPA's Guidelines for BART Detem1inations (70 FR 39104. July 6. 2(05) and ourcomments onthe cost analyses for selective catalytic reduction (see comments #23-24 below and Enclosure 2). In addition. see our comments below on the specific BART detemlination documents.

• Inthe Coal Creek NO, BART detennination. the elimination ofSCRand selective noncatalytic reduction (SNCR) based on uncertainty surrounding "potential" ammonia contamination offly ash is not appropriate. The BART detennination should be based on the 5-factor analysis, including any necessary datato addressthis question (see 70 FR 39166, July 6,2005). See comment #39 below.

• Based on your analysis, thereappear to be available controls underReasonable Progress that cany similarcosts to those found reasonable under BART. Giventhat these controls would provide some additional visibility improvement. the analysis does not support your 

### 3conclusions that itis not reasonable to impose these controls at this time. For further guidance, please refer to the Regional Haze Rule (64 FR 35732, July 1, 1999). See comments #11-18 below.

Detailed Comments SIP Text:
1. Purpose/Legal Authority, last paragraph, p. 3: We note that the Coyote Station Pennit to Construct is contained in Appendix A not Appendix D. Please clarify.
2. Tables 6.3 and 6.4, pp. 41-42: The NOx emissions inventory fOf 2018 has been changed from previous versions reviewed. Please explainthis change. It appears the point source number was revised downward to include projected emissions reductions from the Coyote Station. If so, we note that the Coyote Permitto Construct doesn't require compliance with the revised NOx limit until July 1, 2019. Therefore, it is not appropriate to include the reduction inthe 2018 inventory.
3. Exclusion ofMontana Dakota Utilities Heskett Unit No.2, p. 66-68: (A) Table 7.2

- This table will need to be revised to include updated 98thpercentile visibility impact results based on approved modeling. (B) We are in the process ofreviewing MDU'sDecember 17,2009revised modeling report. EPA will provide additional comments onthis issue ifthe revised modeling fails to address ourconcems. See COlllment #21 below for lllore detail.
4. Section 7.4.2, Depal1ment BARTDetenninations, p. 69-77: The modeling to detennine if each BART-eligible source has a significant impact onvisibility was pertonned by NDDH using the CALPUFFmodel following EPA's Interagency Workgroup onAir Quality Modeling (lWAQM) Phase 2 Summary Report and Recommendations for Modeling Long Range Transport Impacts specified inthe Guidelines for BARTDetenninations Under the Regional Haze Rule, 40 CFRPart 51, Appendix Y. However, NDDH conducted an altemative cumulative visibility modeling approach inthe NOx BARTdeterminations for M.R. YOWlg and Leland Olds because it believes single source modeling results "tendto be five to seven times larger" thanresults whenthe same source is combined with all other sources in a cumulative analysis (although for other pollutants that affect visibility

- PM and S02

- it appears that the State used the single source method contained in the BART Guidelines). The basis for NDDH's beliefis that the perceived change in visibility from controls ona single source is reduced when background contributions from other sources al'e included inthe modeling.

4EPA does not agree that the single source modeling underthe BART Guidelines overstates the degree ofvisibility improvement from emission reductions at the source. The Clean Air Act establishes a National goal ofeliminating man-made visibility impairment from all mandatory Class I Federal areas. Use ofa clean background (i.e.. not considering other nearby sources) is consistent withthe ultimate goal ofthe programto reach natural background conditions. Moreover, the consistent use ofa clean background in BART evaluations in North Dakota and surrounding states will foster emissionreductions that will speed achievement ofnatural background conditions, and will ensure equity among states in achieving this goal. The NDDH has already modeledthe 98th percentile values using the BART Guidelines' methodology for evaluating visibility improvements from the various control options. These values need to be used when weighing the visibility benefit factor in the NO" BART analyses.
In addition, North Dakota has noted elsewhere that "according to the Regional Haze Rule, the focus ofvisibility improvement demonstrations is the 20% worst visibility days, not the cleanest days:' This statement is contradicted by several provisions in the Regional Haze Rule that call ftw assessment ofboth the most and least impaired days. See, e.g., 40 CFR 51.308(d)(2), (flO), and (g)(3).
5. S02 BART section, p. 71: The S02 BART detemlination for Stanton Station Unit 1may result in too high a limit when bumingPowder River Basin (PRB) coal. Please see our comment #49 belowfor more detail.
6. NO" BART section, pp. 73: We do not agree that SNCR satisfies the BART requirements for Leland Olds Unit 2 and M.R. Young Units 1& 2. See our comments below onthe related BARTdeterminations.
7. Section 8.5.1, Hybrid Modeling System, pp. 95-96: The NDDH utilized a hybrid modeling approach for detemlining the status ofits Class I areas with respect to the rate ofprogress visibility goals. This approach involved nesting a local NDDH CALPUFF modeling domain within the WRAP National CMAQ domain. and applying the CALPUFF model in a retrospective sense to more realistically define plume geometry for local point sources. The hybrid modeling results were used in a weight ofevidence analysis to evaluatethe effect of emission sources located outside ofNorth Dakota. Please note that the last version ofthis modeling protocol to be reviewed by EPA was a draft dated April 2007 (i.

### eoo we never received the final October 2008 version for review). As modeling science has improved, there have been a number oftechnical changes in the CALPUFF modeling system and EPA/FLMrecommended default settings since NDDH proposedthe CMAQICALPUFF hybrid modeling approach in 2007. In the Reasonable Progress modeling, the hybrid CALPUFF/CAMxmodeling results were actjusted based on IMPROVE monitoring data, and it is not clear whether the use ofthese obsolete settings affected the weight ofevidence factors or the Reasonable Progress demonstration. The settings NDDH used inthe CALPUFF model within the hybrid modeling system would notbe considered technically 

### 5sound ifcontained in a regulatory modeling protocol for a future project. However, in this instance it does not appear to have made a ditTerence since NorthDakotais not able to meet the unifoffil rate ofprogress with either the WRAP analysis or NDDH's hybrid modeling system. 8. Section 8.6.L Hybrid CMAQ-CALPUFF Perfoffi1ance Evaluation, p. 132, 1stparagraph, 1st

.sentence: Model perfonllance was tested for the 90th percentile days. In addition, NDDH needs to compare perfoffi1ance on the

## 9thpercentile day consistent with the BART metric.
9. Section 8.6.2.3, Apportionmentby Source Group, pp. 146-153: We note that focus was on North DakotaEGUs and boundary condition groups dueto theirrelatively "small" and "large" contributions, respectively. Since NDDH needs to be looking at what is within its control, N0l1h DakotaEGUs become the largest contributors. We also note that North Dakota'sN03 percent contribution in 2018 actually increases at LWA (Table 8.16, p. 152), so it appears that there may be additional NOx sources within North Dakota's control that can be addressed. This increase may be related to increased oil and gas development in the area.

. 10. Section 8.6.2.5, Conclusions, pp. 156-157: NDDH concludes that while the addition of proposed BART controls will substantially decrease the visibility impact ofNorth Dakota EGUs, these EGUs comprise only a small component oftotal 20% worst day impacts at TRNP and LWA. The textneeds to also note that during periods when EGU emissions are transported into the Class I areas, the proposed BART reductions will significantly improve visibility. This can be demonstrated by referencing the peak day and 9gtll percentile CALPUFF results for eachEGU.
11. Section 9.5.1, Step 1, pp. 177-181: We have several commentsrelatedto this section. First, please note that the 

### Q/D approach does not work for sources like Oil & Gas where the emissions are spread out over large areas, but cumulatively the emissions and impacts from these sources can be signiticant. In addition, the narrative needs to acknowledge the potential impact ofprimary PM ifemissions are large. Next. please notethatthe referenceto the BART Guidelines underthe 

### QID discussion is not necessarily applicable for Reasonable Progress purposes. Lastly, it appears that Heskett Station Unit 2 was omitted from the sources reviewed in Table 9.4. Please clarify.
12. Section 9.5.L Table 9.8, p. 184: (A) As noted in our August 12,2009preliminary comments onthe WRAP's May 18,2009 Draft

### SupplementaryInformationforFour-FactorAnalysesforSelectedIndividualfc/citities in North Dakota. the reliance on a 1982 NSPS analysis for Claus Sulfur Recovery Units raises questions regarding why newerdata could not be utilized. Advancements in energy efficient teclmology and heat transfer media may affect tail gas treatment unit operational



### 6needs. Cunent data should be available and may indicate lower energy and steam usage. Please verify that these concerns with the WRAP report were not carried overinto the North Dakota SIP. (8) There appear to be nwnerous NOxcontrols available atcosts similar to, or less than, those selected under BART,raising the questionofwhy Antelope Valley and Coyote Station wan'anted a decision by NDDH that NOxcontrols carry excessive costs. Since NDDHhas already detennined BARTcontrols

- similar to the control options analyzed for the Reasonable Progress units

- to be cost effective and to provide visibility improvement, it is unclear how similar controls on the EGUs at Antelope Valley and Coyote Station would not bejustified. (C) Some average cost effectiveness fIgures are lower for control options that provide greater reductions. 

### e.g., LowNOx Burners (LNB)+SNCR at Antelope Valley Units 1 & 2 and LowEmission Combustion (LEC) Retrofit at Tioga Gas Plant's five 1920 hp reciprocating engines. The clear advantage ofthese options wan-ants further consideration by NDDH. (D) The estimatedcosteffectiveness ofcontrol options for Tioga Gas Planfsrebuilt engines (2350 hp) appears to be inaccurate since reductions are underestimated for add-on controls. Despite emission reductions achieved during rebuild. the percent control effIciency should not differ that much from engines that are not cun-ently operating atpeak performance. It appears that NDDHrelied on the WRAP's May 18.2009 Draft**Supplenlentm~v** Information lor Four-FactorAnalvsesfor SelectedIndividual Facilities in North Dakota, which assumed

, . . that "air-to-fuel ratio adjustments, ignition timing retarding, and LEC retrofit would not achieve further emission reductions since the estimated emission reductions for these measures are less than the reductions which appear to have already been achieved." However, the above reductions should have been assumed on top ofreductions which appear to have been achieved through rebuild. In addition, the WRAP report indicates that SCR reduces emissions from reciprocating engines by 90%; therefore, NDDH needs to explain its use of80% for the 1920 hp engines and 50% for the 2350 hp engines. 'Csing an inappropriately low control et1lciency will result in a biased high cost effectiveness ofa control option.
13. Section 9.5.1. Step 3. p. 183-185: Visibility improvement is not one ofthe four Reasonable Progress statutory factors (cost ofcompliance. time necessary for compliance, energy/non-air quality environmental impacts ofcompliance, and remaining usefu1life ofany potentially affected sources). but the State has the flexibility to consider it in decision-making. The State selected a number ofemission units for potential Reasonable Progress controls; however, as shown in Table 9.9, NDDII may have eliminated these from consideration due to a perceived small visibility improvement attributed to each control measure. The cost effectiveness ($/ton) for reducing emissions at a number ofthe sources considered for Reasonable Progress controls is similar to the cost effectiveness that NDDH considered appropriate for control at the BART sources. Thus, it is reasonable to consider controllingthese sources as well. The 

### 7relatively low visibility benefit for controlling an individual unit should not be a major factor to consider when selecting Reasonable Progress measures: giventhe ultimate purpose ofthe Regional Haze program. cumulative effects across sources need to be considered. In addition, since NDDH has chosen to rely heavily on visibility improvement for its decisions on Reasonable Progress controls, we consider it important to include the 98th percentile day results in addition to the 20% worst days results. In our view, since the 98th percentile day results are used in detem1ining BART, and NDDHhas chosen to rely on visibility improvement in determining Reasonable Progress controls. it makes sense to include the 98th percentile day results under Reasonable Progress to supplement the 20% worst days results.
14. Section 9.5.1, Time Necessary for Compliance, p. 185: As noted in our August 12,2009 preliminary comments onthe WRAP's May 18,2009DraftSupplementary lr!tormationfor Four-FactorAnalyses for SelectedIndividual Facilities in North Dakota. this timeline for compliance seems to be overestimated and/or doesn't accolmt for steps that canbe completed in parallel. In addition, the time necessary for compliance should not include time to develop regulations. Ifnewregulations are necessary, suchregulations need to be submitted with the forthcoming SIP. The WRAP report indicated that two years may be needed to develop the rules to implementReasonable Progress strategies. This statement implies that the State lacks authority to develop and submit a SIP to address ReasonableProgress and Long-Teml Strategy requirements, including relevant Reasonable Progress measures. Please verify that these concems with the WRAP report were not carried over into the NorthDakota SIP.
15. Section 9.5.1, Reasonable Progress Goals

- Required Controls for Point Sources, p. 186-187: Againfor comparison. since NDDH has chosen to rely on visibility improvement in detem1ining Reasonable Progress controls, it is appropriate to also provide and considerthe 981h percentile day results in aggregate. In addition, given that the cost effectiveness ($/ton) for reducing emissions at a number ofthe sources considered torReasonable Progress controls is similarto, or less than, the cost effectiveness that NDDH considered appropriate for control at the BART sources, it is unclear why some additional Reasonable Progress controls are not warranted inthe current plmmingperiod.
16. Section 9.5.4, Coyote Station, p. 189: It appears that NDDH believes at leastthis minimal level ofcontrol is reasonable now. As such, why isn't 

### it included as a required Reasonable Progress control inthe SIP? Further, why is the related Permit to Construct contained in AppendixA, BARTModeling Protocols and Analyses? Finally, this "agreement" must not preclude NDDH's re-evaluation ofthis source in future planning periods.
17. Section 9.6, Visibility Modeling and Weight ofEvidence, p. 191-193: The statement that implementing additional controls at Antelope Valley Station, Coyote Station, and Tioga Gas Plant "will not significantly affect cunent visibility conditions orthe amount oftime necessary to achieve natural conditions"

- is misleading. Visibility improvement in aggregate should result inmore progress. These sources are withinNDDH's control (as opposedto the Canadian sources) and are cost effective to control. We 

### 8understand that NDDH is not able to meet the unifol1n rate ofprogress in this planning period, but this does notjustify the lack ofReasonable Progress controls onthese sources. 18. Table 9.14, Reasonable Progress Goals. p. 195: The addition ofthe goals based on WRAP's modeling approach is useful; however, clarification should be provided as to which goals are being established by NDDH.
19. Section 10.6.5, Smoke Management Teclmiques for Agriculture and Forest Management. pp. 204-205: A statement needs to be addedthat NDDH will re-evaluate potential emissions reductions on sources within North Dakota's control in future planning periods.
20. Section 11.6. Rules for Non-BART Point and Area Sources, p. 213: AlthoughNDDH has determined that 

### it is not reasonable to control these sources during the current plmming period. this sectionimplies that NDDH lacks authority to develop and submit a SIP to address Reasonable Progress and Long-tel1n Strategy requirements. including relevant Reasonable Progress measures. It is not appropriate to use this lack ofauthority as justificationfor elimination ofReasonable Progress controls in the current plmming period nor is a commitment ofthis nature acceptable to address requirements.
21. Appendix A.2.2. AECOM's August 12,2009Response to Concems Regarding BART ExemptionModeling for Heskett Unit 2: (A) NDDH's 2006 CALPUFF BARTexemption modeling indicatedthat baseline emission impacts wouldresult in a visibility impact of0.82 deciviews (dv) at TRNP and 0.58 at LWA. Predicted visibility impainnentexceeding 0.5 dv wouldmake the facility subject-to-BART. MDU then contracted \vith ENSRto make refinements to the State's analysis that included reducing the grid size from 3km to 1km and a number ofother settings in the model that are not consistent with current EPA defaults settings for the CALFUFF model. To address this issue. in November 2009 NDDH, EPA. MDU, and the FLMS negotiated a modeling protocol that involved renuming the model for BART applicability using the current EPA default model settings. MDU recently completedthe revised modeling and provided the results in a December 17, 2009 report. The results show that the facility is exempt from the BART requirements. EPA has obtained and is reviewingthe modeling files to verify these results. Given that this updated modeling was completed afterthe start ofthe current public comment period onthe Regional Haze SIP, EPA will provide additional comments on this issue ifthe revised modeling fails to address ourconcerns. Please note that NDDH will need to revise the SIP to include the revised modeling andyourrelated conclusions. The revision will need to follow North Dakota's public participation process for SiP revisions. (B) We also note an inaccurate reference in Appendix A.2.2 stating that EPA accepted Rapid Update Cycle (RUe) prognostic meteorological data for use in NDDH's S02 Periodic Increment Review. EPA has not taken action to approve NDDH's Periodic Increment Review.



### 922. AppendixB.5, BART SCRTechnical Feasibility Analysis for NorthDakotaLignite: (A) While we agree with your detel111ination that LowDust SCRand Tail-End SCRare technically feasible, we do not agree with all ofthe technical aspects or conclusions ofthe analysis, especially as they relate to HighDust SCR. As you know, we hlVe done a thorough review ofthe technical feasibility analyses submitted by Minnkota for Units 1and 2 at Milton R. Young Station and NDDH's preliminary BACT detenninationpublished for public notice on June 11,2008. Ourcomments and supplemental information were provided inprevious letters from EPA Region 8's Office ofEnforcement, Compliance, andEnvironmental Justice, to the North Dakota Department ofHealth, Division ofAir Quality. Our letters provided substantial inforn1ation and evidencethat all SCRteclmology. including High Dust SCR, is teclmically feasible at facilities burning North Dakota lignite, and we continue to stand by those comments. (B) Please see p. 8 ofthe Institute ofCleanAir Companies (lCAC) May 2009 White Paper on SCR Control ofNOx Emissions from Fossil Fuel-Fired Electric PowerPlants, contained in Enclosure 3 for your use. This paper addresses feasibility ofSCR onlignite-tired boilers and, while noting "[l]ignite from different mines has some common characteristics but also differs in some significant ways," states that "[w]ithproper design, lignite applications can be successful." The ICAC paperaddresses the teclmical issue ofhigh sodium in lignite and states that "[t]hese poisons are not an issue as long as the catalyst stays above dew point conditions."
23. Appendix C.1, Leland Olds SCRCostEstimate: We have numerous concerns with the May 2009 Leland Olds BART Update, Tail-End Selective Catalytic Reduction (TESCR) Cost Effectiveness Evaluation, as prepared by Sargent& Lundy for BasinElectric and utilized by NDDH in its BART determinations for Leland Olds. In summary, several unsubstantiated and likely inappropriate assumptions impact the cost effectiveness numbers relied upon by NDDH to eliminate SCRin its BART detelminations for Leland Olds Units 1 & 2. These assumptions result in calculated costs for TESCR that are biased high. 

### Ifa more reasonable set ofassumptions are incorporated into this analysis, it will likely show SCRto be cost effective onthe cyclone unit (Leland Olds Unit 2), and it may also be cost effective for the wall-tired unit (Leland Olds Unit 1). Please see ourdetailed comments in Enclosure2.
24. Appendix C.4, November 2009 Minnkota SupplementalNO, BACTAnalysis Reports for Units 1 & 2: In response to Minnkota's Supplemental BACTReports, NDDH sent a November 25, 2009, letter to Minnkotaciting a lackofdetailed and comprehensive cost data documentation in the Supplemental BACTReports and the failure to address the use ofmain boiler steam for flue gas reheat. NDDHrequested that this informationbe submitted, as well as a demonstration thatthe cost ofNO, removal for SCR is disproportionately high compared to the cost ofNO-, control inotherrecent BestAvailable Control Teclmology (BACT) detenninations for coal-tired powerplants. EPA has reviewed the Supplemental BACT Reports and wholly supports the statements in NDDH's November 25, 2009letter. Given the fact that you are not satisfied \vith Minnkota's analysis and have requested additional 10supplemental infonnation, it is not appropriate to rely on this cost analysis inthe BART context at this time. EPA has also identitled additional problems and concerns withthe Supplemental BACT Rep0l1s whichmust be addressed for BARTpurposes as welL in accordance withthe requirements of40 CFR 51.308(e)( 1). (SIP must include documentation for BART analyses.) These additional problems and concerns are summarized as follows: (A) The additional outage time estimated in the**Supplt~mental** BACT Reports for catalyst cleaninglreplacement seems very high and is not supported. Considering there are regular planned outages for bothunits, these times should be attributed to catalyst cleaning/ replacement activities that would not otherwise be accommodated during these plmmed outage events. (B) The estimated catalyst replacement schedule under both scenarios used in the Supplemental BACTReports is much shorter than EPA would expect for Low-Dust Selective Catalytic Reduction (LDSCR) and TESCR systems. Furthennore, the assumption that one layer ofcatalyst would be replaced during each plalmed boiler cleaning outage is made without anyjustification and shouldtherefore be given little to no credibility in the final conclusions ofthe BACT analysis. (C) All vendor correspondence related to catalyst costs and replacement, as described inthe Supplemental BACT Reports, must be provided. This includes the original requests submitted to the vendors by Mimlkota and/or their consultants. (D) While the Supplemental BACTReports give a general description ofhowthe pressure drops and parasitic loads were calculated, Mimlkota orNDDHmustprovide more details, including calculations tojustify these high values. (E) No data is provided for the temperature gradient ofthe regenerative gas-to-gas heat exchanger, which is essential to detern1ine the required reheat input for either a natural gasfired or steam system. Furthem1ore, the assumed value offlue gas reheat of600 ,1 Fmust bejustified. We would also expect this temperature to be different for a LDSCR and TESCR due to significantly different S02 and SO" concentrations. (F) The Supplemental BACT Reports claim there were no similar projects "oncoal-fired powerplants in the United States that couldbe used. with adjustments. to properly represent total installed cost" for MRYS. Milmkota orNDDH should considerthe data from the PSE&G Mercer and We Energies South Oak Creek facilities that have installed. or will be installing. LDSCR systems. (G) The cost values used for catalyst. natural gas. and electricity appear higherthan current prices and must be substantiated. Furthermore. the Supplemental BACTRep0l1s assume

11

### . 

## ..

urea would be used as opposed to anhydrous ammonia. Bothoptions should be evaluated andthe least costly option selected, unless there is a compelling reason to use the more expensive option. 

### 25. Appendix 1.1, Consultation with Federal Land Managers: We note that in several ofyour responses to FLM comments, you cite to EPA'sAugust28,2009 Advanced Notice of Proposed Rulemaking (ANPR) regarding the FourComers PowerPlant BART analysis. The ANPRdoes not represent anAgency decision but rather includes infonnation on which EPA Region 9 seeks comment. At this point, no Agency position has even beenproposed, much less finalized. It is not appropriate to rely on the August 28,2009 ANPR to support your position regarding BART analyses in North Dakota.

NDDH BART Determinations
- Pertaining to All 4 Determinations 

### 26. S02 and NOx analyses: In general, analyses ofcontrol options and proposed limits should not be based on worst-case coal scenarios and/orhighest calendaryearemission rates. Use of averages should allowfor accommodation ofworst-case situations and will ensure that the more common conditions are adequately limited.
27. NOx analyses, Step 3: Evaluate Control Effectiveness ofRemaining Control Technologies: Based on ourcomments#22-24 above and Enclosure 2, please ensure that inappropriate assumptions in the cost analyses for SCR were not carried over to the NDDH BART determinations for any ofthe facilities reviewed. In addition and as we have commented in previous cOITespondence, incremental cost analyses are intended to be a useful supplement. not a replacement, for standard $/ton calculations. It is not unusual that the incremental costs will be greater than the average cost etTectiveness as the level ofcontrol increases. but this should not be an automatic basis for eliminating an option which has a reasonable average cost etIectiveness.
28. The visibility impact analyses need to eliminatethe reference to "3 units" for TRNP, as requested by the FLMs. We note that this change was made in the SIP text and should be calTied overto these documents. TRNP was identified as a single national parkunder the Clean AirAct Amendments of 1977 (42 U.S.c. 7472); thus, there is only onemandatory Class I Federal area for thispark. By dividing this ClassI area into 3 units, there may be slight reductions in benefits predicted when modeling the visibility etlects ofapplying controls.



### 12NDDH Proposed Permits to Construct
- Pertaining to All Permits (except Coal Creek)
29. Section Il.A.2., Compliance Date: The last phrase "

...approvesthis pe1111it as part ofthe BART SIP" needs to be revised to "

...approves this pem1it as part ofthe Regional Haze SIP."

Leland Olds:
NDDH BART Determination
30. Unit 1 S02 BART evaluation. p. 5: As we have commented in previous correspondence. we have concerns withthe use of35(s) as an alternative emission factor for S02. NDDH's response did not adequatdyjustify the use ofthe alte111ative. The alte111ative factor was based on a study contained in NDDH's periodic review ofPSD S02 increment consumption. In that study, an emission factor of37.4(s) was proposed. Forthe Leland Olds BART determination, an emission factor of35(5) was used to provide a conservative estimate ofthe uncontrolled emissionrate. In the periodic review. NDDH apparently used CEM data from recent years to derive an alternative emission factor to estimate sulfur emissions. The EPA AP-42 emission fadors \\'ere developed in the mid-1970s and include test data gathered at lignite burning powerplants in North Dakota and elsewhere. EPA has concerns about using recent CEM datato adjust emission factors giventhat coal quality may have changed over the years, ormay change inthe tllture. However. in this instance it does not appear that the use ofthis alte111ative emission factor affects the results ofthe S02 BART detennination.
31. Units 1and 2 NO, BART evaluations: (A) NDDH has revised its analysis and detennines that LDSCR and TESCR are tec1mically feasible and includes separate cost estimates for both systems. However. there is no explanation as to how the LDSCR cost values were obtained. Please clarify and include all SuppOliing documentation in the SIP. See 40 CFR 51.308(e)(1). (B) Based on ourreview ofBasinElectric's May 29. 2009 supplemental TESCR cost analysis and NDDH's July 2009 SCR Teclmical Feasibility Analysis for North Dakota Lignite. y\'e do not agree with certain assumptions used in the TESCRcost analysis. Please see Enclosure 2 for more detail. as well as our comments #22-23 above. Step 3 ofthe BART determination needs to be revised to address these conce111S. These revisions are likely to considerably improve the cost effectiveness ofTESCRfor each unit, making it a reasonable selection for BART. In addition. this version ofthe draft BART detelmination includes new cost estimates for LDSCR. As explained above. it is unclearhowthe cost values for LDSCR were derived.
32. Unit 1NO., BARTevaluation, Step 3. p. 13: We note yourreference to EPA's August 28. 2009 AdvancedNotice ofProposed Rulemaking (ANPR) regarding the Four Corners Power Plant BART analysis to support the use ofan 80% control eHiciency for SCRwith reheat. 13The ANPR does not represent anAgency decision but rather includes information for which Region 9 seeks comment. At this point. nothing has evenbeen proposed much less tinalized. 

### it is not appropriate to rely on the ANPRto support your positionregarding BART analyses in North Dakota. NDDH needs to explain why the more commonly accepted tigure of90% control efficiency is not warranted. For more infonnation, please see the proposed and final Standards for Perfonnance for Electric Utility Steam Generating Units, lndustrialC0111mercial-Institutional Steam Generating Units, and Small lndustrial-CommercialInstitutional SteamGenerating Units (70 FR9713, February 29, 2005 and 71 FR 9869, February 27, 2006) and the May 2009 ICAC White Paper, pp. 4 and 7 (contained in Enclosure 3 ofthis letter).
33. Unit 2 NO" BART evaluation, pp. 23-31: (A) Perthe BART Guidelines, EPAhas found that the use ofSCRs at large cyclone units burning lignite enablesthe units to cost-etfectively meet NO" rates of0.10 Ibs/MMBtu. A revised cost analysis, using the necessary adjustments we have described in comment#23 and Enclosure 2, will most likely showthat SCRis cost effective at this large boiler. (B) ForBART detenninations, visibility improvement must be based onthe 98th percentile day results, not the 20% worst days. We do not agree that single source modeling under the BART Guidelines overestimates visibility improvement. See comment#4 above for more detail. NDDH did not use this approach in the visibility analysis for Unit 1andit must not be used for Unit 2. (C) There appears to be a typographical error at the beginning ofthe last paragraph onp. 

### 30­ should be "BART' instead of"BACTT
34. The "References" section includes NDDH's 2005 Proposed Alternative Air Quality Modeling Protocol to examinethe status ofattainment ofPSD ClassI increments. This protocol was never approved by EPA, and contested elements ofthisprotocol can not be relied upon in your BART detenninations.

Coal Creek:
NDDH BART Detennination
35. S02 evaluation, Step 2, 2lld paragraph, p. 8: There appears to be a typographical error in the 

### 2lld to last sentence

- shouldbeFalkirkMine instead ofCenter Mine?
36. S02 analyses, Step 5, p. 11: The reader is refenedto the Great River Energy (GRE) BART Analysis, pp. 47-51, for visibility improvement analyses. While the 98th percentile results are provided inthe GRE report, it is nearly impossible to understand dIe tables since results are combined tor S02 and NO" and there are no specifics provided for each scenario. NDDH 14needs to extract the relevant nthpercentile results from the GRE analysis

- by pollutant and by specific scenario

- and incorporate them directly into the BART detem1ination document. We note that this infoDnationhas been added to the NOxevaluation sectionbut was still omitted from this S02 evaluation.
37. NOxanalyses, Step 2: Eliminate Teclmically Infeasible Options, p. IS: As noted above in comment#22, we have provided substantial infonnation and evidence that all SCR teclmology, including High Dust SCR, is technically feasible at facilities buming North Dakota lignite, and we continue to stand by those comments.
38. NOx analyses, Step 3: Evaluate Control Effectiveness ofRemaining Control Teclmologies, pp. 15-16: NDDH needs to explain why it accepted GRE's suggested 80% control efficiency for LDSCR instead ofusing the generally accepted 90% efficiency. Formore infom1ation, please see the proposed and final Standards for Perfonnance for Electric Utility Steam Generating Units, Industrial-Commercial-Institutional Steam Generating Units, and Small Industrial-Commercial-Institutional Steam Generating Units (70 FR 9713, February 29, 2005 and 71 FR 9869. February 27, 2006) and the May 2009 ICAC White Paper, pp. 4 and 7 (contained in Enclosure 3 ofthis letter).
39. NOxanalyses. Step 4: Evaluate Impacts and Document Results, p. 17: (A) The elimination ofSCRand SNCR based on uncertainty surrounding "potential" ammonia contamination of11y ash is not appropriate. The BART deteDnination should be based on the 5-factor analysis, including any necessary datato address this question. GRE claims that installation ofSCRor SNCRmay negatively impact t1y ash sales due to ammonia slip and may result in an ash disposal problem, but does not provide any manufacturer's data, vendor infoDnation, or othertechnical orcommercial datato support its claims. See 40 CFR 51.308(e)(I). (SIP must include documentation for BART analyses.) It is our understanding that installation ofSCR and SNCRresult in very little, ifany, impacts to 11y ash sales since the ammonia slip for each control is now very low-lessthan 2 ppm for SCR and less than 5­ 10 ppm for SNCR. Giventhat this concemwasn'traised at the other BART sources where you have proposed SNCR, we know ofno reason for it to apply to Coal Creek. We note that you cite to an example fi:om Nebraskato suppOl1 your decision. Please be advised that the cited example is from a draft BART detem1ination analysis. The State ofNebraska has not submittedto EPA Region 7 its BART detennination analysis as part ofa tinal Regional Haze SIP. EPA Region 7has not, and will not, make a detem1inationregarding the approvability ofNebraska's BART deteDninations until it reviews all components ofthe tinal Nebraska Regional Haze SIP and acts on the revisionthrough its ownpublic notice and comment rulemaking.
40. Evaluate Visibility Impacts, Step 5, pp. 17-19: We note that youhave extracted the visibility impacts data from the GRE BART analysis to include in the NOxBART evaluation. However. it appears that youhave presented the combinedresults for S02 and NOx controls, notjustthe NOx results. Please clarify. 

### 1541. Summary, p. 23: Please correct typographical errors in the SOz BART limits for Unit 1and Unit 2 - should be 95% instead of

### 94°1c).

NDDH Proposed Pennit to Construct for BART

- Coal Creek
42.11.A.4.a.: Please correct the typographical elTor in the tirst paragraph

- should be 95% reduction limit instead of94%.



### Milton R. Young:
NDDH BART Detennination
43. Unit 1and Unit 2NOx BART evaluation: (A) In addition to objecting to selection ofSNCR as BARTbased onthe North Dakota record, we also object to your detennination that separate NO" limits are appropriate for startup. The record does notjustifY the need for such separate limits, nor does itjustifY that the selected values represent BART. As you know. the BART Guidelines contemplate pounds per million Btu limits that apply continuously, with a 30-day rolling average period to accommodate, among other things, potential short-tem1 fluctuations in the emissions rate that may result during startups and other conditions.
As we have noted previously, separate startup limits have not been sought by, or provided to, other facilities (Leland Olds and Stanton) for which SNCR is proposed as BART, and we know ofno reason M.R. Young wanants special treatment. NDDH alludes to the Consent Decree as a basis for special treatment and a need to ham10nize the "BACT limits" under the Consent Decree and the BART limits. First, the Consent Decree terms with respect to startup were the result ofa negotiated compromise in the context ofan enforcement action. The Consent Decree tem1S are not binding in the context ofthis BART determination, and Paragraph 66 ofthe ConsentDecree in no way settles whether separate startup BARTlimits are necessary or appropriate at M.R. Young. At this time, no BACT limit has been established at M.R. Young.
NDDH also alludes to the fact that SNCR, andperhaps the overfire air system, will not work optimally during startup. Ofcourse, this is also true for the other facilities mentioned above. This fact alone is not convincing.
NDDH then references Minnkota's claim that startup has lasted up to 61 hours for Unit 1and that noncompliance ofthis length will make compliance with the 30-day rolling average emission limit "extremely difficult." From your analysis, we cannot determine whether Minnkota was exercising good airpollution control practices to minimize emissions during 

### 16this period orto minimize the duration ofthe staIiup, whetherthis length ofstaliup was an anomaly, orwhat the average emissions rate was during this period. There is no mentionof staliups at Unit 2 or whetherthe same parameters can or should be applied. Also. we Calmot determine from the analysis what the expected "normal" emissions rate is using SNCR and overfire air. Presumably, your proposed BART limits already include some marginofsafety for operational variation. Also, NDDHhas not evaluated potential impacts ofthe separate startup limits onvisibility or why the separate limits representBART. We have found no indicationthatthe proposed startup limits represent the most stringent level ofcontrol for those periods. Furtheml0re, there is virtually no explanation in your BART detennination for the separate startup limit for Unit 2 or why it differs so greatly from the proposed startup limit for Unit 1, or why the other terms that apply to the staIiup limit for Unit 2 in the pennit differ from those for Unit 1or are warranted.
Even ifwe found the separate startup limits to be.iustified, we do not believe the permit is sufficiently clear with respect to detennining compliance with the nonnal 30-day limits and the 24-hour startup limits. In calculating 30-day averages, how will days be accounted for that include some, but not alL hours ofstartup? How will startups that are less than 24 hours be accounted for in calculating 24-hour averages? Finally, we questionthe use ofheat input levels to define the end ofstaIiup as opposed to using temperatures. The latter would be more directly related to SNCR performance. (B) As we have commented in previous correspondence, the presumptive limits should apply as the control floor since the total generating capacity is actually greaterthanthe reported nameplate capacity of734 MW, in fact. > 750 MW. In a November 20, 1995 letter, Minnkota advised NDDHthat M.R. Young was operating at levels above naIneplate and requested a change inthe pemlit description ofeach unit to 277 MWfor Unit 1and 517 MW for Unit 2. These changes ret1ected the capabilities ofthe units as they "are cunently with respectto generator output" and result in atotal generating capacity ofat least 794 MW. Per the BART Guidelines, EPAhas found that the use ofSCRs at cyclone units buming lignite should enable these large units to cost-effectively meet NOx emissionrates of0.10 Ibs/MMBtu. (C) We assume that NDDH has revised its cost estimates based onMiImkota's November 2009 Supplemental NO\ BACT Analysis Reports for Units 1& 2. Minnkota's revised cost analyses are unsubstantiated and highly questionablein many regards, as discussed in comment #24 above. Based on ourreview ofMinnkota's supplemental reports and this BARTdetennination, the NO, BART detenninations need to be revisedto address these issues. Revisions, per our comments. are likely to considerably improve the cost effectiveness ofSCRfor eachunit, making it a reasonable selection for BART. In addition, we have the following concerns specific to the BART detemlination document:



### 17(1) NDDH has assumed a control efficiency of90% (combined) for ASOFA with SCR. IEPA expects that NOx emissions can be reduced by 90% with SCRalone. Please see the proposed and final Standards for Perfonnance for Electric Utility SteamGenerating Units, Industrial-CommerciaL-Institutional Steam Generating Units. and Small IndustrialCommercial-Institutional Steam Generating Units (70 FR9713, February 29. 2005 and 71 FR 9869. February 27,2006) and the May 2009 ICAC White Paper, pp. 4 and 7 (contained in Enclosure 3 ofthis letter). Mimuwta's owncost analysis uses 93.8% combined control and 90% control beyondASOFA with SCR. TheBARTdetennination simply states that NDDH believes a reduction of90% for ASOFA and SCRis "more appropriate on a long-tenn basis" without providing any rationale. Using a lowercontrol efficiency results in significantly inflated $/ton values. (2) The footnote onthe costtables (p. 14 and p. 29) indicates that the cost range provided is based onthe ditTerence inapplying SCRto eachunit as a stand aloneretrotit (high end cost) and applying SCRto both Units 1 & 2 with shared facilities (low end cost). Minnkotaprovidedthese scenarios inits cost analysis. However, it appears the difference betweenthe low and high end ofthe am1Ualized cost range in NDDH's BART detelminationis basedon "ScenariosA & B" in Minnkota's cost analysis. Scenario A (the lower cost) assumes a catalyst layerreplacement (and unit outage time) every 16,000 hours. while Scenario B (the higher cost) assumes a catalyst layer replacement (and additional unit outagetime) at each scheduledboiler cleaning outage. ForUnit L this is three times a yearand for Unit 2 this is four times per year. EPAbelieves that Scenario B is not realistic for a LDSCR orTESCRand should be completely disregarded. It appears as though NDDH is inagreement, but inadvertently used the Scenario B values for the high end ofthe cost range. ratherthan using the stand-alone values. Inadditionto mistakenly using the Scenario B values from Minnkota's cost analysis. it appears that NDDH used the Scenario A & B costs from the "shared facility" Table 4-7SF for Unit 1, while using the Scenario A & B costs from the "stand alone" Table 4-7SA for Unit 2. Correcting these values significantly reduces thehigher annualized cost estimate (based on a stand alone unit instead ofScenario B) leadingto a much smallerrange betweenthe low-end andhigh end estimates. The lower cost estimate (representing shared costs betweenUnit 1 and Unit 2 for Scenario A) and the higher cost estimate (representing Scenario A stand alone unit) should be as follows:
Unit 1LDSCR: $31,749,000/$36,872.000 Unit 1TESCR: $39,307,000/$44.465,000 Unit 2 LDSCR: $57,351,000/$59.881.000 Unit 2 TESCR: $66,506,000/$69,057,000 (3) Combining the higher 93.8% control efticiency for SCR + ASOFA (as submittedby Minnkota) and the worst case scenario cost described by NDDH in the BART Detennination (stand alone unit costs, Scenario A), the follol,ving represents thehigh-end costs for Units 1 & 2: 

### 18Scenario A Stand Alone Costs: Annual NOx Tons Removed Levelized Total Cost

($1000) Average Control Cost ($/ton) II II Unit 1 (LOSCR) 9.348 36.872 3.944 Unit 1 (TESCR) 9.345 44.465 4.758 Unit 2 (LOSCR) 14,862 59.881 4.029 Unit 2 (TESCR) 14.857 69,057 4,648 I

Onp. 17 ofthe BARTOetennination for Unit L NOOH "considers the cost effectiveness and incremental cost ofSCR +ASOFA at the low end ofthe cost range to be reasonable:' while the higher end ofthe range was considered excessive. However. NOOH made this determination based on an errorin the calculation ofthe high-end cost ranges (based on the Scenario B assumption that catalyst is replaced every time the unit is dO\\11 for a planned outage). NOOKs low-end cost effectiveness values ($/ton) range from $3906/ton to $4948/ton. Given that the conectedhigh-end cost estimates are not dissimilar from NOOH's reasonable low-end estimates. these high-end costs should be considered reasonable at present.
As described earlier (and apparently suppOlied by NOOH's narrative inthe BART Oetem1ination. as well as NOOH's criteria for teclmical feasibility, 

### i.e.• a catalyst replacement schedule of3-4 times per year would not have been considered technically feasible by NODH). Scenario B should be dismissed. When the high-end cost range becomes the intended "StandAlone" facility costs, and more appropriate NO" removal et1iciencies are assumed (as provided by Minnkota). the high-end costs become very similarto (and in some cases lower than) what the NDDH BARTDetennination calculated as low-end costs deemed to be reasonable. There is little difference in these high-end cost effectiveness values for Units 1and 2. As such. EPA concludes that even without examiningthe concerns and problems withMinnkota's initial cost values. as discussed in comment#24 above. the existing infonnationfor the BART Detennination demonstrates that SCR is cost effective. Once appropriate adjustments are made to reflect more realistic costs. these values will become even more reasonable. (D) As noted above in comment#4. BART visibility improvement analyses must be based on the 98th percentile day results, not the 20% worst days. We do not agree that modeling based onthe BART Guidelines overpredicts the visibility improvement in NOlih Dakota.

1944. Unit 2 

### SOl Evaluation, Step 3, p. 21: We note the baseline 

### SOl emissions have beenrevised from 16, 728 tons/year upward to 18,090 tons/year in this draft. Please explain why this revision was necessary at this late date.
NDDH Proposed Permit to Construct for BART

- MiltonR. Young
45. II.A.1.c

.. NO:,: limits: The alternative limits for startup are not acceptable. See comment #43(A) above.
46. II.A.1.e.: The conditionthat SO:? and PM limits apply at all times, including startup, shutdown, emergency and malfunction should also apply to NO:,: limits.
47. II.AA.b.(8): This language regarding averaging the emissions ofUnit 1and Unit 2 is not consistent withthe language in the BART detemlination document, SectionIX. The BART detenninationincludes a fonnula and definitionfor Average Allowable Emission Rate (AER), which is not included in the pemlit. Please clarify. 

### Stanton:
NDDH BART Determination
48. S02 BARTevaluation in general: NDDHnotes that a circulating dry scrubber was eliminated from consideration due to excessive incremental costs. HO\vever, EPA would not find the cost effectiveness ofthis option ($1631/ton) unreasonable compared \vith other BART detenninations reviewed.
49. SO:? BARTevaluations for lignite and PRB coal, pp. 8 and 22: In an effort to assess the coal quality basis for NDDH's proposed S02 BARTdetenninations for Stanton, we conducted an independent analysis, using lignite and PRB coal data contained in EPA's Clean Air Markets Division (CAMD) database. The 30-day average SO:? emission potentials (in Ib/MMBtu and percent sulfur) oflignite and PRB coal are available for a wide variety ofsources through

.CAMD, and for 1110St (ifnot all) ofthe large coal mines in the region. We would be happy to

share this information withNDDH, ifdesired. Since these data are readily available, we see no need for the use ofa 33% multiplication factor to adjust an annual average emissionrate to a 30-day rolling average emissionrate. Based upon ourreview ofthe lignite coal quality data in the CAMD database for 2007-2009, it appears that NDDH's proposed 

### SOl BART limit of0.24 Ib/MMBtu when burning lignite is in the range ofwhat we'd expect to see at a 90% control efficiency. However, we wish to note that ifNDDH believes that the proposed Spray DryerAbsorber and Fabric Filterwill be able to achieve 90% reduction ofS02 emissions while burning low sulfur PRB coal, the control devices should be able to achieve greater than 90r 

### yo control when burning higher sulfur content lignite coal. 

### 20Based on ourreview ofthe PRB coal quality data in the CAMD database for 2007-2009, NDDH's proposed S02 BART limit ofO.l6lb/MMBtu when burning PRB coal appears to be too high. The NDDH based its proposed limit on an estimate of 1.2 lb/MMBtu for the aIU1Ual average S02 emissionpotential ofPRB coaL then applied 90% control efficiency to yield 0.12 lb/MMBtucontrolled S02 on an mmual average, then multiplied by 1.33 to convert to a 30-day average limit of0.16lb/MMBtu. The NDDH's estimate of 1.2lb/MMBtuemission potential for PRB coal was apparently based on coal sulfur content ofabout 0.64%. The NDDH's BART Detennination document does not indicate which mines were averaged together to yield 0.64%. Data we obtained from CAMD's database for 15 ofthe largest PRB coal mines reveal that PRB coal typically has much lower sulfur content on a 3D-day average. about halfofthe**0.64~/o** used by NDDH. Our analysis ofthat datayielded an average**S~** emissionpotential of0.78 lb/MMBtu, on a 30-day basis, for all ofthe PRB coal mines together.
It appears that NDDH wishes to use the high end ofa 95% contldence interval ratherthan an average value to set the 90% reduction limit. Therefore. we have averaged all the high end values ofall the 95% confidence intervals for all the PRB mines for which we obtained data. The average ofthese 95% confidence intervals is 0.95 lb/MMBtll, again on a 30-day average basis. The resulting S02 BART limit when burning PRB coal at a 90% control efficiency would most likely be in the vicinity of0.095 Ib/MMBtu. on a 30-day rolling average. 50. NOxBART evaluation: As we have commented in previous conespondence, the 45% control efficiency assumed for the alternative ofcombining combustion controls plus SNCR is lowerthan we've seen elsewhere. Please explain why NDDH accepted this control etnciency number from GRE. In addition, as noted above in comment #22, we have provided substantial infonnation and evidence that all SCRtechnology, including High Dust SCR, is technically feasible at facilities burningNorth Dakota lignite.

NDDH Proposed Penni! to Construct for BART

- Stanton
51. 1l.A.3., Continuous EmissionMonitoring (CEM): Basedon GRE's comments, this section of the permit was revised to eliminate the phrase "Main Stack" from "Unit 1 (Main Stack)" as the location for the CEM. For clarity, the pennitneeds to be revised to specify that the CEM location for a particular pollutant is downstream ofcontrols for that pollutant (unless control efficiency is being measured by a combination ofupstream and downstream CEMs, in which case one ofthe CEMs for that pollutant would be upstream ofcontrols).

21Coyote:
NDDH Proposed Pennitto Construct

- Coyote Station
52. Based on your discussions with Otter Tail Power Company, it appears that this level of minimal control is consideredreasonable atthis time. Therefore. even ifyou disagree with our other comments regarding Reasonable Progress, at least this level ofNOxcontrol should be included in the SIP as arequired Reasonable Progress control measure. As such, the pennit should more closely mirrorthe BART pennitfOffi1at, includingthe appropriate 30-day rolling average emission limit, compliance date no later than 2018 (or sooner ifreasonable), andcompliance detennination, monitoring, recordkeeping, and reporting requirements.

53. ILA.2, Compliance Date: There appears to be a typographical error in theheading- should be "Date" instead of"Data."



### 22ENCLOSURE 2
Comments on Basin Electric CostAnalysis for Tail-End Selective Catalytic Reduction (TESCR)
Below are EPA's comments related to the May 2009 SCR cost estimate submitted by Basin Electric and theirconsultant. Sargent & Lundy (S&L). This cost analysis was**rel~d** uponby the North DakotaDepartment ofHealth in preparing its Best Available Retrofit Teclmology Determinations. BasinElectric and S&L go to great lengths inthe May 2009 submittal describingtheirreservations with applying a TESCRto a unit fired on North Dakotalignite. since an SCRhas neverbeen installed and operated on such a facility. These claimshave beenrepeated extensively inthe context ofthe BARTprocess for both BasinElectric's Leland aIds Plant and Minnkota Power's MiltonR. Young Station (MRYS). as well as inthe context ofthe NOx BACT analysis that was submitted by Minnkota for MRYS. EPAhas previously submitted substantial comments onthese technical issues in bothcontexts and stands by those previous comments. As such, theywill not be repeated here in detail. except as they apply to the cost estimate. We believe NDDHhas correctly dete1111ined that Low Dust SCR (LDSCR) and TESCR are technically feasible in its BART analysis (and via a July 15.2009 letter regarding the BACT analysis for MRYS). thereby making these discussions in the cost analysis largely obsolete.
Comments on BasinElectric's May 29. 2009 Cover Letter:
Inthe cover letterto the S&L analysis. Basin Electric states that "design factors ofthe SCR (catalyst volume and surface area). reagent injectionrates. reagent slip and economic volatility ofthe re-heat fuel are unknown:' These claims t:1il to consider:

o Ifsteam is used for re-heating. which would likely be the preferred method ofreheat. there is no economic volatility ofthe re-heat fuel. o The reagent (NH3) injectionrate is detem1ined by the intended anunonia slip and the sought NOxremoval et1iciency. Engineering calculations shouldbe able to provide a reasonable estimation ofthis cost within an accuracy of+/- 5%. o Pelmissiblereagent slip is a value that canbe designed for and calculatedbased onthe SO" content in the flue gas and the outlet temperature ofthe airheater. o Required minimum catalyst volume and surface area canbe calculated from the soughtNOx removal efficiency and the permissible NH" slip, as is done with other SCRinstallations. o The flue gas composition entering the SCRis used to estimate catalyst deactivation, which is then used to estimate the necessary catalyst volume. The Hue gas composition entering the SCRcan be measured downstream ofthe ESP for a LDSCRorFGD for a TESCR. This Hue gas composition data allows an experienced catalyst supplierto estimate the catalyst deactivationrate with


### 23reasonable accuracy and consequently size the catalyst volume properly depending on the desired minimum catalyst life requested by the operator. While Basin Electric (and later S&L) claim pilot testing is necessary to make an accurate cost estimate, the only relevant infomlation obtained from pilot testing would be the exact catalyst deactivation rate. Presently, this can only be estimated, but it can be estimated with a reasonable degree ofcertainty for the purpose ofthe BART analysis. As stated in previous comments, the operating life ofcatalyst in a TESCRis usually much higherthanthe more conventional LDSCR and even greater compared to the most commonly-used HDSCR, and can be expected to be in the range of50,000 hours. Othercapital, operating, and maintenance costs can be accurately estimated by companies with engineering experience with TESCR systems. Comments on Sargent & Lundy's May 27, 2009 Analysis:
In the second full paragraph ofpage 3, S&L describes the sodium levels in North Dakota lignite and states, "[t]hese sodium levels, occurring inboththe vapor and particulate phase, along with relatively highlevels ofpotassium and calcium

.. significantly increase the potential for catalyst deactivation. plugging and erosion." The first part ofthis statement is conect in that it indicates that these critical alkalis do NOT occur in the phase which would cause catalyst deactivation directly, namely the gas or liquid phase. As vapors- and as such condensable and a particle or aerosol downstream ofa wet scrubber

- and paI1iculate matter, these alkalis can only poison the catalyst when made mobile by means ofion dissociation in a liquid. In other words, only when the catalyst in the TESCR is being cooled down to belo\\ the water dew point, suchpoisoning will occur. Since this does not happen often for a baseloaded unit, the rate ofdeactivation is comparatively slow, which supports the estimated 50,000 operating hours for the TESCRcatalyst.
In the third full paragraph ofpage 3, S&L claims that, "[t]he TE-SCR would still have to be designed to handle vaporphase sodium and fine particulates that are not collected by the ESP and wet FGD." While EPAhas already made extensive comments onthis issue in the context ofthe technical feasibility aIlalysis, all vapors will condense inthe wet scrubber and getmostly absorbed in the slightly acidic scrubber slurry (pH around 5.6- 5.8). Whatever passesthrough as a particle will not vaporize again unless sent through a flame, which would need to provide temperatures above the vaporizationtemperatures for these compounds (due to the non-homogeneous heat transfer distribution'withduct bumers). Thus, this could only happen ifduct bumers are employed. Inthe case where a steam coil will be employed, such re-vaporization is highly unlikely to occur, since the vaporizationtemperatures ofthese compounds are not reached across a steam coi1. This is because the heat transfer distribution with a steam coil is largely homogeneous and the surface temperature ofthe steam coil is belowthe vaporization temperature ofthe compounds. As discussed extensively inthe MinnkotaBACTcomments, the actual flue gas composition analysis data measured downstream ofthe wet FGD at MRYS proves that the amount ofsubmicron alkali aerosols is 

### 24so small that catalyst deactivation does not occurrapidly and a relatively long catalyst life can reasonably expected comparedto most HDSCR installations.
In the fourth full paragraph on page 3, S&L states that "either an in-duct'gas burner or steam heat exchanger" can be employed to raise the Hue gas temperature downstream ofthe gas-gas heat exchanger (GGHE) by an additional 50 F to approximately 600 F. Three things need to be addressed here. First assuming a GGHE temperature gradient of50 F is certainly the worst case scenario. As demonstrated by more than 20 years offull-scale TESCR experience, a GGHE temperature gradient ofonly 20 F is technically feasible and has been demonstrated. Assuming a GGHE gradient of50 F increases the Hue gas reheat cost by a factor of2.5 comparedto a GGHE with a gradient ofonly 20 F. The impact ofthis choice on the economics ofthe TESCR is very significant Second, it must be noted that this is the only time inthe entire analysis where the use ofsteam is mentioned for reheating purposes. Elsewhere in the document where reheating is discussed, it is implied that natural gas needs to be used, which is simply not true. As a matter offact, the vast majority ofall TESCRs in powerplant applications use steam for reheating due to several advantages overnatural gas, including lower cost, no increase in flue gas volume How rate, and no risk ofre-vaporization ofparticle bound and/or condensed catalyst poisons in the Hame ofa duct burner. Third, there is no need to raise the Hue gas temperature in a TESCRto 600 F. As EPA has previously commented, a lower Hue gas temperature of530

- 550 F is a sufficient temperature for a TESCRdue to the low S02 concentration downstream ofwet scrubbers. The higher the selected TESCRtemperature is, the higher the actual t1ue gas volume flow rate will be and therefore,-the largerthe GGHE, SCRreactor, and the ductwork will have to be. Therefore, the unsubstantiated assumption ofusing natural gas over steam for reheating signitlcantly and aliiticially inflates the cost estimate ofTESCR.
In the last paragraph onpage 

### 3, S&L states that "due to the limited etIectiveness ofthe GGHE, the outlet temperature from the TE-SCR system will be approximately 50

- 60 F higher

... resulting in a stack temperature ofapproximately 190 F." First, it unclear why the incrementalreheat temperature has now increased above the already overly conservative value of50 F up to 60 F. Second, it must be pointed outthat S&L's claimconceming a "limited etIectiveness ofthe GGHE" is inaccurate. Thethernlal efficiency ofa well-designed GGHE is near 100% and has nothing to do withthe 50 F gradient selected by S&L. Third, a stacktemperature of 190 F must be viewed very positively for three reasons, namely: o This allows a dry stack, which eliminates ally corrosion and/or acidic droplet ejection issues. o The complete evaporation ofall droplets and aerosols passing throughthe scrubber mist eliminators typically also eliminates the visible S03 plumes (.blue plume') known from many units buming high sulfur coal and equipped with wet scrubbers (i.e. AEP Gavin. Duke Gibson. etc.). o The higherthe t1ue gas exist temperature is. the higher is the effective plume rise and thus the achieved dispersion ofthe residual air pollutants in the Hue gas.


### 25In the first full paragraph ofpage 4, S&L states "the potential exists for sodium and potassium compounds remaining inthe Hue gas as fIne particles to re-vaporize as the Hue gas is reheated in the aforementioned duct burners." Using a steam coil for reheating effectively eliminates this theoretical concern. The additional concern that "fIne particles remaining in the flue gas would also have a tendency to get into the catalyst pores, forn1ing water soluble salts and reducing catalyst activity, as the ±1ue gas passes throughthe water dew point" appears to concede that severe alkali poisoning from the particle bound sodium and potassium passing through the scrubber can only occur in a TESCR when the liquid water is forn1ed inside the catalystpores by means ofmoisture condensing out ofthe flue gas. This is because the water soluble sodium and potassium salts are then allowedto dissociate and migrate as cations into the catalyst pores andreact with the catalytically active vanadium pentoxide (V205) andrender it catalytically inactive. Thus, it becomes a question ofhow often the TESCRreactormust go throughthe water dew point. For base-loaded units, there are infrequent scheduled outages. Since the TESCRreactor can be bypassed and 'buttoned up' to remainhot during forced outages ofa few days, the effective catalyst deactivation resulting trom this effect canbe easily minimized.
Inthe second full paragraph ofpage 4. S&L states that there is a "limited amount ofavailable cost inforn1ation" for TESCRs. This claimis not substantiated and is highly questionable. Companies with TESCRexperience can quite accurately estimate the cost ofa TESCRif asked to do so in the form ofarequest for proposal. Furthermore, the "average annual escalationrate of4.0%" seems to be high. A value of2.0

- 3.0% would seem to be more realistic, particularly in the current economic situation.
Inthe third full paragraph ofpage 4, S&L states thatan allowance was included inthe capital cost estimate for Unit 2 stack linermodiflcations. This is altogether Ulmecessary for the reasons outlined above. S&L continuesthat, "variable O&M costs include

... secondary fuel and catalystreplacement." The need for secondary fuel assumes a natural gas flred duct burner for the flue gas reheat, which is much more costly than using steam

- see additional comments earlier. However, ifnatural gas theoretically had to be used be used for reheat, a GGHE design with a gradient of25 F instead of50 F would cut the cost ofnatural gas inhalf Ifsteam is used for reheat, the natural gas consumption would be eliminated altogether. Assuming the unit is not turbine-limited, steam cost can be estimated based onhow many tons ofsteamthe unit needs to generate one MW and the sales price perMWofthe plant.
S&L's assumed catalystreplacement frequency of6 months (worst case) or 12 months (best case) is far too conservative. A worst case 3years and best case 5 years would be muchmore reasonable (see EPA'sprevious comment letters). In addition, NDDH'stechnical feasibility analysis set a minimum catalyst life threshold of 10,000 hours (greaterthan 12 months) for successful application ofSCR. Considering NDDH believes catalyst life for a TESCRwould be at least 10,000 hours, consideration ofthe low end ofthe cost estimates should be



### 26dismissed automatically. Eliminating the high cost for natural gas for the exorbitant 50 F reheat need and extending the catalyst exchange frequency to something reasonable will dramatically reduce the overall cost for TESCR.
Inthe fourth full paragraphthat begins onpage 4 and continues to page 5. S&L claims. ''the cost effectiveness ofa TE-SCR control system will be particularly sensitive to the cost of natural gas and ammonia." Again, the natural gas cost is inelevant ifthe consumption of steam is used for flue gas reheating. As far as the effect ofthe cost variations ofammonia, it would be the same for SNCR as it is for SCR. However. the cost effectiveness ofSNCRwill be much more affected by the variability ofthe ammoniaprice thanthe cost etfectiveness of an SCR, since it not only reduces much less NO". but also consumes significantly more ammoniaperton ofNO" removed. S&L also claims that "installation ofa TE-SCRcould trigger the necessity to install additional pollution controls to address resulting increases in sulfuric acid mist emissions:' Acid mist emissions are only visible as aqueous H2S04 aerosols in concentrations above approximately 8 ppm. In a dry plume. which is the case downstream ofa TESCR. aqueous H2 S04 aerosols evaporate. This means that the TESCR system would have to 'create' a blue plume by converting enoughresidual**S~** to S03. This is extremely improbable considering the very low**S~** concentrations downstream ofa wet scrubber combined with the expected low S02/S03 conversionrates for the catalyst. EPA is unaware ofany operating TESCR in the world that has caused an acid mist plume.
In the first full paragraph onpage 5, S&L states that the two week unit outage time required for catalyst replacements every 6 or 12 months "were included in the aIU1Ual 0& M estimates." Shutting downthe unit for two full \veeks to replace catalyst is overly conservative. In Europe. a catalyst layer of 192 modules is typically replaced in less than five days and in the US. where catalyst exchanges have not been as streamlined as inEurope yet. changing 144 modules in many cases takes no more than a week. A catalystreplacement frequency ofonce every 3 - 5 years, meaning one layer at every scheduled outage would be a realistic assumption. Bituminous coal fired units typically exchange a layer ofcatalyst during every scheduled outage. whichtypically occur every 12- 24 months.
Onpages 7 - 16, the cost estimates cannot be verified since neitherthe actual financial model used nor all the cost assumptions and estimates were made available. Thus. EPA cmmot provide detailed comments. However. some individual observations are: 

## • The installed catalyst volume of530 m3seems to be very high for a TESCR. This is a realistic HDSCRnumber. Typically. cyclone fired units require about 1.5 

### m' ofcatalyst perMW for a HDSCR. Typically. TESCRs have less thanhalfthe catalyst volume ofHDSCR. which would bring the number down significantly.



### • The selected NO" removal efficiency of85% is unnecessarily low. resulting in a higher $/ton calculation. TESCR systems withNO, removal efficiencies in excess of90% have been in operation in Europe for more than 20 years. 

### 27

# - ,

• All scenarios presented (with the exception ofscenmio E) assume a capacity**t~lctor** of92.3%. which is a result ofthe erroneous assumption ofa 6 months catalyst replacement cycle. Since this is presumably calculated as lost generation, it artificially inflates the O&M costs for those scenarios.

• The price of$7,500 per m3 ofcatalyst is much higher than reality. Catalyst sells currently in the range $4,500

- $6,500 perm3 depending onvolume per order.

• The powercost of5 cents perkW seems to be very high. It should be veritied for how muchthey really sell theirpower, since this number should then be used to calculate the cost for a ton ofsteam for reheat (assuming the unit is not turbine limited and the boiler could not simply produce more steam for reheat without a MW output penalty).

• Natural gas prices are cun'ently between $3 to $5/mmBtu rather than $8 to $12/mmBtu as assLUl1ed.

• Ammonia costs are curreritly more inthan range of$300

- $400 per tonrather than the $450

- $700 perton.

• Tables 2.5-1 and 2.5-5: Without the detailed tinancialmodel, EPA simply notes that SCRretrofits in the US are well belowthe $/kW price range calculated by S&L here.



### 28

### ENCLOSURE 3 Institute ofClean Air Companies' May 2009 White Paperon Selective Catalytic Reduction (SCR) Control ofNOx Emissions from Fossil Fuel-Fired Electric PowerPlants



### 29