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 of Air Quality 

Environmental Health Section 

North Dakota Department of Health 

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 preliminary review of North 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 comment version of the SIP are detailed in 

Enclosure 1 to this letter. In addition, Enclosure 2 contains our detailed comments on the North 

Dakota Department of Health/Basin Electric cost analyses for selective catalytic reduction, and 

Enclosure 3 contains the referenced Institute of Clean 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 of the draft Regional Haze SIP prior to finalizing and adopting the documents for 

submission to EPA. We emphasize that we will only come to a final conclusion regarding the 

adequacy of North Dakota's Regional Haze SIP when we act on the North Dakota Regional Haze 

SIP revision, through our own public notice and comment rulemaking. 

We want to acknowledge your efforts in developing this difficult SIP and in working with 

us over the course of its development as issues arose. This effort has helped to narrow the issues 

significantly. However, important issues remain. Please note our most serious concerns are 

summarized at the beginning of Enclosure 1. 

As you are aware, North Dakota received a finding of failure 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 

fA 

t.~ Printed on Recycled Paper 
· .
 

SIP or promulgate a Federal Implementation Plan by 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. If you have any questions on EPA's comments, please contact me at 

303-312-6434, or have your staff contact 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 

2
 
ENCLOSURE 1
 

EPA Region 8 Preliminary Comments on
 

December 2009 Draft Regional Haze SIP (Public Comment Version)
 

Summary of Major Concerns - (see detailed comments for more information): 

•	 In an October 23, 2009 letter, EPA provided comments to the North Dakota Department 

of Health (NDDH) on the Federal Land Managers (FLMs) consultation version of the 

draft North Dakota Regional Haze SIP. These comments included, among other things. 

concems regarding the modeling methodology used to exempt Montana Dakota Utilities 

(MDLJ) Heskett Station Unit 2 from the BART requirements. 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. MDU recently completed the revised modeling and provided the results in a 

December 17,2009 report. The revised modeling results show the facility is exempt from 

the BART requirements. EPA has obtained and is reviewing the modeling tiles to verify 

these results. Given that this updated modeling was completed after the start of the 

CUlTent public comment period on the Regional Haze SIP, EPA will provide separate 

comments if the revised modeling fails to address our concems. Please note that NDDH 

will need to revise the SIP to include the updated modeling and your related conclusions. 

The revision will need to follow North Dakota's public participation process for SIP 

revisions. See comments #3 and #21 below. 

•	 We find that certain assumptions used in the cost analysis of selective catalytic reduction 

(SCR) for NO, control at Leland Olds and Milton R. Young are unsubstantiated and 

likely inappropriate. If more reasonable assumptions are used, the analysis will likely 

show SCR to be cost eiTective on the three cyclone units (M.R. Young Units 1 & 2 and 

Leland Olds Unit 2). For further guidance. please refer to EPA' s Guidelines for BART 

Detem1inations (70 FR 39104. July 6. 2(05) and our comments on the 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. 

•	 In the Coal Creek NO, BART detennination. the elimination of SCR and selective noncatalytic reduction (SNCR) based on uncertainty surrounding "potential" ammonia 

contamination of fly ash is not appropriate. The BART detennination should be based on 

the 5-factor analysis, including any necessary data to address this question (see 70 FR 

39166, July 6,2005). See comment #39 below. 

•	 Based on your analysis, there appear to be available controls under Reasonable Progress 

that cany similar costs to those found reasonable under BART. Given that these controls 

would provide some additional visibility improvement. the analysis does not support your 

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conclusions that it is 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 explain this 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 Permit to Construct doesn't require compliance with the revised 

NOx limit until July 1, 2019. Therefore, it is not appropriate to include the reduction in the 

2018 inventory. 

3.	 Exclusion of Montana Dakota Utilities Heskett Unit No.2, p. 66-68: 

(A) Table 7.2 - This table will need to be revised to include updated 98th percentile visibility 

impact results based on approved modeling. 

(B) We are in the process of reviewing MDU's December 17,2009 revised modeling report. 

EPA will provide additional comments on this issue if the revised modeling fails to address 

our concems. See COlllment #21 below for lllore detail. 

4.	 Section 7.4.2, Depal1ment BART Detenninations, p. 69-77: The modeling to detennine if 

each BART-eligible source has a significant impact on visibility was pertonned by NDDH 

using the CALPUFF model following EPA's Interagency Workgroup on Air Quality 

Modeling (lWAQM) Phase 2 Summary Report and Recommendations for Modeling Long 

Range Transport Impacts specified in the Guidelines for BART Detenninations Under the 

Regional Haze Rule, 40 CFR Part 51, Appendix Y. However, NDDH conducted an 

altemative cumulative visibility modeling approach in the NOx BART determinations for 

M.R. YOWlg and Leland Olds because it believes single source modeling results "tend to be 

five to seven times larger" than results when the 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 belief is that the perceived change in visibility from 

controls on a single source is reduced when background contributions from other sources al'e 

included in the modeling. 

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EPA does not agree that the single source modeling under the BART Guidelines overstates 

the degree of visibility improvement from emission reductions at the source. The Clean Air 

Act establishes a National goal of eliminating man-made visibility impairment from all 

mandatory Class I Federal areas. Use of a clean background (i. e.. not considering other 

nearby sources) is consistent with the ultimate goal of the program to reach natural 

background conditions. Moreover, the consistent use of a clean background in BART 

evaluations in North Dakota and surrounding states will foster emission reductions that will 

speed achievement of natural background conditions, and will ensure equity among states in 

achieving this goal. The NDDH has already modeled the 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 of visibility 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 of both 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 1 may 

result in too high a limit when buming Powder River Basin (PRB) coal. Please see our 

comment #49 below for 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 on the related 

BART determinations. 

7.	 Section 8.5.1, Hybrid Modeling System, pp. 95-96: The NDDH utilized a hybrid modeling 

approach for detemlining the status of its Class I areas with respect to the rate of progress 

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 of evidence analysis to evaluate the effect of 

emission sources located outside of North Dakota. Please note that the last version of this 

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 of technical changes in the CALPUFF modeling system and 

EPA/FLM recommended default settings since NDDH proposed the CMAQICALPUFF 

hybrid modeling approach in 2007. In the Reasonable Progress modeling, the hybrid 

CALPUFF/CAMx modeling results were actjusted based on IMPROVE monitoring data, and 

it is not clear whether the use ofthese obsolete settings affected the weight of evidence 

factors or the Reasonable Progress demonstration. The settings NDDH used in the 

CALPUFF model within the hybrid modeling system would not be considered technically 

5
 
sound if contained in a regulatory modeling protocol for a future project. However, in this 

instance it does not appear to have made a ditTerence since North Dakota is not able to meet 

the unifoffil rate of progress with either the WRAP analysis or NDDH's hybrid modeling 

system. 

8.	 Section 8.6. L Hybrid CMAQ-CALPUFF Perfoffi1ance Evaluation, p. 132, 1

st paragraph, 1st 

.sentence: Model perfonllance was tested for the 90th percentile days. In addition, NDDH 

needs to compare perfoffi1ance on the 9th percentile day consistent with the BART metric. 

9.	 Section 8.6.2.3, Apportionment by Source Group, pp. 146-153: We note that focus was on 

North Dakota EGUs and boundary condition groups due to their relatively "small" and 

"large" contributions, respectively. Since NDDH needs to be looking at what is within its 

control, N0l1h Dakota EGUs become the largest contributors. We also note that North 

Dakota's N03 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 of North Dakota 

EGUs, these EGUs comprise only a small component of total 20% worst day impacts at 

TRNP and LWA. The text needs 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 each EGU. 

11. Section 9.5.1, Step 1, pp. 177-181: We have several comments related to 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 of primary PM if emissions are large. Next. please note that the reference to the 

BART Guidelines under the 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 12,2009 preliminary comments on the WRAP's May 18,2009 

Draft Supplementary Informationfor Four-Factor Analysesfor Selected Individual fc/citities 

in North Dakota. the reliance on a 1982 NSPS analysis for Claus Sulfur Recovery Units 

raises questions regarding why newer data could not be utilized. Advancements in energy 

efficient teclmology and heat transfer media may affect tail gas treatment unit operational 

6
 
needs. 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 over into the North 

Dakota SIP. 

(8) There appear to be nwnerous NOx controls available at costs similar to, or less than, those 

selected under BART, raising the question of why Antelope Valley and Coyote Station 

wan'anted a decision by NDDH that NOx controls carry excessive costs. Since NDDH has 

already detennined BART controls - 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 

be justified. 

(C) Some average cost effectiveness fIgures are lower for control options that provide greater 

reductions. e.g., Low NOx 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 of these options wan-ants further consideration by NDDH. 

(D) The estimated cost effectiveness of control options for Tioga Gas Planfs rebuilt 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 at peak performance. It 

appears that NDDH relied on the WRAP's May 18.2009 Draft Supplenlentm~v Information 

lor Four-Factor Analvses for Selected Individual 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 of reductions 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 of 80% 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 of a 

control option. 

13. Section 9.5.1. Step 3. p. 183-185: Visibility improvement is not one of the four Reasonable 

Progress statutory factors (cost of compliance. time necessary for compliance, energy/non-air 

quality environmental impacts of compliance, and remaining usefu1life of any potentially 

affected sources). but the State has the flexibility to consider it in decision-making. The State 

selected a number of emission 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 of the 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 controlling these sources as well. The 

7
 
relatively low visibility benefit for controlling an individual unit should not be a major factor 

to consider when selecting Reasonable Progress measures: given the ultimate purpose of the 

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 98 th 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 NDDH has 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 on the WRAP's May 18,2009 Draft Supplementary lr!tormationfor 

Four-Factor Analyses for Selected Individual Facilities in North Dakota. this timeline for 

compliance seems to be overestimated and/or doesn't accolmt for steps that can be completed 

in parallel. In addition, the time necessary for compliance should not include time to develop 

regulations. If new regulations are necessary, such regulations need to be submitted with the 

forthcoming SIP. The WRAP report indicated that two years may be needed to develop the 

rules to implement Reasonable Progress strategies. This statement implies that the State 

lacks authority to develop and submit a SIP to address Reasonable Progress 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 North Dakota SIP. 

15. Section 9.5.1, Reasonable Progress Goals - Required Controls for Point Sources, p. 186-187: 

Again for comparison. since NDDH has chosen to rely on visibility improvement in 

detem1ining Reasonable Progress controls, it is appropriate to also provide and consider the 

981h percentile day results in aggregate. In addition, given that the cost effectiveness ($/ton) 

for reducing emissions at a number ofthe sources considered tor Reasonable Progress 

controls is similar to, 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 in the current plmming period. 

16. Section 9.5.4, Coyote Station, p. 189: It appears that NDDH believes at least this minimal 

level of control is reasonable now. As such, why isn't it included as a required Reasonable 

Progress control in the SIP? Further, why is the related Permit to Construct contained in 

Appendix A, BART Modeling Protocols and Analyses? Finally, this "agreement" must not 

preclude NDDH's re-evaluation of this source in future planning periods. 

17. Section 9.6, Visibility Modeling and Weight of Evidence, 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 or the 

amount of time necessary to achieve natural conditions" - is misleading. Visibility 

improvement in aggregate should result in more progress. These sources are within NDDH's 

control (as opposed to the Canadian sources) and are cost effective to control. We 

8 
understand that NDDH is not able to meet the unifol1n rate of progress in this planning 

period, but this does not justify the lack of Reasonable Progress controls on these sources. 

18. Table 9.14, Reasonable Progress Goals. p. 195: The addition of the 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 added that 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: Although NDDH has 

determined that it is not reasonable to control these sources during the current plmming 

period. this section implies 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 of authority as 

justification for elimination of Reasonable Progress controls in the current plmming period 

nor is a commitment of this nature acceptable to address requirements. 

21. Appendix A.2.2. AECOM's August 12,2009 Response to Concems Regarding BART 

Exemption Modeling for Heskett Unit 2: 

(A) NDDH's 2006 CALPUFF BART exemption modeling indicated that baseline emission 

impacts would result in a visibility impact of 0.82 deciviews (dv) at TRNP and 0.58 at LWA. 

Predicted visibility impainnent exceeding 0.5 dv would make the facility subject-to-BART. 

MDU then contracted \vith ENSR to make refinements to the State's analysis that included 

reducing the grid size from 3 km to 1 km and a number of other 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 completed the 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 reviewing the modeling files to verify these results. 

Given that this updated modeling was completed after the start of the current public comment 

period on the Regional Haze SIP, EPA will provide additional comments on this issue if the 

revised modeling fails to address our concerns. Please note that NDDH will need to revise 

the SIP to include the revised modeling and your related 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. 

9 
22. Appendix B.5, BART SCR Technical Feasibility Analysis for North Dakota Lignite: 

(A) While we agree with your detel111ination that Low Dust SCR and Tail-End SCR are 

technically feasible, we do not agree with all of the technical aspects or conclusions of the 

analysis, especially as they relate to High Dust SCR. As you know, we hlVe done a thorough 

review ofthe technical feasibility analyses submitted by Minnkota for Units 1 and 2 at Milton 

R. Young Station and NDDH's preliminary BACT detennination published for public notice 

on June 11,2008. Our comments and supplemental information were provided in previous 

letters from EPA Region 8' s Office of Enforcement, Compliance, and Environmental Justice, 

to the North Dakota Department of Health, Division of Air Quality. Our letters provided 

substantial inforn1ation and evidence that all SCR teclmology. 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 of the Institute of Clean Air Companies (lCAC) May 2009 White Paper on 

SCR Control of NOx Emissions from Fossil Fuel-Fired Electric Power Plants, contained in 

Enclosure 3 for your use. This paper addresses feasibility of SCR on lignite-tired boilers and, 

while noting "[l]ignite from different mines has some common characteristics but also differs 

in some significant ways," states that "[w]ith proper design, lignite applications can be 

successful." The ICAC paper addresses the teclmical issue of high 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 SCR Cost Estimate: 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 Basin Electric 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 SCR in its BART detelminations for Leland Olds Units 1 & 2. These 

assumptions result in calculated costs for TESCR that are biased high. If a more reasonable 

set of assumptions are incorporated into this analysis, it will likely show SCR to be cost 

effective on the cyclone unit (Leland Olds Unit 2), and it may also be cost effective for the 

wall-tired unit (Leland Olds Unit 1). Please see our detailed comments in Enclosure 2. 

24. Appendix C.4, November 2009 Minnkota Supplemental NO, BACT Analysis Reports for 

Units 1 & 2: In response to Minnkota's Supplemental BACT Reports, NDDH sent a 

November 25, 2009, letter to Minnkota citing a lack of detailed and comprehensive cost data 

documentation in the Supplemental BACT Reports and the failure to address the use of main 

boiler steam for flue gas reheat. NDDH requested that this information be submitted, as well 

as a demonstration that the cost of NO, removal for SCR is disproportionately high compared 

to the cost ofNO-, control in other recent Best Available Control Teclmology (BACT) 

detenninations for coal-tired power plants. EPA has reviewed the Supplemental BACT 

Reports and wholly supports the statements in NDDH's November 25, 2009 letter. Given the 

fact that you are not satisfied \vith Minnkota's analysis and have requested additional 

10
 
supplemental infonnation, it is not appropriate to rely on this cost analysis in the BART 

context at this time. EPA has also identitled additional problems and concerns with the 

Supplemental BACT Rep0l1s which must be addressed for BART purposes as welL in 

accordance with the requirements of 40 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 both units, 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 BACT Reports is much shorter than EPA would expect for Low-Dust 

Selective Catalytic Reduction (LDSCR) and TESCR systems. Furthennore, the assumption 

that one layer of catalyst would be replaced during each plalmed boiler cleaning outage is 

made without any justification and should therefore be given little to no credibility in the 

final conclusions of the BACT analysis. 

(C) All vendor correspondence related to catalyst costs and replacement, as described in the 

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 BACT Reports give a general description of how the pressure 

drops and parasitic loads were calculated, Mimlkota or NDDH must provide more details, 

including calculations to justify these high values. 

(E) No data is provided for the temperature gradient of the 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 of flue gas reheat of 600 ,1 F must 

be justified. 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 "on coal-fired 

power plants in the United States that could be used. with adjustments. to properly 

represent total installed cost" for MRYS. Milmkota or NDDH should consider the 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 higher than current 

prices and must be substantiated. Furthermore. the Supplemental BACT Rep0l1s assume 

11 
. ..
 

urea would be used as opposed to anhydrous ammonia. Both options should be evaluated 

and the 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 of your 

responses to FLM comments, you cite to EPA's August 28,2009 Advanced Notice of 

Proposed Rulemaking (ANPR) regarding the Four Comers Power Plant BART analysis. The 

ANPR does not represent an Agency decision but rather includes infonnation on which EPA 

Region 9 seeks comment. At this point, no Agency position has even been proposed, 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 of control options and proposed limits should not 

be based on worst-case coal scenarios and/or highest calendar year emission rates. Use of 

averages should allow for accommodation of worst-case situations and will ensure that the 

more common conditions are adequately limited. 

27. NOx analyses, Step 3: Evaluate Control Effectiveness of Remaining Control Technologies: 

Based on our comments #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 of the 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 of control 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 eliminate the 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 over to these documents. TRNP was identified as a single national park under the 

Clean Air Act Amendments of 1977 (42 U.S.c. 7472); thus, there is only one mandatory 

Class I Federal area for this park. By dividing this Class I area into 3 units, there may be 

slight reductions in benefits predicted when modeling the visibility etlects of applying 

controls. 

12
 
NDDH Proposed Permits to Construct - Pertaining to All Permits (except Coal Creek) 

29. Section Il.A.2., Compliance Date: The last phrase " ... approves this pe1111it as part of the 

BART SIP" needs to be revised to " ... approves this pem1it as part of the 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 with the use of 35(s) as an alternative emission factor for S02. NDDH's 

response did not adequatdy justify the use of the alte111ative. The alte111ative factor was 

based on a study contained in NDDH's periodic review of PSD S02 increment consumption. 

In that study, an emission factor of 37.4(s) was proposed. For the Leland Olds BART 

determination, an emission factor of 35(5) was used to provide a conservative estimate of the 

uncontrolled emission rate. 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 power plants in North Dakota and elsewhere. EPA has concerns about using 

recent CEM data to adjust emission factors given that coal quality may have changed over the 

years, or may change in the tllture. However. in this instance it does not appear that the use 

of this alte111ative emission factor affects the results of the S02 BART detennination. 

31. Units 1 and 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 our review of Basin Electric'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 TESCR cost analysis. Please 

see Enclosure 2 for more detail. as well as our comments #22-23 above. Step 3 of the BART 

determination needs to be revised to address these conce111S. These revisions are likely to 

considerably improve the cost effectiveness of TESC R for each unit, making it a reasonable 

selection for BART. In addition. this version of the draft BART detelmination includes new 

cost estimates for LDSCR. As explained above. it is unclear how the cost values for LDSCR 

were derived. 

32. Unit 1 NO., BART evaluation, Step 3. p. 13: We note your reference to EPA's August 28. 

2009 Advanced Notice of Proposed Rulemaking (ANPR) regarding the Four Corners Power 

Plant BART analysis to support the use of an 80% control eHiciency for SCR with reheat. 

13
 
The ANPR does not represent an Agency decision but rather includes information for which 

Region 9 seeks comment. At this point. nothing has even been proposed much less tinalized. 

it is not appropriate to rely on the ANPR to support your position regarding BART analyses 

in North Dakota. NDDH needs to explain why the more commonly accepted tigure of 90% 

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 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 of this letter). 

33. Unit 2 NO" BART evaluation, pp. 23-31: 

(A) Per the BART Guidelines, EPA has found that the use of SCRs at large cyclone units 

burning lignite enables the units to cost-etfectively meet NO" rates of 0.10 Ibs/MMBtu. A 

revised cost analysis, using the necessary adjustments we have described in comment #23 and 

Enclosure 2, will most likely show that SCR is cost effective at this large boiler. 

(B) For BART detenninations, visibility improvement must be based on the 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 1 and it must not be 

used for Unit 2. 

(C) There appears to be a typographical error at the beginning of the last paragraph on p. 30­

should be "BART' instead of "BACTT 

34. The "References" section includes NDDH's 2005 Proposed Alternative Air Quality Modeling 

Protocol to examine the status of attainment of PSD Class I increments. This protocol was 

never approved by EPA, and contested elements of this protocol 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 - should be Falkirk Mine instead of Center Mine? 

36. S02 analyses, Step 5, p. 11: The reader is refened to the Great River Energy (GRE) BART 

Analysis, pp. 47-51, for visibility improvement analyses. While the 98th percentile results are 

provided in the 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 

14 
needs to extract the relevant nth percentile results from the GRE analysis - by pollutant and 

by specific scenario - and incorporate them directly into the BART detem1ination document. 

We note that this infoDnation has been added to the NOxevaluation section but 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 of Remaining Control Teclmologies, 

pp. 15-16: NDDH needs to explain why it accepted GRE's suggested 80% control efficiency 

for LDSCR instead of using the generally accepted 90% efficiency. For more 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 of this letter). 

39. NOxanalyses. Step 4: Evaluate Impacts and Document Results, p. 17: 

(A) The elimination of SCR and 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 data to address this question. GRE 

claims that installation of SCR or SNCR may 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 other technical or commercial data to support its claims. See 40 CFR 

51.308(e)(I). (SIP must include documentation for BART analyses.) It is our understanding 

that installation of SCR and SNCR result in very little, if any, impacts to 11y ash sales since 

the ammonia slip for each control is now very low -less than 2 ppm for SCR and less than 5­

10 ppm for SNCR. Given that this concem wasn't raised at the other BART sources where 

you have proposed SNCR, we know of no reason for it to apply to Coal Creek. We note that 

you cite to an example fi:om Nebraska to suppOl1 your decision. Please be advised that the 

cited example is from a draft BART detem1ination analysis. The State of Nebraska has not 

submitted to EPA Region 7 its BART detennination analysis as part of a tinal Regional Haze 

SIP. EPA Region 7 has not, and will not, make a detem1ination regarding the approvability 

of Nebraska's BART deteDninations until it reviews all components of the tinal Nebraska 

Regional Haze SIP and acts on the revision through its own public notice and comment 

rulemaking. 

40. Evaluate Visibility Impacts, Step 5, pp. 17-19: We note that you have extracted the visibility 

impacts data from the GRE BART analysis to include in the NOxBART evaluation. 

However. it appears that you have presented the combined results for S02 and NOx controls, 

not just the NOx results. Please clarify. 

15
 
41. Summary, p. 23: Please correct typographical errors in the SOz BART limits for Unit 1 and 

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 of 94%. 

Milton R. Young: 

NDDH BART Detennination 

43. Unit 1 and Unit 2 NOx BART evaluation: 

(A) In addition to objecting to selection of SNCR as BART based on the North Dakota 

record, we also object to your detennination that separate NO" limits are appropriate for 

startup. The record does not justifY the need for such separate limits, nor does it justifY 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 of no 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 of a negotiated compromise in the context of an enforcement action. The 

Consent Decree tem1S are not binding in the context of this BART determination, and 

Paragraph 66 of the Consent Decree in no way settles whether separate startup BART limits 

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, and perhaps the overfire air system, will not work 

optimally during startup. Of course, 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 1 and 

that noncompliance of this 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 air pollution control practices to minimize emissions during 

16
 
this period or to minimize the duration of the staIiup, whether this length of staliup was an 

anomaly, or what the average emissions rate was during this period. There is no mention of 

staliups at Unit 2 or whether the 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 margin of safety 

for operational variation. 

Also, NDDH has not evaluated potential impacts ofthe separate startup limits on visibility or 

why the separate limits represent BART. We have found no indication that the proposed 

startup limits represent the most stringent level of control 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 1 or are 

warranted. 

Even if we found the separate startup limits to be.i ustified, 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 of startup? How will startups that are less than 24 hours 

be accounted for in calculating 24-hour averages? Finally, we question the use of heat input 

levels to define the end of staIiup 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 greater than the reported 

nameplate capacity of 734 MW, in fact. > 750 MW. In a November 20, 1995 letter, 

Minnkota advised NDDH that M.R. Young was operating at levels above naIneplate and 

requested a change in the pemlit description of each unit to 277 MW for Unit 1 and 517 MW 

for Unit 2. These changes ret1ected the capabilities of the units as they "are cunently with 

respect to generator output" and result in a total generating capacity of at least 794 MW. Per 

the BART Guidelines, EPA has found that the use of SCRs at cyclone units buming lignite 

should enable these large units to cost-effectively meet NOx emission rates of 0.1 0 

Ibs/MMBtu. 

(C) We assume that NDDH has revised its cost estimates based on MiImkota's November 

2009 Supplemental NO\ BACT Analysis Reports for Units 1 & 2. Minnkota's revised cost 

analyses are unsubstantiated and highly questionable in many regards, as discussed in 

comment #24 above. Based on our review of Minnkota's supplemental reports and this 

BART detennination, the NO, BART detenninations need to be revised to address these 

issues. Revisions, per our comments. are likely to considerably improve the cost 

effectiveness of SCR for each unit, 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 SCR alone. Please see the 

proposed and final Standards for Perfonnance for Electric Utility Steam Generating 

Units, Industrial-CommerciaL-Institutional Steam Generating Units. and Small IndustrialCommercial-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). Mimuwta's own cost analysis uses 93.8% 

combined control and 90% control beyond ASOFA with SCR. The BART detennination 

simply states that NDDH believes a reduction of 90% for ASOFA and SCR is "more 

appropriate on a long-tenn basis" without providing any rationale. Using a lower control 

efficiency results in significantly inflated $/ton values. 

(2) The footnote on the cost tables (p. 14 and p. 29) indicates that the cost range provided 

is based on the ditTerence in applying SCR to each unit as a stand alone retrotit (high end 

cost) and applying SCR to both Units 1 & 2 with shared facilities (low end cost). 

Minnkota provided these scenarios in its cost analysis. However, it appears the difference 

between the low and high end ofthe am1Ualized cost range in NDDH's BART 

detelmination is based on "Scenarios A & B" in Minnkota's cost analysis. Scenario A 

(the lower cost) assumes a catalyst layer replacement (and unit outage time) every 16,000 

hours. while Scenario B (the higher cost) assumes a catalyst layer replacement (and 

additional unit outage time) at each scheduled boiler cleaning outage. For Unit L this is 

three times a year and for Unit 2 this is four times per year. EPA believes that Scenario B 

is not realistic for a LDSCR or TESCR and should be completely disregarded. It appears 

as though NDDH is in agreement, but inadvertently used the Scenario B values for the 

high end ofthe cost range. rather than using the stand-alone values. In addition to 

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 the higher annualized cost estimate (based 

on a stand alone unit instead of Scenario B) leading to a much smaller range between the 

low-end and high end estimates. The lower cost estimate (representing shared costs 

between Unit 1 and Unit 2 for Scenario A) and the higher cost estimate (representing 

Scenario A stand alone unit) should be as follows: 

Unit 1 LDSCR: $31,749,000/$36,872.000 

Unit 1 TESCR: $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 submitted by 

Minnkota) and the worst case scenario cost described by NDDH in the BART 

Detennination (stand alone unit costs, Scenario A), the follol,ving represents the high-end 

costs for Units 1 & 2: 

18 
Scenario 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 

On p. 17 of the BART Oetennination for Unit L NOOH "considers the cost effectiveness 

and incremental cost of SCR + ASOFA at the low end of the cost range to be reasonable:' 

while the higher end of the range was considered excessive. However. NOOH made this 

determi nation based on an error in the calculation of the 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 conected high-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 in the BART 

Oetem1ination. as well as NOOH's criteria for teclmical feasibility, i.e .• a catalyst 

replacement schedule of 3-4 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 "Stand Alone" facility costs, and more appropriate NO" removal 

et1iciencies are assumed (as provided by Minnkota). the high-end costs become very 

similar to (and in some cases lower than) what the NDDH BART Detennination 

calculated as low-end costs deemed to be reasonable. There is little difference in these 

high-end cost effectiveness values for Units 1 and 2. As such. EPA concludes that even 

without examining the concerns and problems with Minnkota' s initial cost values. as 

discussed in comment #24 above. the existing infonnation for the BART Detennination 

demonstrates that SC R is cost effective. Once appropriate adj ustments 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 

on the BART Guidelines overpredicts the visibility improvement in NOlih Dakota. 

19 
44. Unit 2 SOl Evaluation, Step 3, p. 21: We note the baseline SOl emissions have been revised 

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 - Milton R. 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 condition that 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 of Unit 1 and Unit 2 is not 

consistent with the language in the BART detemlination document, Section IX. The BART 

detennination includes a fonnula and definition for Average Allowable Emission Rate 

(AER), which is not included in the pemlit. Please clarify. 

Stanton: 

NDDH BART Determination 

48. S02 BART evaluation in general: NDDH notes that a circulating dry scrubber was 

eliminated from consideration due to excessive incremental costs. HO\vever, EPA would not 

find the cost effectiveness of this option ($1631 /ton) unreasonable compared \vith other 

BART detenninations reviewed. 

49. SO:? BART evaluations for lignite and PRB coal, pp. 8 and 22: In an effort to assess the coal 

quality basis for NDDH's proposed S02 BART detenninations 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) of lignite and PRB coal are available for a wide variety of sources through 

. CAMD, and for 1110St (if not all) of the large coal mines in the region. We would be happy to 

share this information with NDDH, if desired. Since these data are readily available, we see 

no need for the use of a 33% multiplication factor to adjust an annual average emission rate 

to a 30-day rolling average emission rate. 

Based upon our review of the lignite coal quality data in the CAMD database for 2007-2009, 

it appears that NDDH's proposed SOl BART limit of 0.24 Ib/MMBtu when burning lignite is 

in the range of what we'd expect to see at a 90% control efficiency. However, we wish to 

note that ifNDDH believes that the proposed Spray Dryer Absorber and Fabric Filter will be 

able to achieve 90% reduction of S02 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. 

20
 
Based on our review of the 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 emission potential of PRB coaL then applied 90% control efficiency to yield 

0.12 lb/MMBtu controlled 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/MMBtu emission 

potential for PRB coal was apparently based on coal sulfur content of about 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 of the largest PRB 

coal mines reveal that PRB coal typically has much lower sulfur content on a 3D-day average. 

about half of the 0.64~/o used by NDDH. Our analysis of that data yielded an average S~

emission potential of 0.78 lb/MMBtu, on a 30-day basis, for all of the PRB coal mines 

together. 

It appears that NDDH wishes to use the high end of a 95% contldence interval rather than an 

average value to set the 90% reduction limit. Therefore. we have averaged all the high end 

values of all the 95% confidence intervals for all the PRB mines for which we obtained data. 

The average of these 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 of 0.095 Ib/MMBtu. on a 30-day rolling average. 

50. NOx BART evaluation: As we have commented in previous conespondence, the 45% 

control efficiency assumed for the alternative of combining combustion controls plus SNCR 

is lower than 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 SCR technology, including High Dust 

SCR, is technically feasible at facilities burning North Dakota lignite. 

NDDH Proposed Penni! to Construct for BART - Stanton 

51. 1l.A.3., Continuous Emission Monitoring (CEM): Based on 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 pennit needs to be revised to specify that the CEM 

location for a particular pollutant is downstream of controls for that pollutant (unless control 

efficiency is being measured by a combination of upstream and downstream CEMs, in which 

case one of the CEMs for that pollutant would be upstream of controls). 

21
 
Coyote: 

NDDH Proposed Pennit to Construct - Coyote Station 

52. Based on your discussions with Otter Tail Power Company, it appears that this level of 

minimal control is considered reasonable at this time. Therefore. even if you disagree with 

our other comments regarding Reasonable Progress, at least this level of NOx control should 

be included in the SIP as a required Reasonable Progress control measure. As such, the 

pennit should more closely mirror the BART pennit fOffi1at, including the appropriate 30-day 

rolling average emission limit, compliance date no later than 2018 (or sooner if reasonable), 

and compliance detennination, monitoring, recordkeeping, and reporting requirements. 

53. ILA.2, Compliance Date: There appears to be a typographical error in the heading- should 

be "Date" instead of "Data." 

22
 
ENCLOSURE 2
 

Comments on Basin Electric Cost Analysis 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 their consultant. Sargent & Lundy (S&L). This cost analysis was rel~d upon by 

the North Dakota Department of Health in preparing its Best Available Retrofit Teclmology 

Determinations. Basin Electric and S&L go to great lengths in the May 2009 submittal 

describing their reservations with applying a TESCR to a unit fired on North Dakota lignite. 

since an SCR has never been installed and operated on such a facility. These claims have 

been repeated extensively in the context ofthe BART process for both Basin Electric's 

Leland aIds Plant and Minnkota Power's Milton R. Young Station (MRYS). as well as in the 

context of the NOx BACT analysis that was submitted by Minnkota for MRYS. EPA has 

previously submitted substantial comments on these technical issues in both contexts and 

stands by those previous comments. As such, they will not be repeated here in detail. except 

as they apply to the cost estimate. We believe NDDH has 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 Basin Electric's May 29. 2009 Cover Letter: 

In the cover letter to the S&L analysis. Basin Electric states that "design factors of the SCR 

(catalyst volume and surface area). reagent injection rates. reagent slip and economic 

volatility of the re-heat fuel are unknown:' These claims t:1il to consider: 

o	 If steam is used for re-heating. which would likely be the preferred method of reheat. there is no economic volatility of the re-heat fuel. 

o	 The reagent (NH3) injection rate is detem1ined by the intended anunonia slip and 

the sought NOx removal et1iciency. Engineering calculations should be able to 

provide a reasonable estimation ofthis cost within an accuracy of +/- 5%. 

o	 Pelmissible reagent slip is a value that can be designed for and calculated based 

on the SO" content in the flue gas and the outlet temperature of the air heater. 

o	 Required minimum catalyst volume and surface area can be calculated from the 

sought NOx removal efficiency and the permissible NH" slip, as is done with 

other SCR installations. 

o	 The flue gas composition entering the SCR is used to estimate catalyst 

deactivation, which is then used to estimate the necessary catalyst volume. The 

Hue gas composition entering the SCR can be measured downstream of the ESP 

for a LDSCR or FGD for a TESCR. This Hue gas composition data allows an 

experienced catalyst supplier to estimate the catalyst deactivation rate with 

23
 
reasonable 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 of certainty for the purpose of the BART analysis. As stated in previous 

comments, the operating life of catalyst in a TESCR is usually much higher than the more 

conventional LDSCR and even greater compared to the most commonly-used HDSCR, and 

can be expected to be in the range of 50,000 hours. Other capital, 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 of page 3, S&L describes the sodium levels in North Dakota 

lignite and states, "[t]hese sodium levels, occurring in both the vapor and particulate phase, 

along with relatively high levels of potassium 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 of a wet scrubber - and paI1iculate matter, 

these alkalis can only poison the catalyst when made mobile by means of ion dissociation in a 

liquid. In other words, only when the catalyst in the TESCR is being cooled down to belo\\ 

the water dew point, such poisoning will occur. Since this does not happen often for a baseloaded unit, the rate of deactivation is comparatively slow, which supports the estimated 

50,000 operating hours for the TESCR catalyst. 

In the third full paragraph of page 3, S&L claims that, "[t]he TE-SCR would still have to be 

designed to handle vapor phase sodium and fine particulates that are not collected by the ESP 

and wet FGD." While EPA has already made extensive comments on this issue in the 

context of the technical feasibility aIlalysis, all vapors will condense in the wet scrubber and 

get mostly absorbed in the slightly acidic scrubber slurry (pH around 5.6- 5.8). Whatever 

passes through as a particle will not vaporize again unless sent through a flame, which would 

need to provide temperatures above the vaporization temperatures for these compounds (due 

to the non-homogeneous heat transfer distribution'with duct bumers). Thus, this could only 

happen if duct bumers are employed. In the case where a steam coil will be employed, such 

re-vaporization is highly unlikely to occur, since the vaporization temperatures of these 

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 of the steam coil is 

below the vaporization temperature of the compounds. As discussed extensively in the 

Minnkota BACT comments, the actual flue gas composition analysis data measured 

downstream of the wet FGD at MRYS proves that the amount ofsubmicron alkali aerosols is 

24 
so small that catalyst deactivation does not occur rapidly and a relatively long catalyst life can 

reasonably expected compared to 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 of the 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 of 50 F is certainly the 

worst case scenario. As demonstrated by more than 20 years of full-scale TESCR 

experience, a GGHE temperature gradient of only 20 F is technically feasible and has been 

demonstrated. Assuming a GGHE gradient of 50 F increases the Hue gas reheat cost by a 

factor of 2.5 compared to a GGHE with a gradient of only 20 F. The impact of this choice on 

the economics of the TESCR is very significant Second, it must be noted that this is the only 

time in the entire analysis where the use of steam 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 of fact, the vast majority of all TESCRs in 

power plant applications use steam for reheating due to several advantages over natural gas, 

including lower cost, no increase in flue gas volume How rate, and no risk of re-vaporization 

of particle bound and/or condensed catalyst poisons in the Hame of a duct burner. Third, 

there is no need to raise the Hue gas temperature in a TESCR to 600 F. As EPA has 

previously commented, a lower Hue gas temperature of 530 - 550 F is a sufficient 

temperature for a TESCR due to the low S02 concentration downstream of wet scrubbers. 

The higher the selected TESCR temperature is, the higher the actual t1ue gas volume flow 

rate will be and therefore,- the larger the GGHE, SCR reactor, and the ductwork will have to 

be. Therefore, the unsubstantiated assumption of using natural gas over steam for reheating 

signitlcantly and aliiticially inflates the cost estimate of TESCR. 

In the last paragraph on page 3, S&L states that "due to the limited etIectiveness of the 

GGHE, the outlet temperature from the TE-SCR system will be approximately 50 - 60 F 

higher ... resulting in a stack temperature of approximately 190 F." First, it unclear why the 

incremental reheat temperature has now increased above the already overly conservative 

value of 50 F up to 60 F. Second, it must be pointed out that S&L's claim conceming a 

"limited etIectiveness of the GGHE" is inaccurate. The thernlal efficiency of a well-designed 

GGHE is near 100% and has nothing to do with the 50 F gradient selected by S&L. Third, a 

stack temperature 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 of all droplets and aerosols passing through the 

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 higher the t1ue gas exist temperature is. the higher is the effective plume rise 

and thus the achieved dispersion of the residual air pollutants in the Hue gas. 

25 
In the first full paragraph of page 4, S&L states "the potential exists for sodium and 

potassium compounds remaining in the 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 through the 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 catalyst pores by means of moisture condensing out of the flue gas. This is 

because the water soluble sodium and potassium salts are then allowed to dissociate and 

migrate as cations into the catalyst pores and react with the catalytically active vanadium 

pentoxide (V205) and render it catalytically inactive. Thus, it becomes a question of how 

often the TESCR reactor must go through the water dew point. For base-loaded units, there 

are infrequent scheduled outages. Since the TESCR reactor can be bypassed and 'buttoned 

up' to remain hot during forced outages of a few days, the effective catalyst deactivation 

resulting trom this effect can be easily minimized. 

In the second full paragraph of page 4. S&L states that there is a "limited amount of available 

cost inforn1ation" for TESCRs. This claim is not substantiated and is highly questionable. 

Companies with TESCR experience can quite accurately estimate the cost of a TESCR if 

asked to do so in the form of a request for proposal. Furthermore, the "average annual 

escalation rate of4.0%" seems to be high. A value of2.0 - 3.0% would seem to be more 

realistic, particularly in the current economic situation. 

In the third full paragraph of page 4, S&L states that an allowance was included in the capital 

cost estimate for Unit 2 stack liner modiflcations. This is altogether Ulmecessary for the 

reasons outlined above. S&L continues that, "variable O&M costs include ... secondary fuel 

and catalyst replacement." 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, if natural gas theoretically had to be used be used for reheat, a 

GGHE design with a gradient of 25 F instead of 50 F would cut the cost of natural gas in half 

If steam 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 on how many 

tons of steam the unit needs to generate one MW and the sales price per MW of the plant. 

S&L's assumed catalyst replacement frequency of 6 months (worst case) or 12 months (best 

case) is far too conservative. A worst case 3 years and best case 5 years would be much more 

reasonable (see EPA's previous comment letters). In addition, NDDH's technical feasibility 

analysis set a minimum catalyst life threshold of 10,000 hours (greater than 12 months) for 

successful application of SCR. Considering NDDH believes catalyst life for a TESCR would 

be at least 10,000 hours, consideration of the low end of the cost estimates should be 

26 
dismissed 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. 

In the fourth full paragraph that begins on page 4 and continues to page 5. S&L claims. ''the 

cost effectiveness of a TE-SCR control system will be particularly sensitive to the cost of 

natural gas and ammonia." Again, the natural gas cost is inelevant if the consumption of 

steam is used for flue gas reheating. As far as the effect ofthe cost variations of ammonia, it 

would be the same for SNCR as it is for SCR. However. the cost effectiveness of SNCR will 

be much more affected by the variability ofthe ammonia price than the cost etfectiveness of 

an SCR, since it not only reduces much less NO". but also consumes significantly more 

ammonia per ton of NO" removed. S&L also claims that "installation of a TE-SCR could 

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 of a TESCR. aqueous H2S04 aerosols evaporate. This means that the TESCR 

system would have to 'create' a blue plume by converting enough residual S~ to S03. This 

is extremely improbable considering the very low S~ concentrations downstream of a wet 

scrubber combined with the expected low S02/S03 conversion rates for the catalyst. EPA is 

unaware of any operating TESCR in the world that has caused an acid mist plume. 

In the first full paragraph on page 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 down the 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 in Europe yet. 

changing 144 modules in many cases takes no more than a week. A catalyst replacement 

frequency of once every 3 - 5 years, meaning one layer at every scheduled outage would be a 

realistic assumption. Bituminous coal fired units typically exchange a layer of catalyst during 

every scheduled outage. which typically occur every 12- 24 months. 

On pages 7 - 16, the cost estimates cannot be verified since neither the 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 of 530 m

3 

seems to be very high for a TESCR. This 

is a realistic HDSCR number. Typically. cyclone fired units require about 1.5 m' 

of catalyst per MW for a HDSCR. Typically. TESCRs have less than half the 

catalyst volume ofHDSCR. which would bring the number down significantly. 

• The selected NO" removal efficiency of 85% is unnecessarily low. resulting in a 

higher $/ton calculation. TESCR systems with NO, removal efficiencies in 

excess of 90% have been in operation in Europe for more than 20 years. 

27 
- , 

•	 All scenarios presented (with the exception of scenmio E) assume a capacity 

t~lctor of 92.3%. which is a result of the erroneous assumption of a 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 m

3 of catalyst is much higher than reality. Catalyst sells 

currently in the range $4,500 - $6,500 per m

3 depending on volume per order. 

•	 The power cost of 5 cents per kW seems to be very high. It should be veritied for 

how much they really sell their power, since this number should then be used to 

calculate the cost for a ton of steam 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 in than range of $300 - $400 per ton rather 

than the $450 - $700 per ton. 

•	 Tables 2.5-1 and 2.5-5: Without the detailed tinancialmodel, EPA simply notes 

that SCR retrofits in the US are well below the $/kW price range calculated by 

S&L here. 

28
 
ENCLOSURE 3
 

Institute of Clean Air Companies' May 2009 White Paper on Selective Catalytic Reduction 

(SCR) Control of NOx Emissions from Fossil Fuel-Fired Electric Power Plants 

29