1 12/2/09 Response to DOI Comments October 23, 2009

Comment 1 : (Section Two: Overview)

We disagree with the statement on page 8 claiming t hat North Dakota has four mandatory federal

Class I areas as defined under the Clean Air Act. Based on the legislation establishing

Theodore Roosevelt National Park and the Clean Air Act, North Dakota has two mandatory federal Class I areas (i.e., Theodore Roosevelt NP and the Lostwood Wilderness Area). The entire acreage of Theodore Roosevelt NP is one Clas s I area under the Clean Air Act, and should be treated as such for all protection purposes, suc h as assessing for increment consumption and calculating visibility impacts.

Response : North Dakota has two Class I areas within its bo undaries: the Theodore Roosevelt National Park which consists of three separate and distinct units and the Lostwood National Wildlife Refuge Wilderness Area. The Department co nsiders the three units of Theodore Roosevelt National Park to be three separate areas for modeling purposes for the following

reasons:

A. Theodore Roosevelt National Park (TRNP) as a PSD Class I area consists of three units (see 44 FR (November 30, 1979) at 69125 and 69127, 40 CFR § 81.423 and NDAC § 33- 15-15-01.2 (Scope) relating to 40 CFR 52.21(e)). T he areas are not contiguous. The North Unit and South Unit are separated by approxim ately 38 miles.

B. Federal regulation, 40 CFR 51.301, states “ Adverse impact on visibility means, for purposes of section 307, visibility impairment whic h interferes with the management, protection, preservation, or enjoyment of the visitor’s visual experience of the Federal Class I area. This deter mination must be made on a caseby-case basis taking into account the geographic ex tent, intensity, duration, frequency and time of visibility impairments and how these fa ctors correlate with (1) times of visitor use of the Federal Class I areas, and (2) t he frequency and timing of natural conditions that reduce visibility. This term does not include effects on integral vistas.” (Emphasis added) Combining the three units of TRNP into a single area for visibility analysis fails to address the “geographic extent” o f any visibility impairment.

C. The North Unit is not visible from the South Uni t and vice versa. The commingling of receptors from the units for a visibility analysis misrepresents the ability of a park visitor

to observe features in another unit.

Any viewable scenes outside any unit of TRNP from w ithin the unit are “integral vistas”. The effects on integral vistas are not considered w hen determining whether an adverse impact on visibility will occur. There are no geol ogical features, terrain or structures in any unit of TRNP that are viewable from another uni t across the land regions separating the units. For example, terrain peaks in the South Unit would have to rise at least 9002

feet above terrain in the North Unit, due to the Ea rth’s curvature, to be seen by a visitor in the North Unit. So the visual range of visitors in one unit does not include aspects of

another unit.

D. The Department has treated the units as separate Class I areas for 30+ years for purposes of PSD increment consumption without objection from EPA or the FLMs prior to 2006.

E. Treating the three units as a single Class I are a effectively extends Class I status to areas

between the units which are classified as Class II by rule and law.

F. The units have three different names, the South Unit, the North Unit and the Elkhorn

Ranch Unit.

Comment 2 : (Section Three: Plan Development and Consultati on)

The plan addresses the State of Minnesota’s request for NDDAQ to analyze the feasibility of reducing electrical generating unit (EGU) emissions in North Dakota to less than 0.25 pounds per million Btu (lb/MMBtu) for sulfur dioxide (SO 2 ) and less than 0.22 lb/MMBtu for nitrogen oxides (NO X ). While NDDAQ listed reasons why it did not belie ve the State of Minnesota’s request was supported by assessments of impact, we request that ND supply the emission rates established by the regional haze plan from EGUs acr oss the State so we and the public can be informed of any differences between the request fro m Minnesota and the final requirements of the NDDAQ plan.

The U.S. Environmental Protection Agency (EPA) will need to review any discrepancy between the Minnesota regional haze plan and the North Dako ta regional haze plan during its review and approval process. In addition, we agree with NDDAQ that the EPA should address the significant contribution of international emissions , particularly from power generation in Canada, in support of NDDAQ’s efforts for reasonable progre ss.

Response : We believe the lb/10 6 Btu metric proposed by Minnesota is inappropriate since it is

not based on the four factors that must be consider ed for a reasonable progress analysis as required by rule and law. We believe cost must be considered, especially on a dollar per deciview of improvement basis.

Comment 3 : (Section Four: Monitoring Strategy and Other Im plementation Plan Requirements)

We note that the language in the footnote of Table 4.1 implies that the visibility monitoring conducted under the cooperative Inter-Agency Monito ring of Protected Visual Environments (IMPROVE) system at Theodore Roosevelt NP is coveri ng more than one Class I area. While the monitoring is at one unit, it is representative of all three units of that one Class I area.

We appreciate NDDAQ’s efforts to enhance monitoring of visibility with additional collection of data. We support the ongoing efforts to collect a nd periodically update state-wide inventories of pollutant emissions that may contribute to the visi bility impairment noted on page 24 of the Plan.3

Response : The footnote to Table 4.1 will be changed.

Comment 4 (Section Five: Baseline and Natural Conditions an d Uniform Rate of Progress for North Dakota Class I Areas)

As previously noted, we do not agree with the state ment on page 30 that North Dakota has four distinct Class I areas. We do agree that the IMPRO VE data collected at Theodore Roosevelt NP sufficiently tracks the long-term visibility condit ions across the entire park and can be used for implementing the requirements of the regional haze rule.

Response : See response to Comment 1.

Comment 5 : (Section Six: Sources of Visibility Impairment in North Dakota Class I Areas)

We appreciate the presentation of the Western Regio nal Air Partnership (WRAP) assessment of sources of visibility impairment at the two North D akota Class I areas. In particular, Table 6.6 is a useful summary of North Dakota’s contribution to impairment listed by component of light extinction. This forms a baseline to compare proje cted conditions in the reasonable progress section of the Plan. We ask that NDAQ clarify in t he narrative that the sulfate and nitrate results are based on regional modeling using the CAMx-PSAT source apportionment tool, while the analyses of weighted emissions potential for organi c carbon (OC), elemental carbon (EC), and particulate matter (PM) are based on emissions and residence time, not modeling. Figures 6.1, 6.2, 6.7, and 6.8 would be more informative if they also included 2018 results for sulfate and nitrate as is shown in the other figures for OC, EC , and PM.

Response : The Department will clarify that sulfates and ni trates are based on WRAP’s tracer analysis modeling results and the results for the o ther pollutants are based on WRAP’s weighted emissions potential analysis.

WRAP does not provide results for Case PRP18b using their tracer analysis (only Base 18b). We have included the weighted emission potential (W EP) analysis for SO 2 and NO

x that includes 2002 and PRP18b results. However, we disagree with the WRAP’s estimate of oil and gas NO

x emissions in 2018.

Comment 6 : (Purpose of the BART Program)

The core purpose of the BART program is to improve visibility in our Class I areas. BART is not necessarily the most cost-effective solution. Inste ad, BART represents a broad consideration of technical, economic, energy, and environmental (inc luding visibility improvement) factors. We

believe that it is essential to consider both the d egree of visibility improvement in a given Class I area as well as the cumulative effects of improving visibility across all of the Class I areas

affected.

Response : The determination of Best Available Retrofit Tec hnology (BART) is based on the assessment of five factors: 1) Cost of compliance, 2) the energy and nonair quality4

environmental impacts of compliance, 3) any existin g pollution control technology in use at the source, 4) the remaining useful life of the source and 5) the degree of improvement in visibility which may be reasonably be anticipated to result fr om the use of such technology (CAA, Sec. 169A(g)(2)). The Department has considered all fiv e factors in its BART determinations. EPA, in Step 5 of the BART Guideline states “...you are fr ee to determine the weight and significance to be assigned to each factor”. In determining BAR T, visibility improvement was generally not weighted as heavily as the cost of compliance becau se we believe the single source modeling required by the BART guideline does not give a true representation of the degree of improvement in visibility which may reasonably be anticipated to result from the use of the technology

.

We believe the cumulative visibility effects analys is promoted by DOI is scientifically unsound and not in accordance with rule or law. Adding the maximum improvement value (or 98 th
percentile) at one Class I area to the maximum impr ovement at another Class I area does not account for these maximums happening at different t imes. In addition, DOI has not defined which Class I areas should be added together to ach ieve the cumulative impact. This makes the analysis arbitrary. The single source modeling und er BART does not provide a realistic estimate of visibility improvement of a given technology. C reating a “cumulative effects” analysis based on the flawed BART analysis only compounds the inac curacy and misleads the reader of the SIP. In addition, the BART Guideline only requires an ev aluation of the change at each receptor. It does not require adding these changes together.

Comment 7 : (Five-Step BART Process)

Step 1: IDENTIFY AVAILABLE RETROFIT CONTROL TECHNOL OGIES Except for Great River Energy’s (GRE’s) analysis fo r NO

x from Coal Creek, all of the other SO 2 and NO

x analyses included a reasonable suite of options.

We also have some general comments that apply to al l of the PM 10 analyses. We believe that the BART analyses are deficient in that they neither ad dress upgrades to the existing Electrostatic Precipitators (ESPs) or propose limits that realist ically reflect the capabilities of those existing ESPs, as well as the proposed new baghouses, to con trol filterable PM. EPA’s BART Guidelines (Guidelines) advise:

• “...it is important to include control options that involve improvements to existing controls and not to limit the control options only to those measures t hat involve a complete replacement of control equipment.”

• “...for retrofitting existing sources in addressing BART, you should consider ways to improve the performance of existing control devises, particularly when a control device is not achieving the level of control that other similar sources are achieving in practice with the same device. For example, you should consider requiring those sources with el ectrostatic precipitators (ESPs) performing below currently achievable levels to improve their performance.”

Although all of these sources have ESPs in place, n one of them except Stanton Unit #1 is currently achieving a level of performance equivale nt to the 0.015 lb/mmBtu proposed for ESPs at sources such as Peabody’s Thoroughbred and LG&E’ s Trimble County projects in Kentucky. Furthermore, EPA has recently issued a permit limit ing the Desert Rock facility to 0.010

lb/mmBtu filterable PM 10 , new baghouses are being permitted at 0.009 – 0.01 2 lb/mmBtu in5

Virginia (Virginia Hybrid Energy Center) and Wyomin g (Dry Fork, WYGEN 3), and ND DOH proposed to permit the Gascoyne project at 0.012 lb /mmBtu. Instead, the limits on filterable

PM 10 proposed by NDDAQ are two – to – three times the e mission rates measured by stack testing and cited by NDDAQ. While we understand tha t a certain “safety margin” must be allowed, we believe that the BART limits should be set to encourage continued good operation and maintenance of the pollution control equipment.

Response : The comment regarding the suite of options evalu ated for NO

x controls at Coal Creek will be addressed later under the specific co mments on the Coal Creek BART

determination.

Regarding BART for PM at the BART eligible sources, in 2008 the emission rate at these sources ranged from 0.004 lb/10 6 Btu to 0.015 lb/10 6 which is generally comparable to levels achieved under BACT. The Department evaluated rece nt stack tests at the various power plants and found that emissions could vary up to 0.061 lb/ 10 6 Btu at Leland Olds Unit 1. The variation in the PM emission rate is probably due to a variat ion in the coal combusted (i.e. higher ash, different ash resistivity, etc.) and/or variations in the boiler and ESP operations. Sources must be able to comply with a BART limitation at all times unless specifically exempted. The Department chose to reduce the current allowable do wn from 0.10 lb/10 6 to 0.07 lb/10 6 Btu. This allows the sources to maintain continuous comp liance yet requires the source to assure the ESP is working properly. The Department also revie wed the effect of PM from the BART sources on visibility. Based on the maximum 24-hour emission rate for the baseline period (5 years) the maximum impact was 0.027 deciviews (98 th percentile). This amount of impact is considered very small and inconsequential. The new est ESP at the BART sources is 30 years old. The Department’s review found that it was not cost effective to replace them and any improvement would not provide appreciable visibilit y improvement. We have concluded that

0.07 lb/10 6 Btu is a reasonable emission limit after consideri ng the five statutory factors.

Comment 8 :

Step 3: EVALUATE EFFECTIVENESS OF REMAINING CONTROL TECHNOLOGIES The ability of SCR to reduce emissions, as assumed by NDDAQ, was inconsistent and

sometimes underestimated. For example, for the LNB/OFA+SCR option, GRE, Basin Electric Power Cooperative (BEPC), and NDDAQ sometimes assum ed 0.07 lb/mmBtu for all averaging periods. However, for example, the WY Department of Environmental Quality has issued permits for new EGUs requiring that they meet 0.05 lb/mmBtu over averaging periods of 24- hours and 30-days. Furthermore, EPA’s Clean Air Mar kets (CAM) data (Appendix A) and vendor guarantees show that SCR can typically meet 0.05 lb/mmBtu (or lower) on an annual average basis. GRE, BEPC, and NDDAQ have not provid ed any documentation or justification to support the higher values used in their analyses . Our review of operating data (Appendix A) suggests that a NO X limit of 0.06 lb/mmBtu is appropriate (with an ade quate “safety-margin”) for LNB/OFA+SCR for a 30-day rolling average, and 0 .07 lb/mmBtu for a 24-hour limit and for modeling purposes, but a lower rate (e.g., 0.05 lb/ mmBtu or lower) should be used for annual average and annual cost estimates. When the annual NO

x reductions are underestimated, the cost-effectiveness of the control option is negativ ely affected.6

Response : The 0.05 lb/10 6 Btu limit in Wyoming was for the Dry Fork Plant wh ich is a new plant and has not demonstrated that it can meet tha t limit.

DOI claims that SCR can achieve 90% removal efficie ncy. The Department believes this is true

for new units but not for retrofits. The EPA Air P ollution Control Cost Manual states “In practice, SCR systems operate at efficiency in the range of 70% to 90%.” EPA’s Air Pollution Control Technology Fact Sheet for SCR states “SCR i s capable of NO

x reduction efficiencies in the range of 70% to 90%.” In the ANPR for the Four Corners Power Plant (Federal Register 8/28/09) EPA states “APS estimated that SCR could a chieve NO

x control of approximately 90% or greater from the baseline emissions. For new fa cilities, 90% or greater reduction in NO

x from the SCR can be reasonably expected. See May 2009 W hite Paper on SCR from Institute of Clean Air Companies. For SCR retrofits on an exist ing coal-fired power plant, Arizona Department of Environmental Quality (ADEQ) determin ed that 75% control from SCR (following upstream reductions by LNB) was appropri ate for the Coronado Generating Station in Arizona. Based on this data, EPA has determined th at an 80% control efficiency for SCR alone, rather than the 90+% control assumed by APS, is app ropriate”. The Department believes 80% is

a reasonable estimate that allows the source to com ply with the expected emission limit on a

continuous basis.

Comment 9 : Step 4: EVALUATE IMPACTS AND DOCUMENT RESULTS The cost of SCR was consistently overestimated. EPA’s BART Guidelines recommend use of the OAQPS Control Cost Manual. Neither Minnkota Power Cooperative (Minnkota), GRE

, BEPC, nor NDDAQ provided justification or documentation for their c ost estimates. We were not provided with any vendor estimates or bids, and none used the recommended Control Cost Manual. This resulted in much-higher SCR costs than suggested by available literature (see Appendix B cost summaries) which shows SCR costs ranging fro m $50 - $267/kW. As recommended by the BART Guidelines, we applied the OAQPS Control Cost Manual to the EGUs and derived costs that fell within the Appendi x B cost-survey range. As a result, we believe that capital and annual costs are overestim ated by NDDAQ.

According to EPA’s BART Guidelines, “the basis for equipment cost estimates should be documented, either with data supplied by an equipme nt vendor (i.e., budget estimates or bids) or by a referenced source (such as the OAQPS Control C ost Manual

, Fifth Edition, February 1996, 453/B-96-001). In order to maintain and improve con sistency, cost estimates should be based on the OAQPS Control Cost Manual, where possible. The Control Cost Manual addresses most control technologies in sufficient detail for a BAR T analysis. The cost analysis should also take into account any site-specific design or other cond itions identified above that affect the cost of a particular BART technology option.”

EPA’s belief that the Control Cost Manual should be the primary source for developing cost analyses that are transparent and consistent across the nation and provide a common means for assessing costs is further supported by this Novemb er 7, 2007, statement from EPA Region 8 to NDDAQ:

The SO 2 and PM cost analyses were completed using the CUECost model. According to the BART Guidelines, in order to maintain and improve consisten cy, cost estimates should be based7 on the OAQPS Control Cost Manual. Therefore, these analys es should be revised to adhere to the Cost Manual methodology.

We are especially concerned about the lack of justi fication and support for the estimates of costs for reheating the exhaust gas streams to facilitate addition of “tail-end” SCR. Reheat costs are a critical issue affecting the economic feasibility o f SCR, and, even in those cases where some data were presented (by GRE), it was still not adequate for us to be able to understand the assumptions that formed the bases for the natural g as usage estimates. Furthermore, we are concerned that the costs of catalyst, ammonia, elec tricity, and natural gas were inflated beyond what we typically see, or what is projected by the Energy Information Administration (EIA) with respect to future natural gas prices. Finally, we a re concerned that this critical cost was simply scaled from a few examples and applied to other SCR analyses—we believe that it deserves individual analyses specific to each case.

Response : The DOI used the EPA Air Pollution Control Cost Manual (February 1996) to estimate the capital cost and operating costs for t he SCR system. The DOI did not use the most

current version of this manual which is dated Janua ry 2002. The EPA Air Pollution Control Cost Manual (both versions) is significantly out-of-date for estimating costs for SCR. This can be seen from the recently published results of EPA’s r eview of the Four Corners Power Plant BART analysis. In the Advanced Notice of Proposed Rulem aking (August 28, 2009), EPA published the Consultant’s, EPA’s and the National Park Servi ce’s estimate of the cost for NO

x controls.

The annualized cost of SCR was as follows:

Unit Consultant EPA NPS

1 $22,297,000 $16,599,600 $2,983,000 2 $23,634,000 $17,851,500 $3,052,010 3 $23,173,000 $16,962,000 $3,497,117 4 $55,755,000 $39,810,900 $9,838,997 5 $55,755,000 $39,810,900 $9,213,942

The NPS cost estimate is 4-6 times lower than EPA’s estimate.

For SCR alone the cost effectiveness was:

Consultant EPA Cost NPS Cost

Unit ($/ton) ($/ton) ($/ton)

1 4,343 3,758 1,558 2 5,484 4,803 1,469 3 4,582 3,646 1,684 4 4,872 4,341 1,185 5 4,872 4,330 1,357

It would appear the NPS is underestimating annualiz ed SCR costs by as much as a factor of 6 and cost effectiveness by as much as a factor of 3. The discrepancy between the annualized cost and the cost effectiveness is apparently due to the NPS overestimating the effectiveness of SCR.8

Based on this apparent underestimation, it appears the costs provided by the consultants and the Department’s estimates are similar to EPA estimates and are reasonable. Any estimate by the FLM of cost on a dollar per deciview basis would be similarly flawed.

As pointed out earlier, the OAQPS Control Cost Manu al is out-of-date. EPA accepted estimates

based on the CUE Cost Model for the Four Corners Po wer Plant BART analysis. Since the OAQPS Control Cost Manual is out-of-date and drasti cally underestimates control costs, we believe the CUE Cost Model provides a more realisti c estimate of the costs.

Comment 10 : (Step 5: Visibility Improvement)

A) DOI believes it is appropriate to consider both the degree of visibility improvement as

well as cumulative effects.

B) DOI is concerned that the Department did not pro vide the total improvement for each BART option.

Response : The total improvement under BART is not the best metric for addressing visibility associated with each option since the single source modeling under BART overpredicts (by a factor of 5-7) the actual improvement in North Dako ta. Incremental differences in improvement provides an easy way to evaluate the visibility imp rovement benefits of one option over another. The difference is equivalent to the total improveme nt of one option minus the total improvement of the other option. Providing the total improveme nt will mislead the reader of the SIP because of the overprediction. However, this information c an be extracted from the analyses conducted by the operators of the BART sources.

C) DOI is concerned about the difference in their m odeling for Leland Olds Unit 2 and the Department’s and Basin Electric’s modeling results (the latter two sets of results agree closely).

Response : There are bound to be differences in modeling re sults when different model settings and options are used as well as different receptor grids. One error noted in the DOI modeling results was the input for the maximum 24-hour SO 2 emission rate for Unit 2. DOI used 17,610 lb/hr plus 1,581 lb/hr for sulfate. Unit 2 had a m aximum 24-hour SO 2 (includes SO 4 ) of 12,205 lb/hr during the baseline period (2000-2004). DOI apparently used an SO 2 + SO 4 emission rate

based on maximum future sulfur content. This is in correct since current visibility conditions (12,205 lb/hr) are compared to conditions after con trols are applied. The BART Guideline states “Use the 24-hour average actual emission rate from the highest emitting day of the meteorological period modeled (for the pre-control scenario)”. The meteorological data used by the Department is from 2000-2004. Use of potential future uncontrolled emissions for the precontrol scenario is inconsistent with the BART guid eline. The Department also noted that this

error carried over into the emission rates for othe r pollutants. This error will provide a much greater improvement in visibility as found by the D OI.

Comment 11 : It appears to be more beneficial to reduce NO

x than to reduce SO 2 in this cool

climate.9

Response : The Department does not necessarily agree with t his statement. There are situations

in North Dakota where reduction in NO

x has very little impact on visibility. This can be seen from the AVS I analysis. A 65% reduction NO

x (2,356 tpy) only provided a 0.01 deciview improvement in the average of the 20% worst days.

Comment 12 : DOI recommends more emphasis on the dollar per d eciview metric.

Response : There was no established data base for this metr ic when the BART analyses were developed and when the Department was making its de cisions. Even the DOI’s data is not very useful since the EPA has not approved the BART dete rminations in that database. Again, the single source modeling does not reflect the true vi sibility improvement. It may be more realistic in some states than in others. Therefore, the comp arison of $/deciview in North Dakota to $/deciview in another State is not an apples-to-app les comparison. The Department has considered the incremental visibility improvement b etween BART options. We believe this is the best metric given the limitations of single sou rce modeling to provide realistic estimates of visibility improvement.

Comment 13 : For several units, NDDOH is proposing alternativ e sulfur dioxide (SO 2 ) limits that are similar to the presumptive BART limits bec ause they allow a source to choose between a limit in terms of pounds of emissions per million B tu of heat input, or percent reduction of that pollutant. While EPA presented its BART Guidelines for SO 2 in that format, we do not believe

that it was EPA’s intention to allow the source to choose the more favorable limit. By definition, BART represents the highest degree of control that meets the five-factor test. Where NDDOH has determined that a lb/mmBtu limit is reasonable, it should require that that limit be met. Similarly, where NDDOH has determined that a percen t reduction limit is reasonable, it should require that that limit be met. If both limits are determined to be reasonable, then to allow the source to choose only one clearly does not represen t the most stringent reasonable degree of control. Therefore, where NDDOH has proposed altern ative limits, both should be required.

There is also a fundamental problem with setting on ly a percent-reduction limit on SO 2 emissions. If fuel sulfur content increases, emissi ons can increase correspondingly. Unless sulfur content is limited, or a cap is placed on mass emis sions (e.g., lb/hr, tons/yr as proposed by Wyoming, for example), the actual amount of SO 2 emitted is unlimited.

Response : The DOI has requested that the sulfur dioxide li mitations be written as 95%

reduction and 0.15 lb/10 6 Btu instead of 95% reduction or 0.15 lb/10 6 Btu. Coal quality data suggests that the source may not be able to comply with the 0.15 lb/10 6 Btu limit when the

maximum sulfur coal is received. This would make t he requested standard impossible to meet for high sulfur coal. The BART guidelines (40 CFR 51, Appendix Y, Section IV.E.4) states “you must require 750 MW power plants to meet speci fied levels of SO 2 of either 95 percent

control or [emphasis added] 0.15 lb/10 6 Btu”. The guidance does not indicate both standar ds apply. In addition, the BART presumptive levels ar e not applicable to any source in North Dakota except for NO

x at Coal Creek Station.10

The DOI has also asked that a mass per unit of time limit be placed on the permit for SO 2. The Department believes this is unnecessary since the D epartment’s evaluation of visibility impacts was based on full load and worst case sulfur (i.e. highest 24-hour emissions). The Department asked the EPA if a mass per unit of time limit (24- hour basis to ensure the accuracy of the modeling) was necessary in the permit that establis hes the BART limits. In a November 21, 2005 response from Laurel Dygowski of Region 8, it was stated “we think that a 24-hour limit is unnecessary and may not be of much value”. Based o n EPA’s guidance and the Department’s determination that mass per unit of time units are not necessary, the Department will not include such limits in the permit that establishes the BART limits.

Comment 14 : DOI does not believe Heskett Unit 2 should be ex empt from the BART requirement.

Response : The Department is reevaluating the status of Hes kett Unit 2. This unit will be addressed in a supplement to this SIP revision.

Comment 15 : DOI believes the 70% reduction requirement at He skett Unit 2 is misleading.

Response : The 70% reduction is a requirement that was plac ed in the draft Permit to Construct. The calculations that were provided are accurate ba sed on the coal quality expected. The Department will clarify that the permit requirement (70% reduction) is not an actual reduction

from current emissions.

Coal Creek BART Determination

Comment 16 : Low NO

x burners and Over-Fire Air should have been conside red coupled with

SCR.

Response : The Department evaluated SCR at an emission rate of 0.043 lb/10 6 Btu (annual average) which is equivalent to 0.05 lb/10 6 Btu on a 30-day rolling average basis. This is th e same as the lowest emission rate in the RBLC. We b elieve a lower emission rate is not

achievable on a continuous basis. Because Coal Cre ek is already equipped with LNB and a form of overfire air, the modifications of these systems is not expected to reduce emissions below

0.043 lb/10 6 Btu.

Comment 17 : NDDAQ is proposing upgrading the existing wet sc rubber to limit SO 2 emissions

to 0.15 lb/mmBtu or 95% reduction on a 30-day rolling average basis. T he proposed scrubber upgrades will each result in an approximately one d v improvement in visibility at Theodore Roosevelt NP and 1.9 dv cumulatively when Lostwood WA is included. We commend NDDAQ for the proposed new wet scrubber, but recommend th at the limits require both 95% control and 0.15 lb/mmBtu, as well as specific caps on emission s.

Response : The Department’s BART determination is based on upgrading the existing wet scrubber to 95% efficiency, not the addition of a n ew wet scrubber. See response to Comment 13 regarding the BART limit.11

Comment 18 : NDDAQ is proposing LNB + SOFA at 0.17 lb/mmBtu o n a 30-day rolling average basis as BART for NO X . As a result, visibility would improve by 0.10 dv at Lostwood and 0.19 dv cumulatively.

Response : See response to Comment 6, Paragraph 2.

Comment 19 : NDDAQ has underestimated the effectiveness of SC R at only 80% control efficiency.

Response : See response to Comment 8.

Comment 20 : NDDAQ has overestimated the costs of SNCR and SC R. Many of the costs associated with SNCR and SCR presented by GRE and N DDAQ were not supported by GRE’s

documentation. Costs associated with lost ash sales and ash disposal were not adequately justified. More reliance should be placed upon use of the EPA Control Cost Manual when the source fails, as GRE did, to provide sufficient sup porting documentation of its costs. Our application of the EPA Control Cost Manual yielded much lower cost estimates for SNCR and

SCR.

Response : See response to Comment 9.

Concerning the inclusion of sunk costs of ash sales infrastructure, an assessment of the effect of removing sunk costs from the calculations has been performed and added to the BART

determination. If the sunk costs for the ash sales infrastructure are disregarded, then the annualized cost for SNCR would be $21,750,000; the cost effectiveness would be $8,122 per ton; and the incremental cost would be $19,692 per ton. This change improves the favorability of the SNCR alternative by only 5%, an insignifican t improvement that does not change the

choice for BART.

On the matter of the possibility of lost ash sales, DOI stated elsewhere in its comments: “If ash sales are not adversely affected, addition of SNCR becomes a reasonable BART selection.” However, neither DOI, EPA nor others have provided evidence to support the opinion that SNCR and its associated use of ammonia will not neg atively impact GRE’s ash sales; in fact, there is some evidence to the contrary. GRE emails dated 8/8/08 and 8/17/08 provide additional information on this issue, as does a summary of a U niversity of Kentucky study on the matter. After considering all the information available, ND DAQ reached the following conclusions.

• SCR and SNCR use at Coal Creek Station will likely result in ammonia in the fly ash.

• The level of ammonia in the fly ash cannot be predi cted with a reasonable certainty.

• The maximum level of ammonia in fly ash that would still avoid negative impacts on the salability of the ash cannot be predicted.

Therefore, NDDAQ cannot determine with reasonable c ertainty that SCR or SNCR will not

result in a level of ammonia in the ash that could reduce or eliminate future ash sales. Any regulator who determines that SCR or SNCR will not jeopardize ash sales would be obligated to present the evidence in support of that position. While another regulator might determine that12

even a small improvement in visibility is worth GRE taking the risk of lost ash sales, making a wrong decision will inflict a significant financial penalty on GRE and send ash to a landfill, or be treated as a hazardous waste (depending on current rule development), instead of it being used beneficially. Having considered all of the informa tion available, the NDDAQ BART determination on this matter remains unchanged.

Furthermore, in a BART and PSD analysis for the Oma ha Public Power District Nebraska City Station Unit #1 coal boiler (Construction Permit Nu mber CP07-0049, 2/26/09 fact sheet, pg. 17), Nebraska DEQ determined SCR was not BART in part be cause ... “ammonia used in the system would cause the ash to be contaminated, thereby jeo pardizing the current beneficial reuse of a portion of the ash produced by NCS Unit 1.”

Comment 21 : We conclude that SNCR is BART for control of NO X emissions from GRE Coal

Creek Units #1 and #2.

Response : See Comment 20 and response concerning lost ash sales.

Comment 22 : NDDAQ has not adequately considered the visibili ty benefits of the control strategies it evaluated.

Response : Tables showing the visibility impacts of the cos t effective control strategies will be added to the GRE Coal Creek BART analysis.

Comment 23 : NPS’ analysis of addition of SNCR indicates that visibility would improve by 0.17 dv at Lostwood and 0.32 dv cumulatively. This yields a cost-effectiveness of $17.2 million per dv at Lostwood WA and $9.2 million per dv cumul atively when Theodore Roosevelt NP is included, which we believe to be reasonable based u pon BART determinations and proposals we

have seen nationwide to date. NPS’ estimates for a ddition of SNCR show cost-effectiveness values below the $17 - $21 million per cumulative d v that NDDAQ accepted for adding SNCR at Stanton #1. Considering that the BART program is i ntended to improve visibility, it follows that any cost-effectiveness value below the costs per dv accepted by NDDAQ at Leland Olds #1 and Stanton should also be acceptable at Coal Creek.

Response : See response to Comment 6.

Stanton Unit 1 Bart Determination

Comment 24 : On page 15 of the comments, the DOI states that “Great River Energy (GRE) operates the 256 MW Stanton Station near Stanton, N D.”

Response : The nameplate capacity of the Stanton Station is 200 MWe, not 256 MW as stated by DOI. The National Park Service was informed by the Department in an October 21, 2009 email that the nameplate capacity of the Stanton Station is 200 MWe. It should be noted that the BART determination is being conducted for Stanton S tation Unit 1, not the entire Stanton Station (which consists of Stanton Station Unit 1 and Unit 10). Stanton Unit 1 can supply steam that will produce 140 – 170 MWe.13

Comment 25 : On page 16 of the comments, the DOI states, “We believe that higher control efficiency is warranted for both the lignite and PR B sub-bituminous scenarios”. The DOI goes on to state that a facility burning coal with an un controlled SO 2 emission rate of 2.4 lb/MM Btu for lignite and 1.6 lb/MMBtu on PRB “should be capa ble of at least 93% control and achieve an emission limit of 0.09 lb/MMBtu on a 30-day rolling average basis 11 ”. Footnote 11 in the DOI comments states, “Please see the entry in Appendix D for the permit issued by Wyoming to Black Hills Power for its WYGEN3 project”.

Response : The DOI states a SD/FF at Stanton #1 “should be capable of” at least 93% control and an emission limit of 0.09 lb/MMBtu on a 30-day rolling average basis. The DOI attempts to support this position by referencing the WYGEN3 fac ility permit. Although the WYGEN3 facility does have a 0.09 lb/MMBtu SO 2 emission limit, according to the EPA RACT/BACT/LAER clearinghouse, the 0.09 lb/MM Btu SO 2 emission limit is on a 12-month rolling average basis, not a 30-day rolling average basis. Also, the RACT/BACT/LAER clearinghouse does not list a required SO 2 removal efficiency. If the WYGEN3 facility burns low-sulfur coal, the facility could comply with the 0.09 lb/MMBtu emission limit with SO 2 control efficiencies below 90%. Furthermore, it is the Department’s understanding that the WYGEN3 facility has yet to operate and demonstrate that the SO 2 emission limit can be achieved. Based upon these facts, the WYGEN3 facil ity permit does not support the DOI position that a SD/FF at Stanton Station Unit 1 “sh ould be capable of” at least 93% control and an emission limit of 0.09 lb/MMBtu on a 30-day roll ing average basis.

The Department maintains the position that a SD/FF operating at Stanton Station Unit 1 is capable of achieving an SO 2 control efficiency of 90%.

Comment 26 : On page 16 of the DOI comments, the DOI states, “Because the larger Stanton Unit #10 also located at this site is achieving les s 0.06 lb/MMBtu on an annual basis (presumably burning PRB coal) using the same SD/FF technology proposed for Stanton Unit #1, NDDAQ should explain why a newer installation of th at technology at Stanton #1 cannot perform as well, at least on PRB coal”.

Response : The DOI incorrectly states that Stanton #10 is l arger than Stanton #1. In fact, Stanton #10 (with a heat input of approximately 642 MM Btu/hr) is approximately 2.8 times

smaller than Stanton #1 (with a heat input of approximatel y 1,800 MM Btu/hr).

The DOI states that Stanton #10 emitted SO 2 at an emission rate of 0.06 lb/MM Btu and asks the Department to explain why Stanton #1 cannot perform as well as Stanton #10 when burning PRB coal. Although the Stanton #10 facility has recent ly emitted SO 2 at an emission rate of 0.06 lb/MM Btu, based upon the average sulfur content of the coal burned the SO 2 removal efficiency at Stanton #10 is estimated to be approximately 90% . The dry scrubber technology proposed as BART for Stanton #1 is expected to achieve an SO 2 control efficiency of 90%, so Stanton #1 will

be expected to perform as well as Stanton #10.

Comment 27 : On page 16 of the DOI comments, the DOI states, “It is likely that increasing the SD/FF efficiency to achieve 0.09 lb/mmBtu would be even more cost effective on a $/ton basis.”14

Response : The DOI provides no basis for this comment. The Department maintains the position that 90% control is a reasonable control efficiency for a SD/FF system and that the Stanton

Station Unit 1 would not be able to meet an SO 2 emission limit of 0.09 lb/MM Btu when combusting higher sulfur coals.

Comment 28 : On page 17 of the DOI comments, the DOI states, “We recommend limits of 0.09 lb/mmBtu and 93% reduction on a 30-day rolling aver age for both fuels based upon recent determination by other states for EGUs burning coal s with similar uncontrolled emissions. Even if coal quality deteriorates to the anticipated wor st-case 2.4 lb/mmBtu, 96% control would still

meet the 0.09 lb/mmBtu limit. We also recommend sh ort and long-term absolute (e.g., lb/hr, tpy) caps on emissions to insure that emissions wil l not increase greatly over time”. The DOI reiterates this comment on page 20 of the DOI comme nts.

Response : DOI has requested that the sulfur dioxide limita tions be written as 93% reduction and

0.09 lb/MM Btu for both fuels instead of 90% reduct ion or 0.16 lb/MM Btu for PRB or 0.24 lb/MM Btu for lignite. Coal quality data suggests that the source would not be able to comply

with the 0.09 lb/MM Btu limit when the maximum sulf ur content coal is received and emissions are controlled at 90%. This would make the request ed standard impossible to meet for high sulfur coal with a 90% reduction requirement. The DOI suggests that the facility can simply control at efficiencies greater than 90% (i.e. 96%) ; however, the Department’s position is that a SD/FF operating at Stanton Station #1 is capable of 90% SO 2 control on an on-going basis, not greater than 90% control as suggested by DOI.

The BART guidelines (40 CFR 51, Appendix Y, Section IV.E.4) states, “you must require 750 MW power plants to meet specified levels of SO 2 of either 95 percent control or [emphasis added] 0.15 lb/10 6 Btu”. The guidance does not indicate both standar ds apply. In addition, the BART presumptive levels are not applicable to this source.

The DOI has also asked that a mass per unit of time limit be placed on the permit for SO 2 . The Department believes this is unnecessary since the D epartment’s evaluation of visibility impacts were based on full load. The Department asked the EPA if a mass per unit of time unit (24-hour basis to ensure the accuracy of the modeling) was n ecessary in the permit that established the BART limits. In a November 21, 2005 response from Laurel Dygowski of Region 8, it was stated, “We think that a 24-hour limit is unnecessa ry and may not be of much value”. Based on EPA’s guidance and the Department’s determination t hat mass per unit of time units are not necessary, the Department will not include such lim its in the permit that established the BART

limits.

Comment 29 : On page 17, the DOI states, “We believe that NDD AQ should have included SOFA with tail-end SCR with reheat in its analysis”

.

Response : The Department analyzed SCR with reheat in the B ART analysis. A 90% control efficiency for SCR with reheat was assumed. For re trofits, the Department believes that a 90% control efficiency for SCR with reheat is highly op timistic and that 80% control is reasonable. It15

should be noted that conducting the BART analysis u sing an 80% control efficiency would make the cost of SCR with reheat even more cost prohibit ive.

In the Department’s judgment, SOFA with SCR with re heat would not attain greater than 90%

NO

x control at Stanton #1. Since SOFA with SCR with r eheat would be more expensive than SCR with reheat (which has already been determined to be cost prohibitive assuming a 90% control efficiency), it can be concluded that an an alysis of SOFA with SCR with reheat would also be considered to be cost prohibitive.

Comment 30 : On pages 18 and 20 the DOI indicates that the ex pected costs for SCR with reheat included in the BART analysis for Stanton #1 are higher than the cost estimates prepared by the DOI. The DOI requests that the Department d ocument and justify the SCR with reheat

cost estimate.

Response : The DOI requests that the Department document an d justify the SCR with reheat cost estimate for Stanton #1. The Department considers the cost estimate of SCR with reheat submitted with the GRE BART analysis to be extensiv ely documented and the Department has

verified the cost estimates.

The DOI states that the expected costs for SCR with reheat included in the BART analysis for Stanton #1 are higher than the cost estimates prepa red by the DOI. See response to Comment 9.

Comment 31 : On page 21 of the comments, the DOI states, “We believe that SCR may represent BART, especially when the modeling issues identified in other reviews are resolved”.

Response : The Department has eliminated high-dust SCR as t echnically infeasible and low-dust

SCR with reheat has been eliminated based on cost. The DOI has questioned the Department’s cost estimates for SCR with reheat and the Departme nt has demonstrated that the costs as presented are reasonable (see response to Comment 9 ). Based upon a consideration of all of the factors, the Department maintains the position that SCR does not represent BART at Stanton

Station Unit 1.

Leland Olds Unit 1 BART Determination

Comment 32 : NDDAQ did not evaluate the impact of the new wet scrubber at Unit 1 versus the

baseline condition.

Response : The Department evaluated the difference in visib ility impact between the top two

SO 2 control technologies, a wet scrubber and spray dry er. As indicated by the BART Guideline, Step 5, a determination of the net visibility improvement is to be made. Our analysi s is

consistent with the BART Guideline. The most effic ient control option (wet scrubber) was selected as BART. The amount of visibility improve ment versus the baseline may be extracted from BEPC’s analysis. The Department did not prese nt this result since we believe it is incorrect

and misleads the reader.16

Comment 33 : DOI recommends that the SO 2 limit be written as 0.15 lb/10 6 Btu and 95%

reduction.

Response : See response to Comment 13.

Comment 34 : DOI believes SOFA + SCR can achieve 83% NO

x removal.

Response : As pointed out in the Advanced Notice of Propose d Rulemaking for the Four Corners Power Plant, the Arizona DEQ determined tha t 75% control was appropriate following

low NO

x burners at the Coronado Generating Station. Lelan d Olds 1 is equipped with low NO

x burners. We believe 75% reduction for the retrofit of a 43 year old plant is appropriate. Reducing the emission rate to 0.05 lb/10 6 Btu achieves 212 tons per year additional NO

x reduction. The cost effectiveness is then $8,888/t on to $12,784/ton. These costs are still

considered excessive and SCR + SOFA is not BART.

Comment 35 : NDDAQ did not evaluate the visibility benefits o f any of the technically feasible options except for the proposed basic SOFA + SCR.

Response : The cost analysis eliminated SCR, coal reburn + SCR, coal reburn + SOFA and SNCR + boosted SOFA on either a very high cost effe ctiveness basis or a very high incremental

cost basis. This left SOFA + SNCR as the most effi cient control option. This option was then modeled to determine the visibility effects.

Comment 36 : NDDAQ is proposing addition of a new wet scrubbe r to limit SO 2 emissions to

0.15 lb/mmBtu or 95% reduction on a 30-day rolling average basis. W e have estimated that the proposed new wet scrubber will result in an approxi mately 1.2 dv improvement in visibility at Theodore Roosevelt NP and 2.4 dv cumulatively when Lostwood WA is included. We commend NDDAQ for the proposed new wet scrubbers, but recom mend that the limits require both 95%

control and 0.15 lb/mmBtu, as well as specific caps on emissio ns.

Response : See response to Comment 13.

Comment 37 : Based upon NDDAQ’s analysis, addition of the pro posed basic SOFA+SNCR to LOS #1 yields a cost-effectiveness of $25.6 million per dv at Theodore Roosevelt NP and $13.2 million per dv cumulatively when Lostwood WA is inc luded. NDDAQ has not adequately considered the visibility benefits of the control s trategies it evaluated. NPS’ analysis of addition of basic SOFA+SCR with reheat yields a cost-effecti veness of $12.6 – $32.3 million per dv cumulatively. We would normally consider costs abov e $20 million/dv to be above the average that most states/source are proposing, but believe that these results warrant further analysis, as we will discuss in more detail with respect to LOS #2.

Response : SOFA + SCR has an estimated cost of $8,888 - $12 ,784/ton of NO

x removed. The incremental cost would be approximately $15,748/ton to $25,319/ton over the next most efficient option. It is clear that SOFA + SCR, or SCR alone, is not cost effective for this unit.17

Comment 38 : NDDAQ underestimated the effectiveness of adding SCR to LOS #1. Outlet emissions projected by NDDAQ for SCR at 0.07 lb/mmB tu represent only a 75% SCR control efficiency We believe that a combination of combust ion controls (e.g., SOFA) plus SCR can achieve 0.05 lb/mmBtu, and represents BART.

Response : See response to Comment 8. This is consistent w ith other BACT determinations, especially for retrofits.

Comment 39 : NDDAQ overestimated the costs associated with ad ding SCR to LOS #1.Our application of the EPA Control Cost Manual yielded much lower cost estimates for SCR. Many of the costs associated with SCR presented by BEPC and NDDAQ were much higher than we have seen presented at similar facilities and were not supported by BEPC’s documentation. More reliance should be placed upon use of the EPA Contr ol Cost Manual when the source fails, as BEPC did for LOS, to provide sufficient supporting documentation of its costs.

Response : See response to Comment 9.

Leland Olds Unit 2

Comment 40 : DOI suggests we investigate the differences in t heir modeling results and the Department’s and BEPC results.

Response : The Department has investigated the DOI modeling – See response to Comment 10(c). The DOI modeling is not consistent with the BART Guideline. The Department’s and BEPC modeling is consistent with the guideline.

Comment 41 : NDDAQ is proposing to limit SO 2 emissions to 0.15 lb/mmBtu or 95% reduction on a 30-day rolling average basis. We recommend 0. 15 lb/mmBtu and 95% reduction on a 30- day rolling average basis.

Response : See response to Comment 13.

Comment 42 : We re-modeled LOS #2 assuming that the new wet s crubber would reduce SO 2 emissions to 0.15 lb/mmBtu and held all other emiss ions to their baseline rates. Our results estimate that the scrubber would improve visibility by 5.6 dv at Theodore Roosevelt NP and 9.4 dv cumulatively when Lostwood WA is included.

Response : See response to Comment 10(c). The much higher future emission rate, which is not consistent with the BART Guideline which requires u se of the baseline emission rate, yielded the higher inaccurate result.

Comment 43 : We agree with NDDAQ’s estimates of control effec tiveness, but suggest that, if

ASOFSA can reduce emissions to 0.5 lb/MMBtu as esti mated by NDDAQ, then addition of SCR at 90% as assumed by NDDAQ could bring emissions do wn to 0.05 lb/mmBtu.18

Response : As pointed out in our response to Comment 8, 80% efficiency is a better number for retrofit of SCR. The Department did use 90% effici ency for SCR + ASOFA.

Comment 44 : NDDAQ overestimated the costs associated with ad ding SCR to LOS #2.Our application of the EPA Control Cost Manual yielded much lower cost estimates for SCR. Many of the costs associated with SCR presented by BEPC and NDDAQ were much higher than we have seen presented at similar facilities and were not supported by BEPC’s documentation. More reliance should be placed upon use of the EPA Contr ol Cost Manual when the source fails, as BEPC did for LOS #2, to provide sufficient supporti ng documentation of its costs.

Response : See response to Comment 9.

Comment 45 : We re-modeled LOS #2 and estimate that ASOFA + S CR would improve visibility by 2.3 dv at Theodore Roosevelt NP and 4 .1 dv cumulatively when Lostwood WA is included. Our higher control-effectiveness results show that we are estimating that removing a

ton of NO

x has greater benefits than estimated by BEPC/NDDAQ.

Response : The DOI modeling is inaccurate – see response to Condition 10(c). We believe the cumulative results are inappropriate – see response to Comment 6, Paragraph 2.

Comment 46 : NPS’ analysis of addition of ASOFA+SCR with rehe at and using NDDAQ modeling results yields a cost-effectiveness of $4. 0 – $9.6 million per dv at Theodore Roosevelt NP and $2.3 – $5.5 million per dv cumulatively when Lostwood WA is included. We believe

that our cost estimates indicate that addition of S CR with reheat is reasonable based upon BART determinations and proposals we have seen nationwid e to date.

Response : See response to Comments 10(c), Comment 6 and Co mment 9.

Comment 47 : The great disparity between modeling results pro duced by BEPC/NDDAQ and NPS requires resolution.

Response : See response to Comment 10(c).

M.R. Young Station Unit 1

Comment 48 : We have estimated that the proposed new wet scru bber will result in an approximately 1.8 dv improvement in visibility at T heodore Roosevelt NP and 3.2 dv cumulatively when Lostwood WA is included. We comme nd NDDAQ for the proposed new wet scrubbers, but recommend that the limits require both 95% control and 0.15 lb/mmBtu, as well as specific caps on emissions.

Response : See response to Comment 13.

Comment 49 : NDDAQ proposes that NO

x emissions be limited to 2,070.2 lb/hr on a 24-hour rolling average basis during startup. We recommend that NDDAQ limit the mass emission rate (e.g., lb/hr) to the rate under normal operation.19

Response : The proposed limit is under normal operating con ditions without the ASOFA and SNCR, since the SNCR cannot be operated until the p roper boiler temperature is reached. The actual startup emissions will be much higher (>1.0 lb/10 6 Btu). Therefore, limiting startup emissions based on normal operations with SNCR (< 0.35 lb/10 6 Btu) will provide no relief to the source during startup.

Comment 50 : NDDAQ underestimated the effectiveness of adding ASOFA + SCR to MRYS #1. We suggest that ASOFSA + SCR can achieve 0.05 lb/mmBtu.

Response : See response to Comment 8. The Department used 90% for ASOFA + SNCR.

Comment 51 : NDDAQ overestimated the costs associated with ad ding SCR. In the absence of supporting documentation by NDDAQ, we also estimate d a total annual cost for ASOFA + SCR with reheat at $9.7 million and $1,028 per ton.

Response : Minnkota has provided its own estimate of the co st of SCR as part of the BACT process under their Consent Decree. Minnkota’s est imate has been included in the BART

determination.

Comment 52 : We believe that ASOFA + SCR with reheat represen ts BART for MRYS #1.

Response : Based on the Department’s evaluation of the five statutory factors, we believe SCR + ASOFA is not BART. As explained in the Department’ s analysis, the cost effectiveness is excessive, the incremental cost over the next most efficient control option (ASOFA + SNCR) is excessive and there is very little visibility impro vement especially when the Department’s cumulative visibility modeling is considered (0.01 deciviews average in the 20% worst days). The cumulative modeling results represents the most realistic degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.

M.R. Young Station Unit 2

Comment 53 : NDDAQ is proposing upgrading the existing wet sc rubber to limit SO 2 emissions

to 0.15 lb/mmBtu or 95% reduction on a 30-day rolling average basis. W e have estimated that the proposed scrubber upgrade will result in an app roximately 1.2 dv improvement in visibility at Theodore Roosevelt NP and 2.2 dv cumulatively when Lostwood WA is included. We commend NDDAQ for the proposed new wet scrubbers, but recom mend that the limits require both 95%

control and 0.15 lb/mmBtu, as well as specific caps on emissio ns.

Response : See response to Comment 13.

Comment 54 : NDDAQ proposes that NO

x emissions be limited to 3,995.6 lb/hr on a 24-hour rolling average basis during startup. We recommend that NDDAQ limit the mass emission rate (e.g., lb/hr) to the rate under normal operation.

Response : See response to Comment 49.20

Comment 55 : NDDAQ underestimated the effectiveness of adding ASOFA + SCR to MRYS #2. We suggest that ASOFSA + SCR can achieve 0.05 lb/mmBtu.

Response : See response to Comment 8.

Comment 56 : NDDAQ overestimated the costs associated with ad ding SCR. In the absence of supporting documentation by NDDAQ, we estimated tot al annual costs for ASOFA+tail-end SCR with reheat at $15.6 million and $898 per ton.

Response : Minnkota has provided a much more detailed cost estimate of SCR with reheat as part of their BACT process under their Consent Decr ee. This estimate has been used in the Department’s BART determination.

Comment 57 : We believe that ASOFA + SCR with reheat represen ts BART for MRYS #2.

Response : Based on the Department’s analysis of BART for M RYS Unit 2, we believe the cost effectiveness of ASOFA + SCR is excessive, the incr emental cost over the next most efficient option (ASOFA + SNCR) is excessive and the visibili ty improvement is very small going from ASOFA + SNCR to ASOFA + SCR (see Department’s final analysis). Therefore, we believe

ASOFA + SCR is not BART.

Modeling

Comment 58 : NDDAQ indicates that the purpose of the hybrid m odeling is as weight of evidence to discount the impact of international (p articularly Canadian) emissions and to better represent plume dispersion from point sources, part icularly those closer to the Class I areas. While the CMAQ 36 km grid resolution does allow dil ution of the plumes from point sources, ND’s hybrid modeling assumptions raise more questio ns that are answered. CALPUFF does allow tracking of individual plumes but the model chemistry is much simplified compared to CMAQ and the methods required to normalize CMAQ res ults to CMAQ-CALPUFF hybrid results becomes quite elaborate and questionable.

Response : To address commenter’s concerns, Sections 8.5.6 (“Normalizing Hybrid Model RRF to WRAP CMAQ RRF”) and 8.6 (“The Impact of Internat ional Sources on North Dakota Class I Areas”) of the draft SIP have been combined and ext ensively rewritten in a new Section 8.5.6. The purpose of this revision is to clarify the usag e and purpose of the NDDoH hybrid modeling system. The emphasis of the rewrite is that the hy brid model was used only to adjust WRAP CMAQ results, and not as a “stand alone” system. W e believe the new language helps to clarify the intent and legitimacy of the NDDoH hybrid model ing approach. The NDDoH also notes that values used for background ammonia and other input settings for CALMET-CALPUFF (including “alternative protocol” settings of ongoi ng concern to EPA and FLMs) become less

critical as the effect of values used both in the n umerator and denominator to a significant extent “cancel out” in the adjustment ratio applied to WRA P CMAQ results. Certainly, these settings will have less impact than if the hybrid model was used in a “stand alone” sense.21

We raise the following technical issues with the CA LPUFF application:

A) Ammonia is known to be an important input to det ermine the amount of ammonium nitrate (NH 4 NO 3 ) formed in CALPUFF. Regional ambient concentratio ns of ammonia are poorly understood. ND has one ammonia monitor at Beulah; please describe the type of monitor and the land use at Beulah compared to o ther areas of the CALPUFF domain. We question if this monitor is representative of th e CALPUFF domain. We note that monthly average NH3 from 2001-2002 was used as back ground ammonia in CALPUFF after removing days influenced by a source region. The draft Plan should identify that source region.

Response : The ammonia monitor at Beulah is a Thermo Scient ific 17c continuous sampler, based on the chemiluminescence analytical process. Land use in the vicinity of the Beulah monitoring site is predominantly rangela nd and cropland, which is typical for

most of North Dakota. Land use in the State is rel atively homogenous, with cropland slightly more common than rangeland in eastern and northern parts of the State, and rangeland slightly more common than cropland in the southwest part of the State. As such, the Beulah ammonia monitor should be represen tative of the Calpuff domain. When processing Beulah monthly background ammonia v alues to use with CALPUFF, hourly observations associated with the northwest w ind-direction quadrant were filtered

from the 2001-2002 data set. This was done to avoi d bias due to the Great Plans Synfuels plant located about eight kilometers northwest of t he monitor site. This plant produces significant amounts of ammonia as a result of its p roduction process.

B) EPA disapproved the use of the Ammonia Limiting Method to define NH3 levels in the VISTAS application cited by NDDAQ.

Response : The NDDoH did not use the Ammonia Limiting Metho d (ALM) to define ammonia levels. Background ammonia for NDDoH hybri d modeling was based on actual ambient ammonia monitoring data. The NDDoH used the ALM simply to avoid double-counting of ammonia by multiple puffs in the modeling domain.

C) For POSTUTIL, hourly ammonia data for 2001 -2003 were used and the Plan does not mention removing data. The Plan should identify if different years were used for the two applications. It appears that the ammonia levels a t Lostwood were doubled compared to measured values based on the expectation that Lostw ood is closer to ammonia sources in Canada. However, that adds a subjective adjustment to the CALPUFF modeling that brings into question the presumption that CALPUFF m odeling is more accurate than just using CMAQ at 36 km.

Response : Based on consultation with Joe Scire (TRC Atmosp heric Studies Group), the NDDoH elected to use hourly background ammonia data (Beulah monitor) with POSTUTIL. Use of the hourly data (rather than mont hly) tended to improve hybrid model agreement with sulfate and nitrate observatio ns in the performance evaluation. As

was the case in the ammonia data set used with CALP UFF, hourly data associated with the northwest wind direction quadrant were removed from the data set used with22

POSTUTIL, because of bias due to a large ammonia so urce (Great Plains Synfuels Plant)

located northwest of the Beulah monitor site. Due to resultant missing data periods, the three year period 2001-2003 of hourly ammonia data was averaged to prepare a composite hourly data set for 2002. The NDDoH cons iders this a refinement of the monthly data used with CALPUFF, and notes that ammo nia background used with POSTUTIL completely supersedes the ammonia backgrou nd used in CALPUFF (this conclusion is the result of extensive testing).

Regarding adjustment of Beulah monitoring data for the Lostwood location, the assumption of higher ammonia background at Lostwood is consistent with predominant land use and other anecdotal evidence (see Section 8.5.4), and it provided better agreement with observations in hybrid model perform ance evaluations for sulfate and nitrate. We note again that NDDoH hybrid modeling is not as sensitive to the specific ammonia background applied because of the ratio app roach used to adjust WRAP CMAQ results (see response to Comment 58).

D) We note that four ozone monitors in central ND w ere selected to represent background ozone in CALPUFF. Are there only four ozone monito rs in the CALPUFF domain? Table 8.6 says background value for ozone was 30 pp b, but does not link this to monitoring data.

Response : The four ozone monitors used to represent backgr ound ozone in the hybrid model (CALPUFF) are located near the primary transp ort path between larger North Dakota point sources and Class I areas. Though the NDDoH operates additional ozone monitors in the State, ozone observations are relat ively homogeneous across North Dakota with little spatial variability. It is not likely that the inclusion of data from additional ozone monitors would have provided any m eaningful difference in results. The NDDoH used hourly ozone data from the four moni tors for year 2002 with CALPUFF. The 30 ppb background ozone number in Tab le 8.6 represents a typical annual average monitored value, and applied only in those rare cases when the hourly value was missing.

Comment 59 : We question the Hybrid model performance evaluat ion. Model performance evaluations are usually based on raw model output. We understand that the Hybrid model results

were normalized before evaluation and then were nor malized again to the WRAP baseline

results. The need to normalize the CALPUFF relati ve response factors to the WRAP results, brings into question the value of using the CALPUFF hybrid regional model to discern the benefits of NDDAQ strategies.

Response : The performance evaluation was based on raw mode l output from the hybrid system. Model output was not normalized or adjusted in any way prior to comparing with observations. Language has been added to Section 8.6 to clarify t his point.

Comment 60 : Section 8.6, including Figure 8.10, describes a possible way to account for international emissions when assessing the progress toward the goal of natural conditions. While we agree that examining the contribution to e xtinction for each aerosol species is a good23

approach to understanding if a State is meeting its fair share of emissions reductions associated with visibility impacts at a Class I area, the meth od described in this section and in the figure

raise concerns since there was no assessment of the international component of the natural

condition estimate. The value in 2064 illustrated in Figure 8.10 uses the same natural condition endpoint for the total extinction as well as the “U .S. Source” extinction, yet the 2064 natural condition estimates for aerosol species include som e global or international component. We believe that a better way to address reasonable pro gress by extinction component is to assess the reduction needed for each aerosol species measured in the baseline period to the end of the first planning period and then assess if a state’s plan a chieves a comparable reduction for its share of

extinction at the Class I areas.

Response : In its approach for discounting the impact of Ca nadian source visibility-affecting emissions, the NDDoH modified the emissions invento ries used in the adjustment of WRAP CMAQ modeling results (see revised Section 8.5.6). The modification involved elimination of all Canadian sources, except for the Canadian compo nent of natural background, which was retained through adjustment of boundary conditions in CALPUFF. Therefore, the modified

emissions inventories accounted for all non-Canadia n sources, including all components of natural background. Thus, there was no need to adj ust the end point for the “U.S. sources” glide path. For clarification, however, further descript ion regarding the context of “U.S. sources” has been added to Section 8.6, and labels for “U.S. sou rces” glide paths in Figures 8.10, 8.24, 8.26 and 8.27 have been changed to “Canadian Sources Dis counted Glide Path”.

Reasonable Progress Goals

Comment 61 : The State should rely on WRAP regional modeling as the primary tool for demonstrating progress toward visibility improvemen t goals. The CMAQ-CALPUFF hybrid modeling is problematic in several ways and gains N D little benefits compared to using WRAP products. Two WRAP products that were omitted but should be included to help ND in making its reasonable progress determination are 1) Weight ed Emissions Potential (WEP) and 2) extinction glide paths for SO 4 , NO 3 , and OC.

The uniform rate of progress glide path cannot be r evised to account for contributions from

natural sources or international sources under curr ent or 2018 conditions without also removing these contributions from the 2064 endpoint. While the contribution from natural and international sources by 2064 is unknown, it may be comparable to current contributions. Therefore removing the estimated contributions from current conditions without also accounting for those contributions to the 2064 endpoint inappr opriately changes the slope of the uniform rate of progress

It would be more appropriate to use the WRAP CAMx-P SAT results to demonstrate the relative

contributions to sulfate and nitrate from Canadian and ND emissions at the North Dakota Class I areas. The Plan has already included these results in Table 6.7.

We suggest NDDAQ use the WRAP extinction glide path s to show the improvement in SO 4 or NO 3 due to emissions reductions from all sources in th e WRAP 2018 inventory, and compare the ND emissions reductions by 2018 to emissions reduct ions from Canada and neighboring states.24

It would be informative for the Plan to include wha t percent of the State’s total SO 2 and NO X emissions from point sources is being reduced under BART. What other point source or area

source reductions are reasonable?

Response : The usage and purpose of the NDDoH hybrid modeli ng system was clarified in the response to Comment 58, and in the revision of Sect ion 8.5.6 of the SIP. The NDDoH does not agree that the NDDoH modeling provides little benef it compared to using WRAP products. Through use of the hybrid model to adjust WRAP CMAQ results, the NDDoH was able to produce a suite of analyses related to weight of ev idence, none of which were available in the original WRAP products. The NDDoH regards these we ight of evidence analyses more useful than the additional WRAP products suggested by the commenter.

Regarding the uniform rate of progress glide path 2 064 endpoint, see response to Comment 60.

The SIP already includes the WRAP Cam

x -PSAT results, demonstrating the relative

contributions to sulfate and nitrate from Canadian and ND emissions at North Dakota Class I areas, in Table 6.7 and 9.12.

A comparison of North Dakota emissions reductions b y 2018 with emission reductions from Canada and neighboring states has been added to Sec tion 9.

The Department has reviewed other point sources, ag ricultural tillage operations, smoke management techniques and oil and gas operations fo r possible air pollution control requirements. The Department determined that addit ional controls were not reasonable during this planning period. However, all sources of emis sions will be reevaluated during future planning periods.

Comment 62 : For stationary sources, NDDAQ developed a method ology to look at options for controls for sources, beyond the source subject to BART, contributing to the major components of aerosol extinction on the worst 20 percent days. While we generally agree with the use of emissions over distance (Q/d) as a screening tool, we note that the Heskett facility was not included in Table 9.4 even though NDDAQ proposes to exclude the source from BART requirements.

Response : The status of Heskett Unit 2 is being reevaluate d and will be addressed in a supplement to this SIP revision.

Comment 63 : Table 9.9 summarizes the results of assessing th e costs and visibility improvement associated with possible controls on th ese facilities. The two power generation facilities, Coyote and AVS, have emissions and Q/d impacts that are similar, if not greater than, BART sources that will be required to add controls. The methodology to calculate visibility improvements noted in Table 9.9 are not explained i n this section but appear to be some calculation of changes in the long-term metric of t he 20 percent worst visibility days. These sources likely contribute to higher impacts on a da ily basis, and a reduction in their emissions would be part of a broad strategy to reach natural conditions at the Class I areas. As such25

NDDAQ should examine the total improvement from the suite of sources as part of its reasonable progress assessment, not a simple unit b y unit approach.

Response : The improvement in the 20% worst days was used t o indicate the amount of visibility improvement. The SIP was revised to better explain this. Addressing individual days under reasonable progress is inconsistent with the reason able progress goals in 40 CFR 51.308(d)(1) which states “The reasonable progress goals must pr ovide for improvement in visibility for the most impaired days over the period of the implement ation plan and ensure no degradation in visibility for the least impaired days over the sam e period.” 40 CFR 51.301 defines the most impaired days as meaning “the average visibility im pairment (measured in deciviews) for the 20% of monitored days in a calendar year with the h ighest amount of visibility impairment.” 40 CFR 51.301 defines the least impaired days as the a verage visibility impairment (measured in deciviews) for the 20% of monitored days in a calen dar year with the lowest amount of visibility impairment.” It is clear that reasonable progress goals should be established based on the average of the “most impaired days” and the “least impaired day”, not individual days.

The Department did evaluate the cumulative effects of the most efficient remaining options. As stated on p. 182, the cumulative visibility improve ment was 0.11 deciviews at LWA and 0.03 deciviews at TRNP. The less efficient control opti ons would provide even less improvement.

Comment 64 : The assessment of non-air quality impacts on pag e 181 in the draft SIP does not

address the substantial human health benefits assoc iated with reductions in fine particulate concentrations resulting from additional control of SO 2 and NO X emissions from Coyote and AVS since they would become the newest and highest emitters of these pollutants after implementation the SIP as drafted.

Response : Reasonable progress is evaluated based on four s tationary factors 1) the cost of compliance, 2) the time necessary for compliance, 3 ) the energy and nonair quality environmental impacts of compliance, and 4) the rem aining useful life of the source.

The Energy and Non-Air Quality Environmental Impact s Analysis does not address health

effects from air emissions. As stated in the BART guideline “In the non-air quality related environmental impacts portion of the BART analysis, you address impacts other than air quality [emphasis added] due to emissions of the pollutant in question. Such environmental impacts include solid or hazardous waste generation and discharges of polluted water from a

control device.”

Even though health effects are not evaluated under this section of the BART analysis, the Department reviewed ambient monitoring data in the vicinity of Antelope Valley Station and Coyote Station. Five ambient monitors are operated in the immediate area. In 2008, the

maximum 3-hour SO 2 concentration was 39 ppb (7.8% of the NAAQS), the maximum 24-hour

SO 2 concentration was 9 ppb (6.4% of the NAAQS) and th e maximum annual average was 1.8 ppb (6% of the NAAQS). For NO 2 , the maximum annual average was 2.7 ppb (5.1% of t he NAAQS). Given the low concentration of these pollu tants, any benefits to health from additional controls and these facilities would be extremely ha rd to quantify.26

Comment 65 : The decision on additional point source controls would be better informed by analysis of the how the emissions from sources with in the State contribute to nitrate and sulfate concentrations in Class I areas, both inside and ou tside of the State, in the baseline period compared with the model projections in 2018. If BART controls on stationary sources as well as expected reductions from Federal mobile source, small engine, and fuel requirements would achieve a reduction that, had all other contributin g States and other regions met similarly, would put the total aerosol extinction on the uniform rat e of progress path, then the State could better support a limited approach to additional controls i n this first planning period. However, based on our review of the information supplied in the dr aft Plan and its appendices, we believe there are cost-effective controls for the Coyote and AVS facilities that should be implemented under the reasonable progress provisions.

Response : The Department reviewed these sources based on t he four statutory factors. We looked at the visibility improvement using an emiss ions inventory that included all contributing sources (cumulative analysis). This analysis showe d very little improvement if additional air pollution controls (SO 2 and NO

x controls) are installed. We believe an individual analysis for

SO 4 and nitrate will show the same result.

Although the Department found (using the four statu tory factors) that additional controls are not reasonable, Otter Tail Power Company has committed to reduce NO

x emissions at the Coyote Station by approximately 35%. This requirement wil l be included as part of this SIP revision. In addition, all sources will be reevaluated during th e next planning period.

Long-Term Strategy

Comment 66 : On Page 184, there is discussion of the reductio n in sulfur dioxide emissions

from the R.M. Heskett Station No. 2. As noted earl ier, we believe this facility is subject to BART and should be assessed under the BART provisio ns. In addition, the reduction in emissions reflect a 21 percent reduction from curre nt emissions. The 70 percent coal-to-stack removal cited in the draft Plan implies a greater r eduction from current emissions.

Response : The status of Heskett 2 is being reevaluated and will be addressed in a supplement to

this SIP revision.

Comment 67 : We request that NDDAQ include in the Long-Term S trategy a linkage between the prevention of significant deterioration program and its assessment of visibility impacts and the Regional Haze Plan in the SIP. This will ensu re that new sources are reviewed in a manner that does not jeopardize the reasonable progress go als established by this Plan.

Response : As part of the PSD program, the Department will evaluate the cumulative effect of all sources on the 20% worst and 20% cleanest days to ensure there is no degradation from

baseline conditions. This has been added to the Lo ng-Term Strategy as Paragraph 10.7.