UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION 8

Ref: 8P-AR Bryce Bird, Director Utah Division ofAir Quality P.O. Box 144820 Salt Lake City, Utah 84114

-4820

Dear Mr. Bird: 1595 Wynkoop Street DENVER, CO 80202-1129 Phone 800-227-8917 http ://www

.epa
.gov/region08 

## D E

C 2 2013

RE: EPA Region 8 Comments on Utah' s Draft PM2 5 State Implementation Plans and Technical Support Documents.

Thank you for the opportunity to provide comments on the state ofUtah ' s draft fine particulate matter (PM2 .5) State Implementation Plans (SIPs) for the Salt Lake City and Provo areas , the technical support documents (TSDs) , which were approved for public comment by the Utah Air Quality Board on September 11 , 2013 , and Section IX, Part H that was approved for public comment by the Board on October 2, 2013 with comments due December 2, 2013. Our comments , which are detailed in the five enclosures to this letter, should be considered preliminary

. Our preliminary assessment is that the draft PM2

.s SIPs need additional development and analysis as detailed in the enclosed comments so that the PM2

.s SIPs can be fully approved by the EPA. However, we will not reach any final conclusions until the state provides a formal submittal ofthe PM2

.s SIPs and after we conduct our own notice and comment rulemaking. We want to acknowledge the tremendous efforts ofthe Utah Department ofAir Quality (UDAQ) on ail ofthe hard work that has been undertaken on the draft PM2
.5 SIPs. We also want to provide any assistance needed and look forward to working with you to resolve the issues that we have identified.Ifyou have any questions , please contact me at 303-312-6416, or have your staffcontact Crystal Ostigaard, Particulate Matter Program Manager, at 303-312-6602.

Enclosures (5) Sincerely,

# ~~~q Carl Daly, Director Air Program

1) EPA Region 8 Comments for Utah PM2

.s SIP Section IX Salt Lake City Part A

.21 ; Provo Part A.22. 2) EPA Region 8 Comments on Utah PM2 

### .s SIP Sub Sections IX.H.11 , 12, and 13 , RACT Discussion in SIP Narratives and RACT Technical Support Documents. 3) EPA Region 8 Comments on Modeling Technical Support Documents for Utah SIP Control Measures for Area and Point Sources , Fine Particulate Matter, for the Salt Lake and Utah nonattainment areas . 4) EPA Region 8 Comments on Mobile Sources , Transportation Conformity, Related Contingency Measures, and liM

. 5) EPA Region 8 Comments on Emission Inventories and RACM Analysis for Area Source Rules

.ATTACHMENT 1 EPA Region 8 Comments for Utah PM2.5 SIP Section IX Salt Lake City Part A.21; Provo Part A.22. The following comments are the Region's general review ofthe SIP narratives and also comments based on Clean Air Act part D- Plan Requirements for Nonattainment Areas, subpart 1

- Nonattainment Areas in General, subpart 4

- Additional Provisions for Particulate Matter Nonattainment Areas, and State Implementation Plans; General Preamble for the Implementation ofTitle I ofthe Clean Air Act Amendments of 1990 (57 FR 13498; April 16, 1992). General Comments : a) The January 4, 2013 court ruling held that the EPA should have implemented the 2006 PM2
.5 24- hour standard based on both Clean Air Act (CAA) subpart 1 and subpart 4. Thus, the state should submit a subpart 1 and subpart 4 moderate area SIP. However, our review ofthe draft SIPs indicates that they do not address CAA subpart 4. Therefore, these aspects ofthe SIP are not approvable and will be discussed further (see CAA, part D, subpart 4 comments below)

. b) In the draft PM2.s SIPs, the state references the "EPA Clean Air Particulate Implementation Rule (FR 72 , 20586). " However, this rule has been remanded, and the March 2, 2012 guidance titled

" Implementation Guidance for the 2006 24-Hour Fine Particulate (PM25) National Ambient Air Quality Standards (NAAQS) " has been withdrawn

. These two documents no longer adequately define what the SIPs should contain. Additionally, 40 CFR 51.1000, Subpart Z- Provisions for Implementation ofPM2

.s National Ambient Air Quality Standards should not be used because the information in the CFR comes from the 2007 Clean Air Particulate Implementation Rule that was remanded. c) Under Chapter 8 ofthe draft PM2.s SIPs, we have concerns regarding the "Full Implementation Reduction" and " Benchmark Emission Reduction" equations

. From the 2012 draft SIP narratives and the new draft SIP narratives out for public comment, these equations have changed. d) Full Implementation Reduction equation for the draft 2012 SIPs was :
" equals: (attainment inventory)- (baseline inventory) " However, the Full Implementation Reduction equation for the draft 2013 SIPs is:

"equals : (baseline inventory)- (attainment inventory) " Benchmark Emission Reduction equation for the draft 2012 SIPs was:
"equals : (Full Imp. Reduction)

- (Milestone Date Fraction) However, the Benchmark Emission Reduction equation for the draft 2013 SIPs is:

"equals: (Full Imp. Reduction) 

## * (Milestone Date Fraction) Why were these equations changed? A discussion is needed on which equations are correct and how the changes affect reasonable further progress (RFP)

. e) Utah provided a table to EPA on October 31 , 2013 , where 15 ofthe 28 sources listed in the draft SIP subsections IX.H

. 12 and 13 , have modeled emissions based wholly or partly on projected actual emissions , or on 2008 actual emissions, rather than on allowable emissions. Ofthese 15 sources, only five had enough information were we able to determine that the proposed allowable emissions in the draft SIP subsections are substantially greater than the modeled emissions, in terms ofequivalent daily emissions. For the other ten ofthe 15 sources, we did not 3have enough information to determine the difference between the projected actuals and proposed allowables. Currently, the draft SIP appears to lack the necessary evidence that projected actual will not be exceeded by an amount that would interfere with attainment or maintenance. Further detail can be found in Attachment 2

. f) The RACT Summary Table, found on the state ' s website, lists emission reductions in tons per year (tpy) which are credited to various stationary sources. This is beyond the reductions achieved by existing emission controls. For some sources, the proposed RACT requirements do not include any requirement to achieve those additional emission reductions. For the additional reductions to be creditable, a requirement to achieve such reductions needs to be reflected in the SIP

. Further detail can be found in Attachment 2. g) In the draft SIP subsections IX.H.l2 and 13 , some sources do not have requirements to maintain existing emission controls as part ofRACT, only requirements to install new controls. The state needs to identify the existing local measures in the area that contribute to attainment ofthe NAAQS in the area, so the EPA can approve the measures specifically as RACT. Further detail can be found in Attachment 2. h) Some instances within the RACT Evaluation Report have identified a certain type ofemission control option as RACT, but the draft SIP subsections IX.H.12 and 13 propose no corresponding RACT requirement. Further detail can be found in Attachment 2

. i) Pre-baseline emission reduction credits were not included in the model nor was there definitive language in the draft SIPs stating that these credits would not be used. Further detail can be found in Attachment 3

. j) There are discrepancies between the Salt Lake nonattainment area' s SIP PM2.5 direct and nitrogen oxides (NOx ) motor vehicle emissions budgets (MVEB) as compared to data from Wasatch Front Regional Councils (WRFC) August 22, 2013 conformity determination. Further detail can be found in Attachment 4. k) Vehicle Miles Traveled data for the Salt Lake nonattainment area is not consistent. The VMT data from the TSD show predicted growth, as would be anticipated, 2010 to 2014 and to 2017 , for all five counties

. However, for 2019, all five counties ' VMT are then estimated to be below their 2017 levels. Inconsistent data for VMT would have impacts on the MOVES modeling performed by the UDAQ to develop mobile sources emissions estimates for inventory data tables , the dispersion modeling, and for defining the respective nonattainment area MVEBs

. Further detail can be found in Attachment 4. CAA part D, subpart 1 Comments CAA part D, subpart 1, 172(c) a) (1) In General. This section states " plan provisions shall provide for the implementation ofall reasonably available control measures as expeditiously as practicable (including such reductions in emissions from existing sources in the area as may be obtained through the adoption, at a minimum, ofreasonably available control technology). " However, many ofthe point sources will not implement controls until 2019. There is no analysis showing that it would be infeasible to implement the control measures earlier. See Attachment 2 for the EPA ' s more detailed review ofreasonably available control technology (RACT). We also note that, to support a 4demonstration that attainment by the moderate area attainment date is impracticable under CAA section 189(a)(l)(B) , the state must show that it has adopted " all available control measures that are technologically and economically feasible. " See 57 FR 13544. Additionally, CAA section 189(a)( 1 )(C) has an additional requirement for RACMIRACT implementation, see below

. b) (9) Contingency Measures

. The draft PM2. s SIPs contingency provisions do not satisfy applicable requirements. First, as noted in the General Preamble, the rule containing the contingency measure must clearly state that the measure will go into effect upon a determination by the EPA that the area has failed to make RFP or attain the NAAQS by the statutory deadline. See 57 FR 13543. R307-302-3 merely states, " Ifthe PM2

.s contingency plan ofthe State Implementation Plan has been implemented, the trigger level for no-bum periods as specified in R307-302-3(4) shall be 15 micrograms per cubic meter for the area where the PM2
.5 contingency plan has been implemented. " Neither the rule nor the SIP states that the contingency measures will be triggered by the EPA's determination that the area has failed to make RFP or attain the NAAQS by the deadline. Second, the General Preamble (57 FR 13543-13544) notes that the contingency measures " should be approximately equal to the emissions reductions necessary to demonstrate RFP for one year. " The state has not estimated the emission reductions that would be achieved by lowering the trigger level for no-bum periods to 15 micrograms per cubic meter or whether those reductions would equal the reductions necessary to demonstrate RFP for one year. CAA part D, subpart 4 Comments CAA part D, subpart 4, 188(b) In the draft PM2

.s SIPs, the state requests a five-year extension to December 14, 2019. This request could only be utilized under subpart 1. However, due to the January 4, 2013 court decision, implementation ofthe 2006 PM2

.s 24-hour standard must follow CAA subpart 1 and subpart 4 and not exclusively subpart 1. Under subpart 4, the moderate area SIP attainment date is December 31 , 2015. Ifthe area does not attain by this date, the area will be reclassified to serious and have a serious area attainment date ofDecember 31 , 2019. Thus, the state does not need to request a five-year extension but should begin to work toward developing a serious area SIP

. However, the state is still required to submit a moderate area SIP that satisfies applicable CAA requirements, including the requirements to adopt and implement reasonably available control measures/reasonably available control technology (RACM/RACT). Regarding this , we reiterate what we stated above: to support a demonstration that attainment by the moderate area attainment date is impracticable under CAA section 189(a)(l )(B), the state must show that it has adopted " all available control measures that are technologically and economically feasible ." See 57 FR 13544

. CAA part D, subpart 4, 189(a) a) In the draft PM2

.s SIPs , the state provides a demonstration of attainment by December 14, 2019. However, under 189(a)(l)(B), a moderate area SIP needs to demonstrate attainment by the moderate area attainment date or demonstrate that attainment is impracticable by that date

. The moderate area attainment date is December 31 , 2015

. Thus, the SIP should demonstrate the impracticability ofattaining by December 31 , 2015 , and the state should begin to develop a serious area SIP that has an attainment date ofDecember 31 , 2019. However, as noted above, the state is still required to submit a moderate area SIP by the applicable deadline (as discussed below, this is proposed to be December 31 , 2014) that satisfies applicable CAA requirements, including the requirements to adopt and implement RACM/RACT.

5b) In the draft PM2

.s SIPs, the state discusses RACM/RACT with implementation dates that range from 2014 to 2019. As stated above, 189(a)(l )(C), RACM/RACT for a moderate SIP shall be implemented no later than four years after designation, and under CAA section 172(c)(1 ), as expeditiously as practicable. However, in the draft SIPs some control measures won't be implemented until the end of20 19, the serious area attainment date. This would not appear to meet the requirements of CAA section 189(a)(l)(C). Also, we reiterate what we stated above: to support a demonstration that attainment by the moderate area attainment date is impracticable under CAA section 189(a)(1)(B), the state must show that it has adopted "all available control measures that are technologically and economically feasible." See 57 FR 13544. Did the state consider whether RACM/RACT could be implemented sooner? The SIP and/or the state's technical support document (TSD) must address this issue. For the serious area SIP development, all sources will need to be reviewed for best available control measure/best available control technology (BACM/BACT), which will have a later implementation date. CAA part D, subpart 4, 189(c) The draft PM2.s SIP narratives do not acknowledge that milestones must be submitted every three years until the areas are redesignated to attainment. The requirements are described in CAA section 189(c). CAA part D, subpart 4, 189(e) In the draft PM2

.s SIPs, the state indicates that volatile organic compounds (VOC) and ammonia are precursors that are presumed to be excluded unless it is demonstrated that they are a significant contributor to PM2.s concentrations. This presumption ofexclusion was only applicable under subpart 1. Under subpart 4, all control requirements applicable to major stationary sources ofPM2.s also apply to major stationary sources ofPM2
.5 precursors, "except where the Administrator determines that such sources [ofthe precursors] do not contribute significantly" to PM2.s levels "which exceed the standard in the area." Additionally, the General Preamble (57 FR 13498; 13541) states the following: "EPA intends to make a formal determination as to whether major stationary sources ofPM 10 precursors contribute significantly to PM 10 levels in a particular area when it takes rulemaking action on the individual moderate area SIPs." We intend to apply the same approach for PM2.s· The state included VOC as a precursor that needed to be reviewed for stationary sources in the SIPs but excluded ammonia from further review. For ammonia, the state discusses doing a sensitivity run with the model to show that ammonia has no effect on predicted PM2
.5 concentrations. The EPA will make a formal determination for PM2
.5 precursors, including ammonia, during the action approving or disapproving Utah's SIPs

. Ifthere is a stationary source ofammonia emissions that contributes a significant portion ofthe county or nonattainment area ammonia inventory, a model sensitivity study should be performed to evaluate the effect ofthat source on ammonium nitrate concentrations. For the EPA to adequately make this determination, documentation is needed showing that ammonia controls for stationary sources would have no effect on predicted PM2 5 concentrations. This might be done by showing 1) that the fraction ofammonia emissions in the inventory from stationary sources is small relative to total anthropogenic emissions and 2) that stationary source ammonia emissions are a negligible fraction oftotal domain ammonia. Any showing would need to discuss the relative sizes ofknown anthropogenic emissions and likely natural emissions in the area, as indicated by monitored levels and other evidence. State Implementation Plans; General Preamble for the Implementation of Title 1 of the Clean Air Act Amendments of 1990, (57 FR 13498, April16, 1992), Comments. 6a) Page 13539; (f) RFP/quantitative milestones. The General Preamble discusses that there is a gap in the law

- the text of section 189(c) does not articulate the starting point for counting the 3-year period for quantitative milestones. The General Preamble states that the EPA believes it is reasonable to begin counting the 3-year milestone deadline from the due date for applicable implementation plan revisions containing the control measures for the area. The EPA recently signed a proposed rule that, iffinalized, would set a new due date for CAA subpart 1/subpart 4 SIPs ofDecember 31, 2014. Utah should include in its SIPs a discussion ofmilestones based on the proposed due date. If December 31, 2014, is finalized as the SIP due date, Utah will need to provide a milestone report every three years after December 31, 2014 until the area is redesignated.

7

### ATTACHMENT 2 EPA Region 8 Comments on Utah PM6 .5 

### SIP Sub Sections IX.H.ll , 12, and 13, RACT Discussion in SIP Narratives and RACT Technical Support Documents I) Comments on Proposed SIP Subsection IX.H

. ll

- General Requirements These comments are based on EPA review ofthe following documents: Subsection H.ll (General Requirements) of a memorandum dated September 20, 2013 , DAQ083-13 , from Bill Reiss ofUtah DAQ to Utah Air Quality Board, posted on Utah DAQ website at: http ://www.airquality.utah.gov/Public-Interest /Public

-Commen-Hearings/Pubrule.htm. RACT Evaluation Reports and RACT Summary Table for major stationary point sources, posted on Utah DAQ website (section 5

.c ofTechnical Support Document) at: http ://www.airquality.utah

.gov

### I AirPollutants/ParticulateMatter /PM25/SaltLakeProvo/index .htm a) 

### IX.H.ll.d: This subsection says " All emission limitations listed in Subsections IX.H.1 2 and IX.H.13 apply during steady-state operation, unless otherwise specified in the source-specific conditions listed in IX.H

. 12 and 13 ." This is inconsistent with CAA requirements that SIP emission limits apply at all times, including periods of startup, shutdown, and malfunction (SSM). See CAA section 302(k) ; 76 FR 21641 (April18 , 2011 )

. EPA ' s interpretation on thi s point has been upheld in several cases, including one involving our SIP call concerning Utah' s unavoidable breakdown rule. See US Magnesium, LLC v. EPA, 690 F

.3d 1157, 1170 (lOth Cir. 2012). b) 

### IX.H.ll.e.i.C and D: These subsections each include the following statement: "The back halfcondensables shall also be tested using the method specified by the Director. " Everywhere else in these subsections ; the language reads , "EPA-approved testing methods acceptable to the Director. " The same language should be used here

. c) 

### IX.H.ll .e.i.G: This subsection does not list a specific method for VOC testing

. Are there no methods that can be specified up front for VOCs ? Please explain. d) 

### IX.H.ll.g: There are no requirements in this subsection for CEMS. The draft SIP subsections for the individual refineries in IX.H

. 12 rely on CEMS for determining some of the emissions and emission factors for sulfur dioxide (S02 ), NOxand H2 S

. CEMS are required for other sources as well. Requirements to operate and maintain CEMS should be included in IX.H

. ll.g., or in IX.H.12. , or both

. e) 

### IX.H.ll.g.i.A.I: We have several comments on this subsection: 1) This subsection specifies S02emission limits of 25 ppmdv and 50 ppmdv at FCCUs

. Please explain how it was determined that 25 ppmdv and 50 ppmdv represent RACT. We are not aware of any RACT Evaluation Report in the TSD that explains this.

82) This subsection specifies a 365-day rolling average basis and a 7-day rolling average basis for the emission limits. Please explain how averaging times longer than 24 hours can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 3) What value was modeled in the attainment demonstration for S02 emissions on a 24-hour basis from FCCUs ? Was it greater than 50 ppmdv, to account for greater variability than a 7-day average? 4) This subsection requires compliance "By no later than January 1, 2018. " Please explain why an earlier date would not be achievable. f) 

### IX.H.ll.g.i.A.III: This subsection says " S02 emissions during periods of Startup, Shutdown, or Malfunction shall not be used in determining compliance with the emission limit of 50 ppmvd @ 0% excess 02 on a 7-day rolling average basis, provided that during such periods the owner or operator implements good air pollution control practices to minimize S02 emissions

." As we have noted above, this is inconsistent with CAA requirements that SIP emission limits apply at all times , including periods of startup, shutdown, and malfunction (SSM)

. g) 

### IX.H.ll.g.i.B.I: This subsection requires compliance " By no later than January 1, 2018. " Please explain why an earlier date would not be achievable. h) 

### IX.H.ll.g.i.B.II: This subsection requires a stack test once every five years at FCCUs for PM emissions. Please explain why once every five years is considered sufficient frequency

. i) 

### IX.H.ll.g.i.B.III: This subsection says " PM emissions during periods of Startup, Shutdown, or Malfunction shall not be used in determining compliance with the emission limit.

.. " As we have noted above, this is inconsistent with CAA requirements that SIP emission limits apply at all times , including periods of startup, shutdown, and malfunction (SSM). j) 

### IX.H.ll.g.ii.A: We have several comments on this subsection : 1) This subsection requires compliance " By no later than January 1, 2018 ." Please explain why an earlier date would not be achievable

. 2) This subsection says "

... except during periods of startup, shutdown, or malfunction. " As we have noted above, this is inconsistent with CAA requirements that SIP emission limits apply at all times , including periods of startup , shutdown, and malfunction (SSM)

. 3) This subsection says " Compliance shall be based on a rolling average of365 days ." Please explain how averaging times longer than 24 hours can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 4) This subsection specifies a limit of 60 ppm for hydrogen sulfide (H2 S) in refinery plant gas . This sort oflimit is normally set in lieu of S02 emission limits at individual emitting units that burn plant fuel gas. Please explain how this limit was factored into the attainment modeling, i.e ., were plantwide allowable so2 emissions calculated using this limit? 9k) 

### IX.H.ll .g.iii.A: This subsection requires compliance "as soon as practicable but no later than January 1, 2018. " Please explain why an earlier date would not be achievable

. We do not view the phrase "as soon as practicable" to be practically enforceable; thus , it is not a meaningful addition to the date deadline and does not help meet CAA section 172(c)( 1) ' s requirement that RACM/RACT be implemented "as expeditiously as practicable, " or CAA section 189(a)(l)(C)'s requirement that "reasonably available control measures for the control of [PM2

.sJ shall be implemented no later than

... 4 years after designation

..." l) 

### IX.H.ll.g.iii.A.I: This subsection contains exemption language " in lieu of40 CFR 63

.654(b) ." Please explain where this exemption language comes from, what its significance is in terms ofVOC emissions, and why it should be considered reasonable for inclusion in the PM2

.s SIP. We could not find it in 40 CFR 63 , subpart CC (National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries). Please also explain why there is an exemption from requirements on heat exchangers when the process fluid contains less than 10% by weight VOCs

. What is the basis for 10% ? 10% VOCs in a fluid seems high

. m) 

### IX.H.ll.g.iv.A: This subsection requires compliance " as soon as practicable but no later than January 1, 2018 ." Please explain why an earlier date would not be achievable

. We do not view the phrase " as soon as practicable" to be practically enforceable; thus , it is not a meaningful addition to the date deadline and does not help meet CAA section 172(c)(l )'s requirement that RACM/RACT be implemented "as expeditiously as practicable, " or CAA section 189(a)(l)(C)'s requirement that "reasonably available control measures for the control of [PM2s] shall be implemented no later than

.. . 4 years after designation

. . ." n) 

### IX.H.ll.g.v: We question why the flare restrictions in this section and its subsections are limited to "hydrocarbon flares ." What is the intended scope ofthis term, and is it intended to address flaring of sulfur-containing gasses? Given that S02is a PM2
. 5 precursor, it would make sense to require compliance with NSPS Subpart Ja's S02 -related provisions. o) 

### IX.H.ll .g.v.A: This subsection requires compliance "Beginning January 1, 2018 ." Please explain why an earlier date would not be achievable. Also, please explain what is meant by "affecting a designated PM2
.5 non-attainment area..." Is this defined somewhere? If so , this provision should include a cross-reference to ensure clarity. If not, the provision should be defined. In addition, while we support the requirement for the refineries to comply with Subpart Ja, we note that Subpart Ja contains an exemption from the H2 S limit in 40 CFR 60.1 03a(h) for releases to the flare as a result ofreliefvalve leakage or other emergency malfunctions. As we have noted above, this is inconsistent with CAA requirements that the SIP emission limits apply at all times, including periods of startup, shutdown and malfunction (SSM). The SIP should note that this exemption does not apply under the SIP. p) 

### IX.H.ll.g.v.B: This subsection requires compliance "By no later than January 1, 2019. " Please explain why an earlier date would not be achievable. Also , this subsection says
" except during periods of startup, shut down, or malfunction." As we have noted above, thi s is inconsistent with CAA requirements that SIP emission limits apply at all times , including periods of startup, shutdown, and malfunction (SSM). 10q) 

### IX.H.ll.g.vi.A: This subsection requires compliance "Beginning January 1, 2017." Please explain why an earlier date would not be achievable. r) 

### IX.H.ll.g.vi.B: This subsection says "These degassing provisions shall not apply while connecting or disconnecting degassing equipment." Please explain the basis for this exemption, i.e., why should it be necessary to exhaust VOCs to the atmosphere while connecting or disconnecting degassing equipment? II) Comments on Proposed SIP Subsections IX.H.12 and IX.H.13

- Source-Specific Emission Limitations in Utah PM 2.5 Nonattainment Area These comments are based on EPA review ofthe following documents: Subsections H.12 and H.13 ofa memorandum dated September 20, 2013, DAQ-083-13, from Bill Reiss ofUtah DAQ to Utah Air Quality Board, posted on Utah DAQ website at: http: //www.airquality.utah. gov/Public-Interest/Pub!ic-Commen-Hearings/Pubrule.htm. RACT Evaluation Reports and RACT Summary Table for major stationary point sources, posted on Utah DAQ website (section S.c ofTechnical Support Document) at: http: //www.airquality.utah.gov

### I AirPollutants/ParticulateMatter/PM25/SaltLakeProvo/index.htm Point Source Reduction Summary table provided by Utah to EPA, via email dated October 31, 2013 , from Marty Gray ofUtah DAQ to Mike Owens ofEPA. This table lists the basis for

"Emissions Modeled" for each ofthe 28 stationary sources that are subject to source-specific RACT, versus the basis for "SIP Emission Limits." a) General Comments 1) Modeled emissions versus allowable emissions: According to the table provided to us on October 31,2013, for 15 ofthe 28 sources listed in draft SIP subsections IX.H.12 and 13, the modeled emissions are based wholly or partly on projected actual emissions, or on 2008 actual emissions, rather than on allowable emissions. For five ofthese 15 sources, we were able to determine that the proposed allowable emissions in the draft SIP subsections are substantially greater than the modeled emissions, in terms ofequivalent daily emissions. For the remaining ten ofthe 15 sources, we do not have enough information to determine whether or not the proposed allowables are substantially greater than projected actuals. Individual instances are cited in the source-specific comments below. The General Preamble 1 contemplates that source allowable emission limits may need to be reduced to the levels sources are actually emitting to support the modeled attainment demonstration. See 57 FR 13543. In a " SIP expectations" paper we provided to the state, via email from Carl Daly to Bryce Bird on July 5, 2012, we said, "The SIP submittal needs to provide evidence that projected actual emissions will not be exceeded by an amount that would interfere with attainment or maintenance ofthe PM2.5 NAAQS." We are seeking an
1 State Implementation Plans ; General Preamble for the Implementation ofTitle I ofthe Clean Air Act Amendments of 1990. 57 FR 13497 , April 16, 1992

. 11explanation why the state chose to use the projected actual emissions as the basis for the modeled emissions at these sources, rather than use the proposed allowable emissions. We are also requesting emissions information where we have been unable to determine whether or not the proposed allowables are substantially greater than projected actuals

. Currently, the draft SIP appears to lack the necessary evidence that projected actuals will not be exceeded by an amount that would interfere with attainment or maintenance. 2) Emission reductions being credited at some sources are not reflected in requirements to achieve those reductions. The RACT Summary Table on the state's website lists the emission reductions in tons per year which are being credited to various stationary sources, beyond the reductions achieved by existing emission controls. For some ofthose sources, the proposed RACT requirements in draft SIP subsections IX.H.l2 and 13 do not include any requirement to achieve those additional emission reductions

. Individual instances are cited in the sourcespecific comments below. For the additional reductions to be creditable in the attainment demonstration, a requirement to achieve such reductions needs to be reflected in the SIP

. 3) Requirements for existing controls are not included as part ofRACT at some sources. For some sources, requirements to maintain existing emission controls are not included as part of RACT in draft SIP subsections IX

.H.12 and 13 , butjust requirements to install new controls. Individual instances are cited in the source-specific comments below. For an approvable attainment demonstration, the state needs to identify the existing local measures in the area that · contribute to attainment ofthe NAAQS in that area, so that EPA can approve those measures specifically as RACT

. 4) Lack ofRACT requirements where a particular RACT control option has been identified. There are some instances where the RACT Evaluation Reports have identified a certain type ofemission control option as RACT, but where the draft SIP subsections IX.H.12 and 13 propose no corresponding RACT requirement. Individual instances are cited in the sourcespecific comments below. We are seeking explanations for these instances. 5) Condensable particulate matter: There are a few instances where the RACT Evaluation Reports and proposed RACT emission limits in draft SIP subsections IX.H.12 and 13 do not take into account condensable PM. Individual instances are cited in the source-specific comments below. We are seeking an explanation why this was not done

. Ifthere is a valid basis for not considering condensable PM in particular cases (for example, ifthe source does not emit condensable PM or emits a de minimus amount) , the TSD or the SIP should explain that basis. 6) Emission limit averaging times

. 'Some ofthe proposed source-specific RACT emission limits have averaging times longer than 24 hours. Individual instances are cited in the sourcespecific comments below

. We are seeking an explanation how averaging times longer than 24 hours can represent RACT in a plan that is intended to attain a 24-hour NAAQS

. 7) Time allowed to comply. In nearly all instances where new controls and/or emission reductions are required, sources are being given until 2017 or 2019 to comply. Little or no explanation could be found for why that amount oftime is necessary . Individual instances are cited in the source-specific comments below

. We are seeking an explanation why an earlier date would not be achievable. As noted in our general comments in Attachment 1, under 12CAA section 189(a)(l )(C), RACT for a moderate SIP must be implemented no later than four years after designation, and under CAA section 172(c)(l), as expeditiously as practicable. The draft SIP's extended deadlines to meet RACT appear to be inconsistent with the CAA's requirements. As also noted in our general comments in Attachment 1, to support a demonstration that attainment by the moderate area attainment date is impracticable under CAA section 189(a)(l)(B), the state must show that it has adopted "all available control measures that are technologically and economically feasible" by the moderate area attainment date. See 57 FR 13544. 8) Stack test frequency. There are a number ofinstances where stack testing is required only once every 3 to 5 years. Examples are: Central Valley Water Reclamation, Chemical Lime, Great Salt Lake Minerals, Kennecott Power Plant, Kennecott Refinery, Nucor Steel, Proctor & Gamble, University ofUtah, BYU, Geneva Nitrogen, and Provo City Power. We are concerned with stack test frequencies longer than one year. Please explain why these test frequencies are sufficient to ensure continuous compliance with the limits. 9) Excess emission reporting. There are no proposed requirements for any sources to report excess emissions. Please explain how this will be addressed. 1

0) Refineries (general): i) For all four petroleum refineries, draft SIP subsection IX.H.12 proposes sourcewide emission limits for PM2.s, S02 and NOx in tons per day (tpd) and tons per rolling 12- month period. No other types oflimits are proposed. The RACT Evaluation Reports for the refineries do not give any indication what emission limits in tons per day might represent RACT. Please explain how the proposed emission limits in tons per day were calculated and determined to represent RACT. Please also explain how rolling 12-month averages can represent RACT in a plan that is intended to attain a 24-hour NAAQS. ii) According to the RACT Summary Table, the Cooling Tower, Flares, Fugitives and Tanks VOC control methods at the refineries are not required for implementation until 2019. The VOC emissions involved are estimated as significant, at least 1,300 tpy, according to the Table. Please explain why an earlier date would not be achievable. iii) Sulfur Recovery Units (SRUs) are identified as RACT in the RACT Evaluation Reports for the refineries, but no level ofcontrol efficiency is identified as RACT. Draft SIP subsections IX.H.11 and IX.H.12 do not specify any level ofcontrol efficiency that the SRUs must achieve. We consider it essential to specify a level ofcontrol efficiency as RACT and would expect 95% or better control. Please supplement the TSD with a discussion ofwhat level ofcontrol should be expected for the SRU at each refinery and include that level ofcontrol in draft SIP subsection IX.H.11 or IX.H.12. We also note that only one ofthe four refineries (Chevron) is required to measure S02 emissions from the SRU, via CEMS. The draft SIP should require all four refineries to do this. See related comment above on IX.H.l1.g. b) ATK Launch Systems

131) Draft SIP subsection IX.H.12.a indicates that the proposed RACT provisions for ATK consist solely of limits on the pounds ofreactive waste, reactive compounds, and rocket motor propellants that may be open burned or tested " when the PM2 .s levels exceed 35 ug/m3 at the nearest real-time monitoring station," during winter months (November through February). In our November 1, 2012 comments on an earlier draft ofthe PM2 .s SIP, we stated that these proposed provisions are inconsistent with the CAA and EPA ' s regulations on dispersion techniques and intermittent control systems (40 CFR 51.118 and 51.119) and are not creditable for purposes ofdemonstrating attainment or meeting RACT requirements. They are not a substitute for continuous emissions limits/controls. Also , in ef fect, these provisions treat the area around ATK as an independent nonattainment area. Regarding the proposal to apply the requirements on a seasonal basis, EPA is evaluating whether this is an acceptable approach to address PM2

.s under the CAA. No emission controls , or efforts to minimize the above-mentioned open burning or testing, or to investigate alternatives to open burning or testing, such as waste minimization, other means ofdisposal, or transporting the materials somewhere outside the nonattainment area before burning or testing, are proposed. The proposed provisions do not appear to be based on a RACT analysis, nor is it clear whether these provisions represent a reduction f rom 2008 baseline emissions. It is also not clear what pollutant(s) these provisions are intended to address. It is also not clear why certain provisions only apply to rocket motors less than 1,000,000 lbs. ofpropellant per motor and larger motors are not addressed. 2) None ofthe provisions identified as RACT controls in the RACT Evaluation Report are reflected as proposed RACT in draft SIP subsection IX.H.12

.a. Page 4 ofthe Report identifies RACT for NOx as replacement ofthe burners at the two largest boilers (each rated at 71.1 MMBtulhr) with LNB 

### + FGR. Page 5 identifies RACT for VOC as the current practice ofusing oflow VOC and/or low vapor pressure solvents, the storing ofVOC emitting material in closed containers, and practices to prevent spills. Page 8 identifies RACT for PM2.s, S02, NOx and VOC as increased waste minimization efforts to reduce open burning, and notes that ATK has a waste minimization program in place. Please explain why none ofthese selected RACT controls in the RACT Evaluation Report are reflected as proposed RACT in draft SIP subsection IX.H.12.a. 3) The RACT Summary Table projects a 9.24 tpy reduction in NOxemissions resulting from installation ofLNB 

### + FGR at the two 71 MMBtu/hr boilers

. IfATK is being credited with a NOxreduction due to installation ofnew controls as RACT, then this needs to be reflected as proposed RACT in draft SIP subsection IX.H.12.a. The draft SIP subsection does not currently propose any controls for these boilers

. 4) The RACT Summary Table indicates that LNB and FGR will be installed at the 71 MMBtu/hr boilers for NOxcontrol by 2017. Please explain why an earlier date would not be achievable. 5) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31 , 2013 does not include ATK, therefore we have no information on what emissions basis was used for modeling (e.g. , projected actuals, proposed allowables , 90% of

14PTE, or possibly something else) and how that compares to the emissions that are proposed to be allowed. c) Big West Oil Refinery (a.k.a. Flying J) 1) The RACT Summary Table indicates that ultra low NOxburners (ULNB) will be installed by 2017 , and that a flue gas filter for PM control, deSOxcatalyst for S02 control, and a redundant scrubber for S02control will all be installed by 2019. Please explain why an earlier date would not be achievable. 2) There are a number of instances where new controls are identified as RACT in the RACT Evaluation Report, and are credited with emission reductions in the RACT Summary Table, but are not required in draft SIP subsection IX.H.12

.b: i) Page 5 ofthe RACT Evaluation Report identifies RACT for S02at the FCCU as use of deSOxcatalyst. The Report says an S02reduction of 125 tpy is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2019. ii) Page 8 ofthe RACT Evaluation Report identifies RACT for NOxat Process Heaters and Boilers as retrofitting the three boilers and replacing the unifier charge heater with ULNB capable ofachieving a NOxemission rate of0

.035 lb/MMBtu. The Report says a NOx reduction of 30 tpy is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2017. iii) Page 9 ofthe RACT Evaluation Report identifies RACT for S02at the SRU as installation ofa redundant S02caustic scrubbing system, to be operated in the event of SRU malfunction or planned outage
. The Report says an S02 reduction of 50 tpy is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2019. Draft SIP subsection IX.H.l2.b specifies the calculations to be used for demonstrating compliance with sourcewide S02 and NOxemission limits, but it is not apparent whether any ofthese calculations take into account any requirement to install and use new emission controls. Please explain. IfBig West Oil is being credited with emission reduction due to installation ofnew controls as RACT, then this needs to be reflected as proposed RACT in the SIP. 3) Page 12 ofthe RACT Evaluation Report proposes no changes to existing wastewater operations as VOC RACT for wastewater separators and drains. One option is presented as technically feasible (ensuring all drains are covered and routing the API separator vent gas to a control device for thermal combustion or oxidation), with potential 70% VOC control, but was not selected as RACT. One other area refinery (Chevron) , however, operates a regenerative thermal oxidizer system in conjunction with covers and vent routing. Page 12 of the RACT Evaluation Report for Big West Oil estimates VOC emission reductions as high as 38 tpy if a similar system were employed at Big West, but does not propose such a system, instead stating only that "further discussions on controlling wastewater VOC emissions need to be held. " Since it is proven to be technically and economically feasible at another area refinery, why is it not proposed here? Please explain. 154) Under " Source-wide PM2

.s, " draft SIP subsection IX.H.12.b.i. reads , " Following installation ofthe Flue Gas Blow Back Filter (FGF) ," but does not specify a deadline for installation of the FGF. This is not approvable because the limits key offofinstallation ofthe FGF. 5) Same paragraph, the SIP language proposes to defer the establishment of a condensable ratio for the Catalyst Regeneration System until "no later than January 1, 2019. " At that time a new source-wide limit will be established in an AO

. This is not approvable

. There is no explanation why it would not be possible to establish the condensable ratio now, through testing, use ofemission factors , or estimates. The SIP is supposed to evaluate RACT for condensable and filterable PM. The SIP cannot defer the establishment of limits. And the SIP must contain the RACT limits , not an AO. 6) In the next paragraph, the language reads , " Filterable PM2

.s emissions shall be determined by applying various emission factors

..." This language is imprecise/vague. Please delete the word "various. "

. 7) In the same paragraph, the language reads , "Unless otherwise specified by an Approval Order

... " This is not approvable language. EPA needs to be able to approve any revisions to the methods for determining compliance, unless the SIP establishes enforceable, replicable procedures for modifying the methods. For example, where a revision to an emission f actor is established through a simple stack test, we have been willing to approve SIP language that describes the process . The process should include notice to us ofthe stack test date, results , and new emission factor. 8) In the next paragraph, the language reads, "Daily gas consumption by all boilers and furnaces shall be measured by meters that can delineate the flow ofgas to the indicated emission points. " The phrase " indicated emission points" is undefined. The SIP language needs to specif y the emission points that are covered. 9) Source-wide NOx provisions : Same issues regarding use ofphrase "various emission factors ," AO overriding the SIP for establishment ofemission factors , AO as the future location f or emission factors should "future information reveal that there is a difference in the emission factors for natural gas and plant gas," and use ofthe phrase " indicated emission points. " 1

0) Source-wide S02provisions: Same issue regarding use ofthe phrase "various emission factors ." Also, the phrase " by whatever meters are necessary" is imprecise/vague. Also , there is no requirement for S02 CEMS or any other technique for accounting for SRU emissions. It is our understanding that the SRU at each refinery has an S02 CEMS , which we would expect to be used to account for a portion of source-wide S02emissions

. See, for example, SIP subsection IX.H.12.g.iii for Chevron, which requires use of S02CEM in determining S02emissions from the SRU. Please explain why this is not accounted for at Big West. 11 ) The RACT Evaluation Report does not identify any level ofcontrol efficiency as RACT for S02emissions from the SRU at Big West Oil , nor does this appear in draft SIP subsections IX

.H.11. or IX

.H.12.b. We consider it essential to specify a level ofcontrol efficiency as RACT and would expect 95 % or better control. Please supplement the TSD with a discussion 16ofwhat level ofcontrol should be expected for the SRU at Big West Oil and include that level ofcontrol in draft SIP subsection IX.H.ll or IX.H.l2.b. 12) Draft SIP subsection IX.H.12.b relies on NOxand H2S CEMS to determine some ofthe emissions and emission factors, but this subsection ofthe draft SIP doesn't clearly require the operation ofCEMS. This does not appear to be addressed by the General Requirements for Petroleum Refineries at draft SIP subsection IX.H.l1.g. Please see our related comment on IX

.H.11

.g. 13) There are no proposed requirements to report excess emissions

. Please explain how this will be addressed.

d) Bountiful City Light & Power 1) Comments on Gas Turbine # 1 : i) The table provided to us on October 31 , 2013 indicates that NAAQS attainment modeling was based on projected actual emissions for existing turbine GT #1 and for the existing internal combustion engine #8. Page 2 ofthe RACT Evaluation Report indicates that 2008 actual emissions for GT # 1 were less than 1 ton/year for each pollutant ofinterest (PM2. s, NOx, S02and VOC)

. We expect that the projected actual emissions would be only slightly higher. However, draft SIP subsection IX

.H.l2.c indicates that the proposed RACT allowable for GT #1 is 0.6 grams NOxper kilowatt-hour

. Since GT #1 is rated at 5.3 MW, the proposed RACT allowable is equivalent to allowable NOxemissions of7 lblhr, or 30.7 tons/year. The RACT Evaluation Report indicates that the PTE for this turbine is 13.3 tons/year for NOx . Please explain how the proposed RACT allowable could equate to a tons/year figure that is substantially more than the PTE

. Also , please explain how the projected actual emissions could be a valid basis for modeling when the proposed allowable emissions are at least 30 times higher (30.7 tons/year allowed versus less than 1 ton/year actual). 2) Comments on Gas Turbines #2 and #3: i) The table provided to us on October 31 , 2013 indicates that modeling was based on 90% ofPTE for the two new turbines. Page 2 ofthe RACT Evaluation Report indicates that the PTE for NOxfor each new turbine is 39.65 tons/year. The proposed RACT allowable in draft SIP subsection IX.H.l2.c

. is 15 ppm for NOxat each turbine. Please explain what the equivalent allowable would be in terms oftons/year and how that compares to the PTE figure of39.65 tons/year. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. 3) Comments on Dual Fuel IC Engine #8: i) Draft SIP subsection IX.H.12.c does not include any proposed emission limits or operational restrictions as RACT for IC Engine #8. Page 11 ofthe RACT Evaluation 17Report identifies Good Combustion Practices as RACT for NOx at this engine. The current title V permit specifies a NOxemission limit for this engine in grams per horsepower-hour, and requires testing for compliance after every 800 operating hours, or at least once every 24 months. Please explain why this emission limit was not included in subsection IX.H.12

.c . as proposed NOx RACT for this engine

. e) Constellation Energy Resources (CER Generation II, LLC), West Valley Power Plant I ) The table provided to us on October 31 , 2013 indicates that modeling was based on projected actual emissions. However, page 1 ofthe RACT Evaluation Report indicates that " Rather than using the actual emissions from 2008 , potential to emit values (permitted emissions) are used for establishment ofa baseline for RACT evaluation. " This leaves it somewhat unclear whether PTE might have been used for modeling, rather than projected actual emissions. Please explain

. Our objective here is to see ifthere is a substantial difference between the proposed RACT allowable and the emissions used for modeling

. 2) Page 4 ofthe RACT Evaluation Report identifies RACT for VOC as retention ofthe existing oxidation catalyst systems, and indicates that those systems can probably be expected to keep VOC emissions down to about 10 ppm. However, draft SIP subsection IX.H.12

.d does not include any proposed emission limit or required controls for VOC. Please explain why this is not included. 3) Draft SIP subsection IX.H

. 12.d. proposes RACT allowables for the turbines on a 30-day rolling average . Please explain how 30-day rolling averages can represent RACT in a plan that is intended to attain a 24-hour NAAQS

. 4) Draft SIP subsection IX.H.12.d relies on CEMS to determine emissions but doesn 't clearly require the operation of CEMS

. This does not appear to be addressed by the General Requirements at draft SIP subsection IX.H.11

. Requirements to operate and maintain CEMS should be included in IX.H.11 or in IX.H.12

.d

. 5) There are no proposed requirements to report excess emissions. Please explain how this will be addressed. f) Central Valley Water Reclamation I) For NOxcontrol, page 4 ofthe RACT Evaluation Report recommends that RACT be no addon controls. However, page 3 ofthe Report indicates that Good Combustion Practices (GCP) is a technically feasible RACT option and offers no reason why GCP should be ruled out as RACT. Please explain whether the proposed performance-based RACT limits for NOx in draft SIP subsection IX.H.12

.e. (which are 1.75 grams per horsepower-hour at the 1150 kW engine generators and 1.8 grams per horsepower-hour at the 1340 kW engine generators) are intended to represent GCP

. If GCP is intended to be reflected in terms of some other type of requirement, then please explain why this was not included in IX

.H.12.e. 2) For VOC control, page 4 ofthe RACT Evaluation Report indicates that installation of oxidation catalyst for VOC control at the five IC engines is not economically feasible , but

18offers no cost information to support this conclusion

. This is not sufficient to satisfy RACT requirements. Please explain what information was used to arrive at this conclusion. 3) The table provided to us on October 31, 2013 indicates that the emissions used for NAAQS attainment modeling were "2008 Actual. " Pages 2 and 5 ofthe RACT Evaluation Report indicate that the 2008 total NOx emissions (for the IC engines and the digesters combined) were 28.41 tons. This figure is equivalent to average daily emissions of0.078 tons. Draft SIP subsection IX.H.l2.e ., however, proposes to allow NOxemissions from the IC engines of 0

.648 tpd and 205.6 tpy
. No emission limits or operational limits are proposed for the digesters. Please explain how the 2008 actual emissions could be a valid basis for modeling, when the proposed allowable emissions are at least eight times higher (0.648 tpd allowed versus 0.078 tpd actual). Please also explain how 0

.648 tpd was calculated to be an appropriate RACT limit. No such explanation appears in the RACT Evaluation Report. 4) The proposed SIP language should be clarified as follows to ensure the enforceability of emission limits:

i) Subparagraph i should clearly state that Central Valley Water Reclamation shall maintain and operate electrical meters to record the electricity production at each ofthe engines. The text should also identify the current engines at the plant. ii) In Subparagraphs ii and iii , please state the number ofthe 1150 kw and 1340 kw engine generators. iii) Subparagraph iv should clarif y that compliance with the emission limits in Subparagraphs ii and iii shall be determined by stack test, and that compliance with the emission limit in Subparagraph i shall be determined through use ofemission factors. Also , Subparagraph iv should state the required frequency of stack tests. Ifthe required frequency will be less than once per year, please explain why such a frequency is adequate to ensure continuous compliance with the limits. g) Chemical Lime Company (LHoist North America) 1) Draft SIP subsection IX.H.l2.f. requires installation of SNCR technology for NOx control and a baghouse for PM control on the Lime Production Kiln "upon source start-up. " Page 1 ofthe RACT Evaluation Report states that the kiln has been in "temporary care and maintenance mode" since November of2008

. It is unclear whether this means the kiln is now completely shut down

. Please explain whether " source start-up" means a cold start-up after a complete shutdown. 2) The RACT Summary Table indicates that a baghouse will be installed at the lime processing rotary kiln for PMz.s control by 2019, and SNCR will be installed at the kiln for NOxcontrol by 2019

. Please explain why an earlier date would not be achievable

. 3) Draft SIP subsection IX

.H.l2

.f. does not include any proposed NOxemission limit after installation of SNCR technology at the kiln, nor does it indicate whether the SNCR will even be tested after it is installed. If Chemical Lime is being credited with a NOxemission

19reduction due to eventual installation of SNCR, then this needs to be reflected in terms ofa NOx emission limit and appropriate compliance testing requirements by a specific deadline. 4) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed at Chemical Lime, on a plantwide daily basis. The table provided to us on October 31, 2013 lists emission figures in tons/year that were used for modeling for Chemical Lime. The basis for those figures is not indicated. We do not know if those figures might represent the proposed RACT allowable, i.e., installation of SNCR and a baghouse at the kiln after it resumes operation. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. 5) Condensable PM is not accounted for in the RACT Evaluation Report or in the proposed PM emission limit in draft SIP subsection IX.H.12.f. of0.12 lbs/ton of stone feed. The SIP subsection does not indicate whether stack testing needs to include condensable PM. Please explain why condensable PM is not accounted for. See our related General Comment #5 on condensable PM above. Please also explain why the proposed emission limit is expressed as PM rather than PM2
.5. The table provided to us on October 31, 2013 indicates that the emissions inputted to modeling were 117.42 tpy ofPM2

.s· How does this relate to the proposed emission limit of0.12 lbs. ofPM per ton of stone feed? 6) Stack testing is proposed to be required at a minimum ofevery five years. We are concerned with stack test frequencies longer than one year. Please explain why these test frequencies are sufficient to ensure continuous compliance with the limits. h) Chevron Products Company- Salt Lake Refinery 1) Page 8 ofthe RACT Evaluation Report identifies NOx RACT for Process Heaters and Boilers as replacement ofboilers 1, 2 and 4 with ULNB capable ofachieving a NOx emission rate of 0.03 lb/MMBtu. The Report says a NOx emission reduction of 110 tpy is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2017. However, draft SIP subsection IX.H.12.g. does not include a requirement to replace boilers 1, 2 and 4. The SIP subsection specifies the calculations to be used for demonstrating compliance with sourcewide NOx emission limits, but it is not apparent whether any ofthese calculations take into account any requirement to replace the boilers with ULNB. Please explain. If Chevron is being credited with emission reduction due to installation ofnew controls as RACT, then this needs to be reflected as proposed RACT in the SIP. Please also explain why an earlier date than 2017 would not be achievable. 2) Page 7 ofChevron's own RACT analysis, dated March 11,2013, contains an analysis for three rich bum reformer compressor engines with a potential to emit of 159

.2 tpy NOx each

. Using air-to-fuel ratio (AFR) controls and Non-Selective Catalytic Reduction (NSCR) at a cost of $4,966/ton was considered by Chevron to be economically infeasible, but we find that conclusion to be questionable. Though Chevron states that AFR 

### + NSCR will be implemented in the future "within one year ofthe date ofentry ofthe pending draft agreement with EPA," it would appear to be a logical requirement for the PM2

.s SIP. Why was it not discussed in the state's RACT Evaluation Report and why is it not proposed to be required for this SIP? 203) Under "Source-wide PM2.5," draft SIP subsection IX.H.l2

.g.i. reads, "Filterable PM2

.s emissions shall be determined by applying 

### various emission factors

..." This language is imprecise/vague. Please delete the word "various." 4) In the same paragraph, the language reads, "Unless otherwise specified by an Approval Order

.. ." This is not approvable language. EPA needs to be able to approve any revisions to the methods for determining compliance, unless the SIP establishes enforceable, replicable procedures for modifying the methods. For example, where a revision to an emission factor is established through a simple stack test, we have been willing to approve SIP language that describes the process. The process should include notice to us ofthe stack test date, results, and new emission factor. 5) In a later paragraph, the language reads, "Daily gas consumption by all boilers and furnaces shall be measured by meters that can delineate the flow of gas to the indicated emission points." The phrase " indicated emission points" is undefined. The

-SIP language needs to specify the emission points that are covered

. 6) In a later paragraph, the language reads, "By no later than January 1, 2017, Chevron shall conduct stack testing to establish the ratio of condensable PM2
.5 from the FCC Catalyst Regenerator and SRUs. At that time the condensable fraction will be added and a new source-wide limitation shall be established in the AO." This is not approvable. There is no explanation why it would not be possible to establish the condensable ratio now, through testing, use ofemission factors , or estimates. The SIP is supposed to evaluate RACT for condensable and filterable PM. The SIP cannot defer the establishment of limits. And the SIP must contain the RACT limits, not an AO. 7) Source-wide NOx provisions: Language reads , "

... the most recent listing ofthese emission factors is maintained in Chevron's AO. " This is not approvable. The SIP must contain the relevant emission factors for RACT, not an AO. 8) Source-wide S02provisions: The RACT Evaluation Report does not identify any level of control efficiency as RACT for S02 emissions from the SRU at Chevron, nor does this appear in draft SIP subsections IX

.H.ll. or IX

.H.l2.g. We consider it essential to specify a level ofcontrol efficiency as RACT and would expect 95% or better control. Please supplement the TSD with a discussion ofwhat level of control should be expected for the SRU at Chevron and include that level ofcontrol in draft SIP subsection IX.H.ll or IX

.H.l2.g. 9) Draft SIP subsection IX.H.12.g relies on NOx, S02 and H2 S CEMS to determine some ofthe emissions and emission factors , but this subsection ofthe draft SIP doesn't clearly require the operation ofCEMS

. This does not appear to be addressed by the General Requirements for Petroleum Refineries at draft SIP subsection IX.H.ll

.g. Please see our related comment on IX

.H.ll.g. I 0) There are no proposed requirements to report excess emissions. Please explain how this will be addressed

.
21i) Great Salt Lake Minerals Corporation CGSLM): Production Plant 1) The RACT Summary Table indicates that a PM emission limit of0.010 gr /dscfwill be imposed at all baghouses and scrubbers on salt/SOP production lines by 2017. Draft SIP subsection IX

.H.12.h. requires stack tests by January 1, 2017. Page 13 ofthe RACT Evaluation Report indicates, however, that with the sole exception ofwet scrubber AH-013 , all existing baghouses and scrubbers at GSLM can already meet 0

.010 gr /dscf, as demonstrated by recent stack test results. The proposed limit "will be more representative of actual operations operating at RACT levels." Further, the existing emission limit for nine of the eleven PM control devices is already at or near 0.01 gr /dscf in the current NSR permit. Please explain why an earlier date than 2017 would not be achievable. It appears that only AH-013 needs time to comply. 2) Draft SIP subsection IX.H.12.h

. does not require stack testing for condensable PM. Please explain why condensable PM is not addressed. This is not explained in the RACT Evaluation Report. 3) The RACT Summary Table indicates that ultra low NOx burners (ULNB) will be required at Boilers # 1 and #2 by 2017. Draft SIP subsection IX.H.12.h

. requires stack tests by January 1, 2017, to demonstrate compliance with a proposed NOx emission limit of9

.0 ppmdv. Please explain why an earlier date would not be achievable. 4) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31, 2013 indicates that the emissions used for modeling were " 2008 Actual. " The RACT Evaluation Report does not indicate what the emissions were in 2008

. There is also no information on what the allowable emissions will be, on a plantwide daily basis, after RACT is applied. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. 5) The RACT Summary Table projects emission reductions by 2017 of22.12 tpy ofNOx (due to installation ofULNB) and 7.97 tpy ofPM (due to imposition ofmore stringent allowables in gr/dscf at existing PM controls)

. It is unclear why the state would use 2008 actuals as the basis for modeling, when emission reductions through application of new controls as RACT are projected after 2008. It appears that no credit for these reductions is reflected in the modeling. Please explain

. 6) Stack testing is proposed to be required at a minimum ofevery five years. We are concerned with stack test frequencies longer than one year. Please explain why these test frequencies are sufficient to ensure continuous compliance with the limits. 7) Please explain why emission limits are proposed in terms ofPM1 orather than PM2

.S· j) Hexcel Corporation 1) Draft SIP subsection IX.H.12.i. proposes a plantwide limit on daily natural gas consumption and a plantwide limit on daily carbon fiber production. Page 5 ofthe RACT Evaluation Report indicates, however, that "existing controls" consist not only ofa plantwide carbon 22fiber production limit and a natural gas consumption limit (the latter for NOx and S02 control) , but also a plantwide VOC emission limit, along with various operational controls on incinerators/ovens. Please explain why no plantwide VOC emission limit or operational controls on the incinerators/ovens are proposed as RACT requirements. 2) The RACT Evaluation Report also identifies continued use ofincinerators as RACT for VOC control at Fiber Lines 2-8 and 10-12, the Pilot Plant, and the Matrix Operations. The current NSR permit (Approval Order) dated December 28 , 2011, specifies minimum operating temperatures and residence times for the incinerators. Please explain why a requirement for continued use ofthese incinerators for VOC control, with appropriate operational parameters, is not included as proposed RACT in draft SIP subsection IX

.H.12.i

. 3) The RACT Evaluation Report also indicates that Fiber Lines 13 and 14 currently are permitted with a baghouse for PM control, the use ofultra-low NOx burners for NOxcontrol, and use ofa Regenerative Thermal Oxidizer (RTO) for VOC emission control. The Report identifies these controls as RACT for PM2
.5, NOxand VOC at Fiber Lines 13 and 14. The current NSR permit (Approval Order) dated December 28 , 2011 , specifies operational requirements for the baghouse and RTO at these fiber lines. Please explain why no emission limits or requirements for PM2.s , NOxor VOC controls are proposed in subsection IX.H

. 12

.i. as RACT requirements at Fiber Lines 13 and 14

. k) Hill Air Force Base 1) Page 1 ofthe RACT Evaluation Report says Hill AFB is subject to existing requirements in 40 CFR 60, subparts De, IIII and JJJJ, as well as requirements in 40 CFR 63, subparts N, GG, ZZZZ, and DDDDD. These bodies ofregulation contain numerous requirements for the pollutants ofinterest for the PM2
.5 SIP

. Compliance with NSPS (40 CFR 60) and MACT (40 CFR 63) requirements is identified in several places in the RACT Evaluation Report as RACT for NOxand VOCs

. Hill AFB is also subject to numerous other requirements for the pollutants ofinterest for the PM2
.5 SIP (primarily for VOCs). These requirements may be found in the title V permit and pertain to topics such as surface coating operations, degreasing, and solvents. However, the only requirement proposed as RACT in draft SIP subsection IX.H.12.j. is a limit of0

.5 tpd ofVOC emissions from painting and depainting operations. No such limit is proposed in the RACT Evaluation Report. As we explained in the General Comments above, for an approvable attainment demonstration, the state needs to identify the existing local measures in the area that contribute to attainment ofthe NAAQS in that area, so that EPA can approve those measures specifically as RACT. 2) The only proposed emission limit in draft SIP subsection IX.H.12.j is 0.5 tpd for VOC emissions from painting and depainting operations

. Subparagraph ii says, "Compliance with this daily average shall be determined monthly." This language is not approvable because it is inadequate to ensure enforceability ofthe limit. The SIP needs to specify the method(s) used to determine compliance, identify what specific painting and depainting operations at Hill AFB are to be covered by this limit, and require recordkeeping. Also, the import of Subparagraph ii is not clear. Is this intended to make the daily limit into a monthly average?

23If so, we question whether an averaging time longer than 24 hours can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 3) We could find no explanation how 0.5 tpd ofVOC emissions from painting and depainting operations represents RACT. The RACT Evaluation Report does not propose any such limit. Please explain how this proposed limit was calculated to be RACT. 4) Page 3 ofthe RACT Evaluation Report says no additional control is considered RACT for NOx for the 12 boilers at Hill AFB , on the basis ofhigh cost, in dollars per ton ofNOx removed. The main reason given is that normally steam is provided from outside (Wasatch Energy Systems) and the boilers are only kept for the event that steam no longer can be provided from the outside

. This may be appropriate for emergency operation, but ifthe outside source of steam is lost permanently, then the boilers at Hill AFB will have to operate routinely from then on. This could allow the dollars

-per-ton costs to become feasible. Please address this concern. 5) The RACT analysis for degreasing operations (section 2.1.d ofthe RACT Evaluation Report) appears inadequate. Questions include: Are there older units that could be replaced with newer units with up-to-date passive and active emissions control methods, such as condensers or carbon adsorption systems? Is there a smaller number oflarger units that can be addressed separately, and/or multiple units in concentrated areas that could be addressed in groups ? Has the use of low VOC solvents been examined? The July 16, 2013 TechLaw RACT evaluation states: "Nellis Air Force Base is in the RBLC as permitted with vapor condensers and recovery for controlling VOC emissions. It appears that there could be potential for emissions reductions from the same or similar technologies for some but not all ofthe degreasing operations at HAFB ." Please explain whether these options have been considered, or will be considered

. 6) We have the same comment on the RACT analysis for general solvent use (section 2.1.g of the RACT Evaluation Report) as for degreasing operations above. Other facilities should be examined for potential RACT control measures. I) Holly Refining & Marketing Company 1) The RACT Summary Table indicates that a Wet Gas Scrubber (WGS) will be installed f or PM, S02and NOx control at proposed FCCU #2 by 2017, that Selective Catalytic Reduction (SCR) will be installed for NOx control at heaters and boilers by 2017 , that the compressors will be replaced with electric units for control of all pollutants by 2017 , and that a WGS will be installed for S02control at the Sulfur Recovery Unit (SRU) by 2017. Please explain why an earlier date would not be achievable. 2) There are a number ofinstances where new controls are identified as RACT in the RACT Evaluation Report, and are credited with emission reductions in the RACT Summary Table, but are not required in draft SIP subsection IX

.H.12.k: i) Pages 5 and 6 ofthe RACT Evaluation Report identify RACT for PM2

.s and S02at proposed FCCU #2 as installation ofWGS. The Report says reductions of 30 tpy for

24PM2 .5and 260 tpy for S02are expected. These expected reductions are also cited in the RACT Summary Table, to be achieved by 2017. ii) Page 7 ofthe RACT Evaluation Report identifies RACT for NOx at proposed FCCU #2 as installation ofWGS-LoTOx. The Report says a NOx reduction of26.2 tpy is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2019. iii) Page 9 ofthe RACT Evaluation Report identifies RACT for NOx at Process Heaters and Boilers as installation of SCR on three process heaters (1 OH1, 30H1 and 30H2) and Boiler #8. The Report says a NOx reduction of 35 tpy is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2017. iv) Page 9 ofthe RACT Evaluation Report identifies RACT for all pollutants at the Compressors as replacement ofthe existing compressors with all electric equipment. The Report says the expected emission reductions are 1.6 tpy for PM2

.s, 0.04 tpy for S02, 96.2 tpy for NOx, and 4 tpy for VOC. These expected reductions are also cited in the RACT Summary Table, to be achieved by 2017. v) Page 11 ofthe RACT Evaluation Report identifies RACT for S02at the Sulfur Recovery Unit (SRU) as "continue to operate the WGS unit as a final S02removal system for the existing SRU." The Report says a S02 reduction of 125 tpy from the 2008 baseline (modeled) inventory is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2017. Draft SIP subsection IX.H.12.k. specifies the calculations to be used for demonstrating compliance with sourcewide S02 and NOx emission limits, but it is not apparent whether any ofthese calculations take into account any requirement to install and use new emission controls. Please explain. IfHolly is being credited with emission reductions due to installation ofnew controls as RACT, then this needs to be reflected as proposed RACT in the SIP. 3) Page 14 ofthe RACT Evaluation Report proposes no changes to existing wastewater operations as VOC RACT for wastewater separators and drains. One option is presented as technically feasible (ensuring all drains are covered and routing the API separator vent gas to a control device for thermal combustion or oxidation), with potential 70% VOC control, but was not selected as RACT. One other area refinery (Chevron), however, operates a regenerative thermal oxidizer system in conjunction with covers and vent routing. Page 14 of the RACT Evaluation Report for Holly estimates VOC emission reductions as high as 31.6 tpy ifa similar system were employed at Holly, but does not propose such a system, instead stating only that "further discussions on controlling wastewater VOC emissions need to be held." Since it is proven to be technically and economically feasible at another area refinery, why is it not proposed here? Please explain. 4) Under "Source-wide PM2s," draft SIP subsection IX.H.12.k. reads, "PM25 emissions shall be determined by applying various emission factors

..." This language is imprecise/vague. Please delete the word "various." Also, unlike Big West and Chevron, this language does not say "filterable." Was that an inadvertent omission? 255) In the same paragraph, the language reads , "Unless otherwise specified by an Approval Order

..." This is not approvable language

. EPA needs to be able to approve any revisions to the methods for determining compliance, unless the SIP establishes enforceable, replicable procedures for modifying the methods. For example, where a revision to an emission factor is established through a simple stack test, we have been willing to approve SIP language that describes the process. The process should include notice to us ofthe stack test date, results , and new emission factor. 6) Language in a later paragraph reads , "Daily natural gas and plant gas consumption shall be determined through the use offlow meters. " There is no indication where these meters are located, for which emission points they are tracking the fuel consumption, and how they would delineate the flow of gas to the emission points

. The SIP language needs to specify the emission points that are covered. 7) Source-wide S02provisions : Language reads , "

. . . excluding routine SRU turnaround maintenance emissions

." It is unclear why Holly needs this exemption when it is not proposed for the other refineries

. As we explained in our comment on SIP subsection IX.H

. 1l.d, periods ofexemption from emission limits are inconsistent with CAA requirements that SIP emission limits apply at all times, including periods of startup, shutdown, and malfunction. This comment applies also to periods of scheduled equipment maintenance

. 8) There is no requirement for S02CEMS or any other technique for accounting for SRU emissions of S02

. It is our understanding that the SRU at each refinery has an S02 CEMS , which we would expect to be used to account for a portion of source-wide S02emissions. See, for example, SIP subsection IX

.H

. 12

.g.iii for Chevron, which requires use of S02 CEMS in determining S02emissions from the SRU

. Please explain why this is not accounted for at Holly. 9) The RACT Evaluation Report does not identify any level ofcontrol efficiency as RACT for S02emissions from the SRU at Holly, nor does this appear in draft SIP subsections IX.H

. 11

. or IX.H.12

.k

. We consider it essential to specify a level ofcontrol efficiency as RACT and would expect 95 % or better control. Please supplement the TSD with a discussion of what level ofcontrol should be expected for the SRU at Holly and include that level ofcontrol in draft SIP subsection IX

.H.ll or IX.H

. 12.k. 1

0) The source-wide S02provisions include a provision that, "The sulfur content ofthe fuel oil shall be tested ifdirected by the Director. " Why was this provision considered necessary for Holly? Chevron's source-wide S02provisions also account for fuel oil, but do not include this particular provision. What is the import ofthis provision? Iftests show a different sulfur content than the ASTM method, will the test results establish a new emission factor going forward? This is not explained. 11) Unlike Big West and Chevron refineries , there is no requirement for NOx CEMS or any other technique for accounting for catalyst regenerator emissions ofNOxat Holly. See, for example, requirement for NOxCEMS at the Catalyst Regeneration System at Big West and


### 26requirement for NOx CEMS at the FCC Regenerator at Chevron. Please explain why this is not accounted for at Holly. 12) Draft SIP subsection IX.H.12.k relies on H2 S CEMS to determine some ofthe emissions and emission factors, but this subsection ofthe draft SIP doesn't clearly require the operation of CEMS. This does not appear to be addressed by the General Requirements for Petroleum Refineries at draft SIP subsection IX.H.ll.g. Please see our related comment on IX.H.l1.g. 13) There are no proposed requirements to report excess emissions. Please explain how this will be addressed. m) Kennecott- Bingham Canyon Mine/Copperton Concentrator I) Page 5 ofthe RACT Evaluation Report identifies NOx RACT for haul truck tailpipe emissions as "replace all trucks that are older than 14 years with trucks that have the highest tier rating available and that in the future as trucks are replaced, the replacements use the highest tier engine available." The Report explains that the higher tier engines have lower NOx emissions in grams per horsepower-hour. However, draft SIP subsection IX.H.l2.l. does not propose any such requirement. Instead, the only proposed requirement pertaining specifically to haul trucks is a limit of 30,000 miles ofhaul truck use per calendar day. This choice of a truck mileage limit as a representation ofRACT is not reflected in the RACT Evaluation Report. Please explain why the proposed RACT requirement pertaining to the haul trucks does not resemble the discussion in the RACT Evaluation Report. 2) The RACT Summary Table indicates that higher tier engines will be used in haul trucks for NOx control by 2019 and credits Kennecott with a 64.7 tpy NOx reduction. For additional reductions such as this to be creditable in the attainment demonstration, a requirement to achieve such reductions needs to be reflected in the SIP. Please explain why this was not done. Please also explain why an earlier date would not be achievable. Page 5 ofthe RACT Evaluation Report says that ifthe four tier 1 trucks that are older than 2005 were replaced now, that would reduce the emissions by 64.7 tpy. Page 9 ofthe Report says that "Requiring KUC to replace the model year 2004 haul trucks with trucks that have the highest tier rating available will reduce NOx emissions by a minimum of64.7 tpy. This will begin in 2018 with complete reduction by 2018. In 2019 the six 2005 model year trucks will begin replacement by 2019 but the replacement will not be complete until the end of2019." Please explain why the 64.7 tpy emission reduction in the RACT Summary Table is not proposed to occur until 2019. From the RACT Evaluation Report, it appears that reductions beyond the 64.7 tpy reduction cited in the RACT Summary Table might occur by 2019. 3) Draft SIP subsection IX.H.12.l. proposes to limit sourcewide emissions to 6,205 tons per rolling 12-month period, for NOx, PM2

.s and S02 combined, until January 1, 2019. After that date, sourcewide emissions are proposed to be limited to 5,585 tons per rolling 12-month period. No rolling 12-month emission limits are proposed in the RACT Evaluation Report. Please explain how rolling 12-month limits can represent RACT in a plan that is intended to attain a 24-hour NAAQS. Please also explain how these proposed limits were calculated and whether they have any relationship to the proposed mileage limit of 30,000 miles per day of haul truck use.

274) The provisions in the draft SIP are not adequate to ensure the enforceability ofthe specified measures. For example, the draft does not specify means to determine compliance with the 30,000 mile calendar day limit. Regarding the source-wide combined NOx, PM2.5 and S02 limits, the draft SIP states that compliance will be determined "per methodology outlined in the Emission Inventory." It is unclear what this means , and it is not sufficient to ensure the limits could be enforced, even assuming a 12-month averaging period would be sufficient. 5) We are also concerned with the specification of a combined limit for the three pollutants and require an explanation how this is sufficient given the differing impacts ofthe three pollutants on ambient PM2.s levels. 6) The provisions to address fugitive dust are vague and practically unenforceable. What does the phrase "as conditions warrant" mean? The draft language does not explain. Greater specificity is needed. What is "the pit influence boundary?" The draft language does not define this phrase

. What does it mean to require, as one possible measure, "ensure the surface ofthe active haul roads located within the pit influence boundary consists of

. .. chemical dust suppressant?" Isn ' t chemical dust suppressant something applied to the surface ofthe haul roads? What does the phrase "shall be the primary means" mean? Is it possible to specify that the ore conveyors shall be used to transport all crushed ore from the mine to the concentrator? Or at least some minimum percentage on a daily basis? Please explain why twice per year application ofchemical dust suppressant to active haul roads outside ofthe pit influence boundary is adequate. Assuming there is an air quality benefit to the use ofgraders, the draft SIP needs to specify the required frequency of grading. n) Kennecott- Power Plant, Tailings Impoundment, Bonneville Borrow Plant and Laboratory 1) Page 4 ofthe RACT Evaluation Report says a RACT analysis was not performed on existing main boilers 1, 2 and 3 at the Power Plant, because they are being replaced by a Unit 5 combustion turbine and will not be in operation after 2016. However, draft SIP subsection IX.H.12.m. says that boilers 1, 2 and 3 shall not be operated after January 1, 2018 , or upon commencing operation ofUnit 5, whichever is sooner. This implies that boilers 1, 2 and 3 are allowed to operate until possibly 2018. Draft SIP subsection IX.H.12.m

. does not specify any emission limits for boilers 1, 2 and 3. Please explain why emission limits for boilers 1, 2 and 3 are not proposed to be retained until2018 as RACT. As we explained in the General Comments above, for an approvable attainment demonstration, the state needs to identify the existing local measures in the area that contribute to attainment ofthe NAAQS in that area, so that EPA can approve those measures specifically as RACT. 2) Draft SIP subsection IX.H.12.m. says the NOx and VOC emission limits for Unit #5 at the Power Plant (combined cycle combustion turbine) apply "under steady state operation." No limits are listed for any other periods of operation. As we have noted in our comments above on SIP subsection IX.H.11.d, this is inconsistent with CAA requirements that SIP emission limits apply at all times, including periods of startup, shutdown, and malfunction (SSM)

. We have similar concerns regarding the language that appears twice that reads , " The limited use ofnatural gas during startup, for maintenance firings and break-in firing does not constitute steady-state operation and does not require stack testing."

283) Draft SIP subsection IX.H.12

.m. does not indicate any stack test methods or other means (e.g ., CEMS) for demonstrating compliance with any ofthe proposed emission limits at the Power Plant, nor are any averaging times indicated for the emission limits

. Draft SIP subsection IX.H.11.e. should be cross-referenced for stack test methods, as was done for other sources (e.g., Central Valley Water Reclamation ; Chemical Lime), and averaging times indicated for the emission limits. For CEMSs, appropriate requirements should be specified. In particular, we do not understand why NOxCEMS is not required. Please explain. 4) Stack testing for Unit #5 (combustion turbine) is proposed to be required once every three years . We are concerned with stack test frequencies longer than one year. Please explain why this test frequency is sufficient to ensure continuous compliance with the limits. 5) Page 7 ofthe RACT Evaluation Report identifies NOxRACT for boiler 4 as installation of LNB with OFA and SCR. The RACT Summary Table indicates that these controls will be installed by 2019, with an expected NOxreduction of 170 tpy. Please explain why an earlier date would not be achievable. Please also explain why draft SIP subsection IX

.H.12

.m. does not include a requirement to install these controls. The subsection does indicate that the NOx emission limit for boiler 4 changes from 336 ppmdv to 60 ppmdv on January 1, 2018 , but it is not clear that this can be treated as an enforceable requirement to install new controls. 6) Draft SIP subsection IX.H.12.m.i.D proposes to restrict fuel to natural gas during winter months (November through February) for boiler #4, with coal allowed the rest ofthe year. EPA is evaluating whether proposals to apply requirements on a seasonal basis are an acceptable approach to address PM2

.s under the CAA. Also , during the winter months, the draft SIP proposes to allow Unit #4 to burn coal during natural gas curtailments, plus sufficient time to empty the coal bins following the curtailment. Was any coal usage modeled in the attainment demonstration? Ifnot, then we would be concerned with allowing the burning ofcoal until the coal bins are empty. 7) The RACT Evaluation Report identifies this source as consisting ofnot only the Power Plant, but also the Tailings Impoundment, Bonneville Borrow Plant (BBP) and Laboratory. For the Tailings Impoundment, page 9 ofthe Report identifies RACT as water spray/wet suppression, polymer application, and revegetation. These are all existing practices

. Draft SIP subsection IX.H.12.m., however, contains no requirements for dust control at the Tailings Impoundment. As we explained in the General Comments above, for an approvable attainment demonstration, the state needs to identify the existing local measures in the area that contribute to attainment ofthe NAAQS in that area, so that EPA can approve those measures specifically as RACT

. For the BBP, page 9 ofthe RACT Evaluation Report says RACT has not yet been identified because the BBP has not yet started operation. However, draft SIP subsection IX.H.12.m. proposes as RACT a limit of 12,500 miles per day ofhaul truck use. Please explain how this was determined to be RACT. Also , the draft SIP needs to specify a means to determine compliance with the mileage limit. 8) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31 , 2013 indicates that projected actuals were used for modeling. We do not 29know ifthe projected actuals take into account the expected shutdown of boilers 1, 2 and 3, and replacement with a combustion turbine. There is also no information on what the allowable emissions will be, on a plantwide daily basis, after RACT is applied. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. o) Kennecott- Smelter, Refinery and Molybdenum Autoclave Processing Plant 1) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31, 2013 indicates that projected actuals were used for modeling. The RACT Evaluation Report does not indicate what the actual emissions are on a plantwide daily basis. There is also no information on what the allowable emissions will be, on a plantwide daily basis , after RACT is applied. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. 2) Draft SIP subsection IX.H.12.n. proposes emission limits in pounds per hour for the Main Smelter Stack and for the Refinery boilers and Combined Heat Plant. The RACT Evaluation Report does not give any indication what emission limits in lblhr might represent RACT. Please explain how the proposed emission limits 

### in lb/hr were calculated and determined to represent RACT. 3) Draft SIP subsection IX.H.12.n. does not specify any stack test methods. Draft SIP subsection IX.H.11.e. should be cross-referenced for stack test methods, as was done for other sources (e.g., Central Valley Water Reclamation ; Chemical Lime) , and an averaging time specified for the NOx emission limits at the Refinery. 4) Draft SIP subsection IX.H.12.n.i.A.I.3. proposes a NOx emission limit for the Main Stack on an annual average. Please explain how an annual average can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 5) Draft SIP subsection IX.H.12.n.i.A.III.l. proposes NOx RACT allowable emission limits for the Holman Boiler on a 30-day average. Please explain how 30-day averages can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 6) Draft SIP subsection IX.H.12.n.i.B.III, on monitoring ofNOx emissions at the Holman Boiler, requires "CEMS or alternate method determined according to applicable NSPS standards." Why is the language about an alternate method necessary? Hasn't the monitoring method already been established? Why would it change? 7) For the Tankhouse Boilers, draft SIP subsection IX.H.l2.n.ii.B. states, " compliance with the emission limitation by the second boiler shall be determined by the stack test ofthe first boiler." We question whether that's acceptable, regardless ofwhether the two boilers are identical in make, model, and pollution control equipment. What about the proper operation and maintenance ofthe boilers and control equipment?

30Also , stack testing for the Tankhouse Boilers at the Refinery is proposed to be required once every three years. We are concerned with stack test frequencies longer than one year. Please explain why this test frequency is sufficient to ensure continuous compliance with the limits. 8) Draft SIP subsection IX.H.12.n.ii.C. allows for use of#2 fuel oil during testing and maintenance periods at the Tankhouse Boilers. No limit is placed on the duration ofthese periods. Ifthe emissions associated with such fuel use have not been modeled in the attainment demonstration, then we would be concerned with such use. 9) Draft SIP subsection IX

.H.12.n.iii. needs to define the terms "MAP" and " TEO. " p) Nucor Steel 1) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31, 2013 indicates that projected actual emissions were used as the basis for modeled emissions. The RACT Evaluation Report provides some information on 2008 actual annual emissions for portions ofthe plant, but we are unable to determine what the emissions were for the overall plant on a daily basis. Also , we are unable to determine from draft SIP subsection IX.H.12.o. how much emissions are proposed to be allowed for the overall plant on a daily basis. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. 2) Page 8 ofthe RACT Evaluation Report says that " Based on the consent decree, Reheat furnace #1 and Reheat furnace #2 constitute RACT

." Please be aware that there is no provision in the Clean Air Act for consent decrees to constitute RACT. Since the consent decree apparently required a "thorough evaluation ofpossible NOxcontrols for reheat furnaces ," then that evaluation should be presented in the RACT Evaluation Report, or at least a summary ofthat evaluation, rather thanjust a statement about EPA' s conclusion ofthe study. EPA made no conclusion from the study that constituted RACT. The RACT Evaluation Report does not explain what possible NOxcontrols were considered, nor why 0.07 lb/MMBtu should constitute NOxRACT for new reheat furnaces, nor why 0.09 lb/MMBtu should constitute NOxRACT for retrofit furnaces. 3) Draft SIP subsection IX.H.12.o

. proposes a NOx emission limit for the Electric Arc Furnace (EAF) Baghouse of " 59.75 lbs/hr (12-month rolling average). " Please explain how a 12- month rolling average can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 4) Draft SIP subsection IX

.H.12.o. does not specify an averaging time or a stack test method for the proposed NOxemission limits at Reheat Furnaces #1 and #2 , nor for the proposed VOC emission limit at the EAF Baghouse. Draft SIP subsection IX

.H.11

.e. should be crossreferenced for stack test methods, as was done for other sources (e.g

., Central Valley Water Reclamation ; Chemical Lime) , and an averaging time specified for the emission limits. 5) Stack testing at the EAF Baghouse for VOC is proposed to be required once every five years and stack testing at the Reheat Furnaces for NOxis proposed to be required once every three

31years. We are concerned with stack test frequencies longer than one year. Please explain why these test frequencies are sufficient to ensure continuous compliance with the limits. q) Olympia Sales 1) With regard to PM2

.s control, page 5 ofthe RACT Evaluation Report indicates that Olympia Sales plans to install , within the next year, a baghouse for PM control from the woodworking shop, to replace the existing cyclones

. Page 8 identifies RACT for PM2
. 5 as installation ofthe baghouse. The RACT Summary Table indicates that the expected emission reduction due to baghouse installation will be 7

.5 tpy for PM10 and 4.4 tpy for PM2
.5 . The only proposed RACT requirement in draft SIP subsection IX.H.12.p. , however, is installation and operation ofthe baghouse by January 1, 2015. No emission allowable is proposed for PM2 

### .s. If Olympia Sales is being credited with an emission reduction due to installation of a new baghouse, then this needs to be reflected as proposed RACT in the SIP with a proposed emission limit for PM2 

### .s . 2) With regard to VOC control, page 7 ofthe RACT Evaluation Report indicates that recent revisions to the wood furniture MACT will require Olympia Sales to cut the amount ofVOC in their topcoats and sealers almost in halfby January of2015. Page 8 identifies RACT for VOC as continued research and implementation on the use oflow VOC coating and waterbased coatings. The current NSR permit (Approval Order) dated April 13 , 1995 , requires use ofHigh Volume Low Pressure (HVLP) spray guns for all painting processes . However, draft SIP subsection IX.H.12.p. does not propose any RACT requirements for VOC. Please explain why this is not included. 3) Page 1 ofthe RACT Evaluation Report indicates that the plant' s assumed operation will be similar to that ofthe past five years. Page 2 indicates that 2008 actual emissions were 4.28 tons for PM2
.5 and 20.88 tons for VOC. The table provided to us on October 31 , 201'3 indicates that the emissions used for NAAQS attainment modeling were 0

.0279 tpy for PM2
.5 and 15.66 tpy for VOC. Please explain whether the expected installation ofa baghouse accounts for the PM2
.5 reduction from 2008 actual emissions and whether compliance with MACT accounts for the VOC reduction from 2008 actual emissions. If Olympia Sales is being credited with a VOC reduction due to MACT compliance, then this needs to be reflected in proposed RACT requirements in draft SIP subsection IX.H.12

.p. Similarly, as we stated above, if Olympia Sales is being credited with a PM2

.s emission reduction, then this needs to be reflected in terms of a proposed PM2
.5 emission limit for the new baghouse

. 4) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31, 2013 lists emission figures in tons/year that were used for modeling. The basis for these figures (e.g., projected actuals, proposed allowables, 90% ofPTE, or possibly something else) is not indicated. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. r) Pacificorp Gadsby 1) Page 9 ofthe RACT Evaluation Report says, "The summary ofall the above RACT evaluations is that PacifiCorp will extend the SCR catalyst beds on each ofthe three 32combustion turbines at the Gadsby facility. This will increase the amount ofcatalyst and slightly reduce NOxemissions

. Total NOxis expected to drop by 10.7 tons ofactual emissions by the 2017 projection year. " The RACT Summary Table indicates that Gadsby is being credited with a 10.7 tpy NOxemission reduction due to expansion ofthe SCR catalyst beds. However, draft SIP subsection IX.H.12.q. does not reflect this. The proposed RACT emission limits for NOx for the turbines (5 ppmdv and 22.2lblhr at each turbine) are the emission limits that are already in effect. There is no requirement to expand the SCR catalyst beds. If Gadsby is being credited with a NOxemission reduction resulting from expansion of the catalyst beds , then this needs to be reflected as proposed RACT in the SIP

. 2) The RACT Summary Table indicates that SCR catalyst beds will be expanded for NOx control at the natural gas fired turbines by 2017. Please explain why an earlier date would not be achievable. 3) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31 , 2013 indicates that projected actual emissions were used as the basis for modeled emissions. Pages 2 and 6 ofthe RACT Evaluation Report indicate that actual NOx emissions in 2008 were 154.2 tons at the boilers and 29.6 tons at the combustion turbines , for a plantwide total of 183.8 tons
. We expect that projected actuals would be slightly higher. However, we are unable to determine what the proposed RACT allowables equate to in tons per year, for the overall plant. Draft SIP subsection IX.H.12.q

. proposes NOxemission limits of 336 ppmdv at each ofthe three boilers and 22

.2 lblhr for the three turbines combined. The equivalent annual allowable for the turbines is 97

.2 tons , which is 3.3 times as much as the 2008 actual emissions. Please explain what the equivalent annual allowable is for the boilers

. Our objective here is to see ifthere is a substantial difference between the proposed RACT allowable and the emissions used for modeling. For the turbines at least, there does appear to be a substantial difference, which causes us concern. See our General Comment # 1. 4) Draft SIP subsection IX.H.12.q

. proposes RACT allowables for the turbines on a 30-day rolling average. Please explain how 30-day rolling averages can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 5) Draft SIP subsection IX.H

. 12.q uses the word "permittee" several times

. We suggest using

" owner/operator" or " Pacificorp" instead.

s) Tesoro Refining & Marketing Company

- Salt Lake City Refinery 1) Page 14 ofthe RACT Evaluation Report proposes no changes to existing wastewater operations as VOC RACT for wastewater separators and drains

. One option is presented as technically feasible (ensuring all drains are covered and routing the API separator vent gas to a control device for thermal combustion or oxidation) , with potential 70% VOC control, but was not selected as RACT. One other area refinery (Chevron) , however, operates a regenerative thermal oxidizer system in conjunction with covers and vent routing. Page 14 of the RACT Evaluation Report for Tesoro estimates VOC emission reductions as high as 11 tpy ifa similar system were employed at Tesoro , but does not propose such a system, instead stating only that " further discussions on controlling wastewater VOC emissions need to be 33held. " Since it is proven to be technically and economically feasible at another area refinery, why is it not proposed here? Please explain. 2) There are a number ofinstances where new controls are identified as RACT in the RACT Evaluation Report, and are credited with emission reductions in the RACT Summary Table, but are not required in draft SIP subsection IX.H.12.r: i) Page 5 ofthe RACT Evaluation Report identifies RACT for S02 at the FCCU as installation of WGS. The Report says a reduction of 585 tpy for S02is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2019. ii) Page 6 ofthe RACT Evaluation Report identifies RACT for NOx at the FCCU as installation of WGS-LoTOx. The Report says a NOx reduction of 106 tpy is expected

. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2019. iii) Page 8 ofthe RACT Evaluation Report identifies RACT for NOx at Process Heaters and Boilers as installation ofULNB on the heaters on the Ultraformer Furnace F-1. The Report says a NOx reduction of 17 tpy is expected. This expected reduction is also cited in the RACT Summary Table, to be achieved by 2017. Draft SIP subsection IX.H.l2.r. specifies the calculations to be used for demonstrating compliance with sourcewide S02 and NOxemission limits, but it is not apparent whether any ofthese calculations take into account any requirement to install and use new emission controls. Please explain. IfTesoro is being credited with emission reductions due to installation ofnew controls as RACT, then this needs to be reflected as proposed RACT in the SIP

. 3) Under "Source-wide PM2
.5 ," draft SIP subsection IX.H.12.r.i

. reads , "Filterable PM2 

### .s emissions shall be determined by applying various emission factors

..." This language is imprecise/vague. Please delete the word "various. " 4) In the same paragraph, the language reads, "Unless otherwise specified by an Approval Order

... " This is not approvable language. EPA needs to be able to approve any revisions to the methods for determining compliance, unless the SIP establishes enforceable, replicable procedures for modifying the methods. For example, where a revision to an emission factor is established through a simple stack test, we have been willing to approve SIP language that describes the process. The process should include notice to us ofthe stack test date, results , and new emission factor. 5) In the next paragraph, the language reads , " Daily gas consumption by all boilers and furnaces shall be measured by meters that can delineate the flow ofgas to the indicated emission points ." The phrase "indicated emission points" is undefined. The SIP language needs to specify the emission points that are covered. 6) In the next paragraph, the SIP language proposes to defer the establishment ofa condensable ratio for FCCU wet gas scrubber stack and SRU/TGTU/TGI until "no later than January 1, 2019. " At that time a new source-wide limit for PM2

.s will be established in an AO. This is 34not approvable. There is no explanation why it would not be possible to establish the condensable ratio now, through testing, use ofemission factors, or estimates. The SIP is supposed to evaluate RACT for condensable and filterable PM. The SIP cannot defer the establishment oflimits. And the SIP must contain the RACT limits, not an AO. 7) Source-wide S02 provisions: There is no requirement for S02 CEMS or any other technique for accounting for SRU emissions. It is our understanding that the SRU at each refinery has an S02 CEMS, which we would expect to be used to account for a portion ofsource-wide 

### SOz emissions. See, for example, draft SIP subsection IX.H.12.g.iii for Chevron, which requires use of 

### SOz CEMS in determining S02 emissions from the SRU. Please explain why this is not accounted for at Tesoro. 8) The RACT Evaluation Report does not identify any level ofcontrol efficiency as RACT for 

### SOz emissions from the SRU at Tesoro, nor does this appear in draft SIP subsections IX

.H.11. or IX.H.12.r. We consider it essential to specify a level ofcontrol efficiency as RACT and would expect 95% or better control. Please supplement the TSD with a discussion ofwhat level ofcontrol should be expected for the SRU at Tesoro and include that level of control in draft SIP subsection IX.H.11 or IX.H

. 12.r. 9) Draft SIP subsection IX.H.12.r relies on NOx CEMS at the FCCU wet gas scrubber, and on H2 S CEMS for plant fuel gas as an alternative to direct S02measurement, to determine some ofthe emissions and emission factors, but this subsection ofthe draft SIP doesn't clearly require the operation ofCEMS. This does not appear to be addressed by the General

. Requirements for Petroleum Refineries at draft SIP subsection IX.H.11.g. Please see our related comment on IX.H.11.g. 1

0) There are no proposed requirements to report excess emissions. Please explain how this will be addressed

. t) Proctor & Gamble Paper Products 1) Page 9 ofthe RACT Evaluation Report identifies low-NOx burners and good combustion practices as RACT for the paper machine dryer burners. Draft SIP subsection IX.H.12.s. , however, does not propose any NOx emission limits as RACT for the paper machine dryer burners

. The current NSR permit (Approval Order), dated August 2, 2013, includes NOx emission limits for the paper machine process stacks of0.09lb/MMBtu and 13.50 lb/hr

. Please explain why the NOx limits in the current NSR permit are not included as RACT emission limits. 2) Draft SIP subsection IX.H.12.s. indicates that a PM2
.5 RACT emission limit is "to be determined" for the Paper Machine Process Stacks, following stack testing that is proposed to be required by January 1, 2015, to "establish the ratio ofcondensable PM2
.5." The SIP subsection indicates that a PMz.s limit will then be established in the Approval Order. This is not approvable. RACT needs to be included in the SIP (including condensable PM2 .s), not determined at a future date or specified in an AO. 3) Page 3 ofthe revised TechLaw RACT Evaluation Report indicates that there are three diesel tanks at Proctor & Gamble which emit a total ofover 150 tpy ofVOCs. TechLaw 35recommends a RACT evaluation for these tanks. Please explain why the state ' s own RACT Evaluation Report does not include any such evaluation. 4) Stack testing is proposed to be required once every five years . We are concerned with stack test frequencies longer than one year. Please explain why this test frequency is sufficient to ensure continuous compliance with the limits. u) University ofUtah 1) The table provided to us on October 31 , 2013 indicates that the emissions used for NAAQS attainment modeling were projected actual emissions

. It is not clear what this means , considering that the following changes at the University have occurred, or will occur, after the 2008 emission baseline year, as outlined in the RACT Evaluation Report: Lower campus heating plant (Building 303):

• New natural-gas-fired turbine cogeneration unit (73 MMBtu!hr) has been installed and is operating

• Boiler 5 (105 MMBtu!hr) was shut down by 2012 and is being replaced by two 40 MMBtu!hr boilers, expected to be operational by 2017; net expected Oxreduction is 13.15 tpy.

• Boiler 4 (105 MMBtu!hr) will be decommissioned by 2016 and replaced by two 40 MMBtu/hr boilers, expected to be operational by 20 19 ; net expected NOx reduction is 13

. 15 tpy.

• Boiler 3 (105 MMBtu!hr) will be decommissioned by 2018 and replaced by two 40 MMBtu!hr boilers, expected to be operational by 2021 ; net expected NOxreduction is 13.15 tpy. Upper campus heating plant (Building 302) :

• Boiler 4 (87.5 MMBtu/hr) received an upgraded burner management system in 2012 ; estimated NOx reduction was 6

.04 tpy.

• Boilers 1 and 3 (87

.5 MMBtu!hr each) will each receive an upgraded burner management system by 2016; expected NOxreduction is 6

.04 tpy at each boiler. Please explain whether the projected actual emissions take all this into account and how the projected actual emissions were calculated, on a daily basis

. Please also explain what the allowed emissions are for the same time period, on a daily basis. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. 2) The only proposed RACT emission limits in draft SIP subsection IX.H.l2.t. are for the lower campus heating plant:

36• 9 ppmdv for the 40 MMBtulhr boilers that will replace boilers 4 and 5

• 9 ppmdv for the cogen turbine when it is operating alone, or 15 ppmdv when it is operating with the WHRU duct burner

• 187 ppmdv for boiler 3 (because it will not be replaced until 2021) There are no proposed RACT emission limits or emission control requirements for the boilers at the upper campus heating plant, even though the RACT Evaluation Report identifies RACT for NOx at the upper campus boilers to be an upgraded burner management system ("02 trim technology"). The RACT Summary Table identifies 0 2 trim technology as RACT for NOx at the upper campus heating plant and indicates that the upper campus plant is being credited with 12.07 tpy ofNOx reduction as a result. Ifthe University is being credited with an emission reduction due to new controls, then this needs to be reflected as proposed RACT in the SIP, with a requirement to install such a system by a specific deadline. As stated in our General Comment #3, ifRACT consists ofexisting controls, the state needs to identify the existing local measures in the area that contribute to attainment ofthe NAAQS in that area, so that EPA can approve those measures specifically as RACT. 3) The RACT Summary Table indicates that one (or more) boilers at the lower campus heating plant will be replaced for PM, S02, NOxand VOC control by 2017. The Table also indicates that 0 2trim technology will be installed for NOx control at the upper campus heating plant units 1 & 3 by 2015

. Please explain why earlier dates would not be achievable. Similarly, the draft SIP specifies dates in 2017, 2018 and 2019 for initial stack tests for various boilers and for Boiler #3 to convert to backup/peaking status. Please explain why earlier dates would not be achievable. 4) No NOx test method is specified in draft SIP subsection IX.H.12.t. Draft SIP subsection IX.H.11.e. should be cross-referenced for stack test methods, as was done for other sources (e.g., Central Valley Water Reclamation; Chemical Lime). 5) Stack testing is proposed to be required once every three years at the boilers for NOx . We are concerned with stack test frequencies longer than one year. Please explain why this test frequency is sufficient to ensure continuous compliance with the limits. v) Vulcraft!Nucor Building Systems 1) The table provided to EPA on October 31, 2013 indicates that NAAQS attainment modeling was based on emissions that are "90% ofPTE" and that the proposed RACT allowable emissions are also "90% ofPTE." Draft SIP subsection IX.H.12.u. lists a proposed RACT emission allowable for VOC of305.07 tons per rolling 12-month period. We note that this is 90% ofthe allowable in the current NSR permit (Approval Order), which is 338.97 tons per rolling 12-month period. Please explain how it was determined that application oflow-VOC paint results in a calculation of305.07 tons ofVOC per rolling 12-month period as RACT. This is not explained in the RACT Evaluation Report. Please also explain how a rolling 12- 37month emission limit can represent RACT in a plan that is intended to attain a 24-hour NAAQS

. 2) Page 6 ofthe RACT Evaluation Report says R307-350 requires the use oflow-VOC paint and identifies the requirement as RACT. The Report says the requirement under R307-350 is to use paint at Vulcraft with less than 2.8 lbs/gallon VOCs , and to use paint at Nucor Building Systems with less than 2.3 lbs/gallon VOC , unless the products are air-dried, in which case less than 2

.8 lbs/gallon must be used. However, draft SIP subsection IX

.H

. 12.u. says only that R307-350 applies to Vulcraft. Please explain why the specific limits in R307- 350 are not cited as RACT in draft SIP subsection IX .H

. 12.u. 3) Page 5 ofthe RACT Evaluation Report says " It is not technically feasible to construct a collection system at every degreaser" to capture and control VOCs. No analysis was provided to support this conclusion. Facilities frequently do install such collection systems. Please explain further. 4) The draft SIP needs to specify a means to determine compliance with the emission limit. w) Wasatch Integrated Waste Management 1) Draft SIP subsection IX.H.l2.v. requires SNCR to be installed and operating for NOxcontrol by January 1, 2019. Please explain why an earlier date would not be achievable. 2) Draft SIP subsection IX.H.l2.v

. specifies a NOx emission limit of350 ppmdv, but does not say whether the limit is already in effect, or is intended to go into effect after installation of SNCR

. The current NSR permit (Approval Order) dated October 22, 2007 , already specifies 350 ppmdv, therefore it appears to us that subsection IX.H

. 12.v. needs to specify what new NOxlimit will go into effect after installation of SNCR, along with a deadline for initial compliance testing and a test method

. 3) Draft SIP subsection IX.H.l2

.v. says compliance shall be determined by CEMS

. If a NOx CEMS is not already installed and certified, then a deadline should be specified by which it must be certified. Also , the draft SIP subsection doesn ' t clearly require the operation of CEMS

. This does not appear to be addressed by the General Requirements at draft SIP subsection IX.H.ll. Requirements to operate and maintain CEMS should be included in IX.H.11 or in IX.H.l2

.v. 4) Page 1 ofthe RACT Evaluation Report indicates that 40 CFR 60, subpart BBBB (emission guidelines for small municipal waste combustors) applies to this source, but does not identify it as RACT

. Subpart BBBB contains numerous requirements for emission control. Please explain why the requirements that affect control ofPM2 .5 , S02 ,**NO ~**  and VOC should not be considered part ofRACT and incorporated as requirements in draft SIP subsection IX.H

. l2

.v. , along with a requirement to continue operating and maintaining the existing emission control equipment for these pollutants. As we explained in the General Comments above, for an approvable attainment demonstration, the state needs to identify the existing local measures in the area that contribute to attainment ofthe NAAQS in that area, so that EPA can approve those measures specifically as RACT.

385) Page 5 ofthe RACT Evaluation Report indicates that RACT for PM2 .5, VOC and NOx includes replacement ofthe emergency diesel generator with a Tier 4 generator upon equipment replacement, but says there is no timeline established for this replacement at this time. Draft SIP subsection IX.H.12.v. says nothing about replacing this generator. Please explain why the state considers this to be RACT when there is no timeline and no mention of it as a requirement in the draft SIP subsection. 6) Page 5 ofthe RACT Evaluation Report also indicates that RACT includes the requirements for municipal solid waste landfills at 40 CFR 63, subpart AAAA. However, no specific requirements are cited and draft SIP subsection IX.H.12.v. does not include any requirement to comply with 40 CFR 63 subpart AAAA. Please explain whether the state considers the landfill to be part ofthis source for purposes ofthe PM2 

### .s SIP, and if so, whether the state considers the landfill rule to be part ofRACT. We note that the current NSR permit includes the landfill. x) Brigham Young University- Main Campus 1) The current NSR permit (Approval Order) dated June 19, 2012, specifies NOx emission limits of95 ppmdv at Boiler #1 and 127 ppmdv at Boilers #4 and #6. The RACT Evaluation Report explains that Boiler #1 is utilized as a standby heat source and was not included in the RACT analysis. Boilers #2, #3 and #5 are coal-fired but are prohibited from burning coal in winter months, therefore were also not included in the RACT analysis. We think all ofthese units should be assessed for RACT. For example, ifBoilers #2, #3 and #5 are capable of burning natural gas, the RACT analysis should address potential control technologies and limits for that fuel. 2) Draft SIP subsection IX.H.13.a. proposes a NOx RACT limit of30 ppmdv for Boilers #1, #4 and #6, with compliance testing required at #4 and #6 by January 1, 2017. We assume this means that LNB 

### + FGR is expected to be able to achieve 30 ppmdv. Boiler #1 is only required to be retrofitted with LNB 

### + FGR, and then tested, ifit operates more than 300 hours per rolling 12-month period. All six boilers are restricted to natural gas as fuel from November 1 to February 28. No emission limits are specified prior to January 1, 2017. Assuming that EPA concludes that seasonal controls are creditable in the attainment demonstration, and that the proposed limits and deadlines are consistent with CAA requirements, the SIP must nonetheless include the existing emission limits (cited above) for Boilers #1, #4 and #6, and indicate that these limits remain in effect until the new limits take effect on January 1, 2017. The SIP must also specify provisions sufficient to determine compliance with the limits. 3) As mentioned above, draft SIP subsection IX.H.13.a. says Boiler #1 may be operated for up to 300 hours per rolling 12-month period without triggering the need to comply with the 30 ppm emission limit that represents RACT (i.e., LNB 

### + FGR). What is the impact ifthose 300 hours occur during a PM2

.s episode? How did the state model Boiler #1? Again, we caution that EPA is still evaluating whether seasonal controls are an acceptable approach to address PM2

.s under the CAA; in other words, EPA must determine whether a seasonal restriction on coal burning, or seasonal limits, are creditable in the state's attainment demonstration. 394) Pages 2 and 5 ofthe Report identify NOxRACT for Boilers #4 and #6 as replacement ofthe burner spud tips and adding 18% FGR (Flue Gas Recirculation)

. The RACT Summary Table refers to this as LNB 

### + FGR and indicates this is expected to yield 11.1 tpy ofNOxreduction

. The RACT Summary Table indicates that LNB and FGR will be installed at Boilers #4 and #6 by 2017. Please explain why an earlier date would not be achievable

. 5) Regarding Boilers #2 , #3 and #5: Assuming that EPA concludes that seasonal controls are creditable in the attainment demonstration, and that the existing limits for these units are consistent with CAA requirements for RACT/RACM, the NOxemission limits for these boilers (331 ppmdv, listed in the current NSR permit) should be included as part of RACT in draft SIP subsection IX

.H.13.a. , along with provisions suf ficient to determine compliance with the limits. It is not clear whether these units are capable ofburning natural gas. Thi s is relevant to the RACT analysis and should be explained. 6) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31 , 2013 indicates that projected actual emissions were used as the basis for modeled emissions. The RACT Evaluation Report provides some information on 2008 baseline actual emissions for portions ofthe plant, but we are unable to determine what the emissions were on a daily basis in winter months, for the boilers that have operated in winter. Also , we are unable to determine from draft SIP subsection IX.H.13 .a. how much emissions are proposed to be allowed on a daily basis during those months. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. 7) No NOxtest method is specified in draft SIP subsection IX.H.13

.a. Draft SIP subsection IX

.H.11.e

. should be cross-referenced for stack test methods, as was done for other sources (e.g

., Central Valley Water Reclamation; Chemical Lime). 8) Two items should be clarified for the benefit of all readers: First, the SIP should specifically identif y the number ofcentral heating plant units and their names , instead ofmerely referencing " [a]ll central heating plant units. " Second, the testing requirements for Unit # 1 are not clear. We suggest rephrasing the relevant part ofthe footnote to read ,"

... then, within 18 months ofexceeding 300 hours of operation, low NOxburners with Flue Gas Recirculation shall be installed and an initial stack test shall be performed to determine compliance with the emission limit in H

. 13

.a.ii

.A above

. A stack test shall be required every three years thereafter. " 9) Stack testing is proposed to be required at Units #4 and #6 once every three years . We are concerned with stack test frequencies longer than one year at these Units. Please explain why this test frequency is sufficient to ensure continuous compliance with the limits.
y) Geneva Nitrogen 1) Page 2 ofthe RACT Evaluation Report states, "The Prill Tower is a low density prill production unit with no emission control equipment. The uncontrolled prill tower is the major source of ammonium nitrate (NH4N03 ) particulate matter. " Page 3 rejects a wet 40scrubber as not economically feasible for PM10/PM2
.5 control. Page 5 says RACT is represented by the following: "The Prill Tower shall continue to use pollution prevention measures ofreducing microprill formation and reduce carryover offines through entrainment." No such measures are proposed as RACT in draft SIP subsection IX.H.13.b. Page 28 of Geneva Nitrogen's own RACT analysis describes some pollution prevention measures that have already been accomplished during 1995 through 2012. Please explain whether the intent is to require Geneva Nitrogen to continue to look for additional pollution control measures, and if so, why this is not included as a requirement in draft SIP subsection IX.H.13.b. 2) Please explain how the emissions used for NAAQS attainment modeling compare to the emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to us on October 31, 2013 lists emission figures in tons/year that were used for modeling. The basis for these figures (e.g., projected actuals, proposed allowables, 90% ofPTE, or possibly something else) is not indicated. Also, please provide information on what the proposed allowables equate to, in terms ofplantwide emissions. Our objective here is to see ifthere is a substantial difference between the proposed allowable emissions and the emissions used for modeling. 3) Please explain why condensable PM is not accounted for in the RACT Evaluation Report, nor in the proposed PM10 emission limit in draft SIP subsection IX.H.13.b. (which is 0.22 tpd at the Prill Tower). The draft SIP subsection does not indicate whether stack testing needs to include condensable PM. Please also explain why PM10 is specified rather than PM2.s· 4) No stack test methods are specified in draft SIP subsection IX.H.l3.b. Draft SIP subsection IX.H.ll.e. should be cross-referenced for stack test methods, as was done for other sources (e.g., Central Valley Water Reclamation; Chemical Lime). 5) There appear to be conflicting provisions for stack testing. Testing is specified in draft SIP subsection IX.H.l3.b.ii.A, in 13.b.v., and in 13.b.v.A.I. Subsection 13.b.ii.A says that emissions shall be tested every three years but does not indicate testing for which limit or when testing shall commence. Subsection 13.b.v. says compliance testing is required on the Prill Tower, Montecatini Plant, and Weatherly Plant, but says that testing shall be performed no later than January 1, 2019. Again, this subsection does not specify testing for which limits, and it is not clear how this dovetails with subsection 13.b.ii.A. Furthermore, we do not understand why it is appropriate to defer testing until January 1, 2019. Subsection 13.b.v.A.I. indicates that stack testing for the NOx limits must occur every three years, but does not specify a date for the initial test. The SIP must clearly state a reasonable date by which stack testing must start, the frequency oftesting after that, and the limits for which the testing is required. 6) Draft SIP subsection IX.H.13.b.v.B appears to be a requirement derived from the Compliance Assurance Monitoring rule. The language raises several questions. First, since it requires use ofa NOx CEMS, why should it not be used for determining emission compliance, rather thanjust a compliance "indicator"? Second, there's a lack ofclarity- for which NOx emission limit(s) is this supposed to be used? Third, it says excursions trigger an

41inspection, corrective action, and a reporting requirement. Inspection by whom? Corrective action by whom? What sort ofreport and to whom? This subsection should be clarified.

z) Pacificorp

- Lakeside Power Plant 1) Page 5 ofthe RACT Evaluation Report identifies RACT for VOC as retention ofthe existing oxidation catalyst systems at Block # 1 and Block #2, and indicates that Block #2 has a permitted VOC emission limit of2

.8 ppmdv from each turbine/HRSO stack, on a 3-hour average. However, draft SIP subsection IX

.H.13.c. does not include any proposed VOC emission limit or required controls for VOC at Block # 1 or Block #2. Please explain why thi s is not included. 2) Please explain how the emissions used for modeling for NAAQS attainment compare to the proposed allowable emissions. The table provided to us on October 31 , 2013 indicates that for Lakeside Block 1, modeling was based on projected actual emissions. For Block 2, modeling was based on 90% ofPTE. The only RACT allowable proposed in draft SIP subsection IX.H.13.c is 2.0 ppmdv for each turbine/HRSO stack. Please explain what the equivalent plantwide emissions are in tons per day , and what emissions in tons per day were used for modeling

. 3) Draft SIP subsection IX

.H

. 13

.c uses the word "permittee. " We suggest using
" owner /operator" or "Pacificorp" instead

. aa) Pacific States Cast Iron Pipe Company (PSCIPCO) 1) Draft SIP subsection IX.H

. l3.d. indicates that low NOx burners (LNB) with flue gas recirculation (FOR) technology shall be required to be in operation on the Annealing Oven by January 1, 2017

. This is identified as RACT on page 7 ofthe RACT Evaluation Report. It is not clear why page 6 ofthe Report indicates that the current NOxemission rate for the Annealing Oven at PSCIPCO (3

.98 lb/hr and 0

.098 lb/MMBtu) , without L Band FOR, is about the same as the emission rates for " annealing furnaces " at other facilities where LNB + FOR has already been installed (4

.34 lb/hr and 0

.095 lb/MMBtu). This would seem to imply that addition ofLNB + FOR at PSCIPCO would not get much NOxreduction, ifany. However, the RACT Summary Table indicates an expected reduction at PSCIPCO of 1 1. 9 tpy ofNOx. Please explain how that amount ofexpected reduction was estimated. 2) Draft SIP subsection IX.H.13.d. does not propose any NOxemission limit or minimum required NOxcontrol efficiency at the Annealing Oven after installation ofLNB + FOR. If the plant is being credited with a NOxemission reduction due to new controls (11.9 tpy, cited above) , then this needs to be reflected in proposed RACT requirements for NOxin draft SIP subsection IX.H.13 .d. , in terms ofan emission limit or control efficiency, with appropriate testing requirements to determine compliance. 3) Draft SIP subsection IX.H.13

.d

. proposes to require installation ofa 95 % efficient thermal oxidizer by January 1, 2018 , to control VOC emissions from Painting Operations. The RACT Summary Table proposes to credit the oxidizer with a 129.1 tpy VOC reduction. The draft SIP subsection indicates that compliance with the efficiency requirement shall be determined

"using a method acceptable to the Director. " This language is a form ofdirector discretion 42that undermines federal enforceability ofthe SIP. The language should be revised to specify a test method for VOC, or else subsection IX.H.11.e should be revised to specify a test method for VOC and this subsection would then cross-reference it. 4) The RACT Summary Table indicates that LNB & FGR will be installed for NOx control at the Annealing Oven by 2017, and that thermal regenerative oxidation will be installed for VOC control at the Painting Operations by 2019. Please explain why earlier dates would not be achievable. 5) Draft SIP subsection IX.H.l3.d. indicates that a VOC limit for the thermal oxidizer controlling the painting operations shall be established in the Approval Order (AO) by no later than January 1, 2019. As we have noted in other instances, this approach is not approvable. RACT limits need to be specified in the SIP, not determined at a future date or specified in an AO. 6) The table provided to EPA on October 31, 2013 indicates that the emissions used for NAAQS attainment modeling were the 2008 actual emissions. The RACT Evaluation Report does not indicate what those emissions were for NOx and VOC (the pollutants emitted in greatest quantity from PSCIPCO). Please explain what the actual 2008 plantwide NOx and VOC emissions were, and what the allowed plantwide emissions are estimated to be after application ofRACT, on a daily basis. Our objective here is to see ifthere is a substantial difference between the proposed RACT allowable and the emissions used for modeling. bb) Payson City Power I) Page 2 ofthe RACT Evaluation Report indicates that 2008 actual NOx emissions, for all four IC engines combined, were 4.0 tons/year. From information elsewhere in the RACT Evaluation Report, it appears that this figure represents virtually all ofthe NOx emissions from Payson City Power in 2008. This figure is equivalent to average daily emissions of 0.011 tons. We expect that the projected actual emissions would be only slightly higher. The table provided to us on October 31, 2013 indicates that the emissions used for NAAQS attainment modeling were the projected actual emissions. Draft SIP subsection IX.H.13.e. indicates that the proposed RACT allowable for NOx is 1.54 tpd and 268 tons per rolling 12- month period, for all engines combined. Please explain how the projected actual emissions could be a valid basis for modeling, when the proposed allowable emissions are 140 times higher (1.54 tpd allowed versus 0.011 tpd actual)

. Please also explain how 1.54 tpd was calculated to be an appropriate RACT limit. No such explanation appears in the RACT Evaluation Report. 2) The current NSR permit for Payson City Power, dated September of 1996, contains performance-based NOx emission limits, in grams per kilowatt-hour, for each ofthe four engines. Limits are 4.96 grams per kW-hr at two engines, 7.60 grams per kW-hr at the third engine, and 8.76 grams per kW-hr at the fourth engine. Please explain why these limits were not included in draft SIP subsection IX

.H.l3.e. as part ofproposed RACT. 3) Pages 5 and 7 ofthe RACT Evaluation Report appear to be taking credit for VOC reductions that may result from the requirements of40 CFR 63 subpart ZZZZ, which will require the engines at Payson City Power to meet a CO emission limitation as a surrogate for HAP 43emissions. The Report lists the reductions as occurring on the basis that "it is likely" that Payson City Power will be required to install oxidation catalyst controls

. The RACT Summary Table projects a 1.4 tpy VOC reduction resulting from installation of oxidation catalyst by 2017. However, draft SIP subsection IX.H

. 13.e. does not include any proposed VOC allowable or requirement for VOC controls. IfPayson City Power is being credited with a VOC emission reduction, either due to installation ofnew controls , or due to new requirements applicable to existing controls, then this needs to be reflected in proposed RACT requirements in the SIP. 4) The RACT Summary Table indicates that oxidation catalyst for VOC control will be installed at the IC engines by 2017

. Please explain why an earlier date would not be achievable. 5) The draft SIP does not specify a requirement for stack testing or use ofCEMS

. It must do so. If stack testing will be used, the text should specify the method to be used (or cross-reference SIP subsection IX.H.ll.d), the initial test date, and the frequency oftesting

. Also, how will power production on a daily basis be determined? And what records must the owner /operator keep? 6) The draft SIP should specifically identify the number and types ofemitting units at Payson City Power, e.g. "Payson City Power has four dual-fuel internal combustion engines of size that are used to and have a generating capacity of " cc) Provo City Power 1) Page 2 ofthe RACT Evaluation Report indicates that 2008 actual NOx emissions, for all four IC engines combined, were 20.1 tons/year. From information elsewhere in the RACT Evaluation Report, it appears that this figure represents virtually all ofthe NOx emissions from Provo City Power in 2008

. This figure is equivalent to average daily emissions of0.055 tons
. We expect that the projected actual emissions would be only slightly higher. The table provided to us on October 31, 2013 indicates that the emissions used for NAAQS attainment modeling were the projected actual emissions. Draft SIP subsection IX.H.l3.f. indicates that the proposed RACT allowable for NOx is 2.45 tpd and 254 tons per rolling 12-month period for the overall plant. Please explain how the projected actual emissions could be a valid basis for modeling, when the proposed allowable emissions are at least 44 times higher (2.45 tpd allowed versus 0.055 tpd actual). Please also explain how 2.45 tpd was calculated to be an appropriate RACT limit. No such explanation appears in the RACT Evaluation Report. 2) The current NSR permit for Provo City Power, dated December of 2004, contains performance-based NOx emission limits, in grams per kilowatt-hour and ppmdv, for each of the boilers and engines. The limits are 1.46 grams per kW

-hr and 155 ppmdv at each oftwo boilers, and 10.4 gram, s per kW

-hr and 1,660 ppmdv at each offour engines. Please explain why these emission limits, covering the main emitting units at the facility , were not included as part ofRACT. 3) Pages 5 and 10 ofthe RACT Evaluation Report appear to be taking credit for VOC reductions at the four IC engines that may result from the requirements of40 CFR 63 subpart ZZZZ, which will require the engines at Provo City Power to meet a CO emission limitation 44as a surrogate for HAP emissions. The Report lists the reductions as occurring in 2017 as a result ofthe addition of oxidation catalyst controls. The RACT Summary Table projects a 1.4 tpy VOC reduction resulting from installation ofoxidation catalyst by 2017. However, draft SIP subsection IX.H.13 .f. does not include any proposed VOC allowable or requirement for VOC controls. IfProvo City Power is being credited with a VOC emission reduction, either due to installation ofnew controls, or due to new requirements applicable to existing controls, then this needs to be reflected in proposed RACT requirements in the SIP. 4) The RACT Summary Table indicates that oxidation catalyst for VOC control will be installed at the IC engines by 2017. Please explain why an earlier date would not be achievable. 5) Regarding compliance demonstration requirements: i) Stack testing is proposed to be required every 8,760 hours ofoperation and/or at least every five years. We are concerned with stack test frequencies longer than one year. Please explain why this test frequency is sufficient to ensure continuous compliance with the limits. ii) The text should specify the date for the initial stack test for each unit and the test method to be used (or cross-reference subsection IX.H.ll.d.). iii) Subsection IX.H.13.f.iii. should be clarified to say that stack testing is required every 8.760 hours of operation or every five years, whichever occurs sooner. iv) It is not clear how power production will be determined or how 12-month rolling totals ofpower production would be adequate to determine compliance with a daily limit. v) The SIP needs to specify what records the owner/operator must keep. vi) The draft SIP should specifically identify the number and types ofemitting units at Provo City Power, e.g. "Provo City Power has four dual-fuel internal combustion engines of

__ size that are used to and have a generating capacity of

____ , as well as two natural gas fired boilers of size that are used to

____ and have a generating capacity of " dd) Springville City Corporation- Whitehead Power Plant 1) Page 2 ofthe RACT Evaluation Report indicates that 2008 actual NOx emissions, for all seven IC engines combined, were 0.1 tons/year. From information elsewhere in the RACT Evaluation Report, it appears that this figure represents virtually all ofthe NOx emissions from the plant in 2008. This figure is equivalent to average daily emissions of0.00027 tons. We expect that the projected actual emissions would be only slightly higher. The table provided to us on October 31, 2013 indicates that the emissions used for NAAQS attainment modeling were the projected actual emissions. Draft SIP subsection IX.H.13.g. indicates that the proposed RACT allowable for NOx is 1.68 tpd and 248 tons per rolling 12-month period, for all engines combined. Please explain how the projected actual emissions could be a valid 45basis for modeling, when the proposed allowable emissions are approximately six thousand times higher (1.68 tpd allowed versus 0.00027 tpd actual). Please also explain how 1.68 tpd was calculated to be an appropriate RACT limit. No such explanation appears in the RACT Evaluation Report. 2) The current NSR permit, dated December of2003, contains performance-based NOx emission limits, in lb/hr and grams per kilowatt-hour for each of seven engines. Limits are 27.00 lb/hr and 2.50 grams per kW-hr at the four Enterprise engines, and 24.00 lb/hr and 4.90 grams per kW-hr at each ofthe three General Motors EMD engines. Please explain why these emission limits, covering the main emitting units at the facility , were not included as part ofRACT

. 3) Pages 4 and 10 ofthe RACT Evaluation Report appear to be taking credit for VOC reductions that may result from the requirements of40 CFR 63 subpart ZZZZ, which will require the engines at the Whitehead power plant to meet a CO emission limitation as a surrogate for HAP emissions. The Report lists the reductions as occurring on the basis that " it is likely" that the plant will be required to install oxidation catalyst controls. However, draft SIP subsection IX.H.13.g

. does not include any proposed VOC allowable or any proposed requirement for VOC controls

. Ifthe plant is being credited with a VOC emission reduction, either due to new controls, or due to new requirements applicable to existing controls , then this needs to be reflected in proposed RACT requirements for VOCs in the SIP. 4) The RACT Summary Table indicates that oxidation catalyst for VOC control will be installed at the IC engines by 2017. Please explain why an earlier date would not be achievable. 5) The draft SIP should specify the requirement for the owner /operator to operate and maintain CEMS and output meters for each engine, and state or cross-reference the relevant CEMS requirements. 6) The draft SIP should specifically identify the number and types ofemitting units at Springville City Power, e.g. "Springville City Power has seven dual-fuel internal combustion engines of

__ size that are used to and have a generating capacity of

_ __ _ as well as one natural gas fired boiler of size that is used to and has a generating capacity of , as well as one boiler fired on digester gas of stze that is used to and has a generating capacity of "

46ATTACHMENT 3 EPA Region 8 Comments on Modeling Technical Support Documents for Utah SIP Control Measures for Area and Point Sources, Fine Particulate Matter, for the Salt Lake and Utah Nonattainment Areas.
1) Pre-Baseline Emission Reduction Credits. Either the state must include any banked emission reduction credits in the projected inventory and model them as part ofthe attainment demonstration, or the applicable SIP rules must include definitive language stating that no pre-baseline emission reduction credits (a.k.a. banked emissions) may be used within the 2006 24-hour PM2.5 nonattainment areas to offset increases ofPM2.5, NOx, S02, or VOC from major stationary source construction or modification. Ifthe emission reduction credits will be added to the modeled emissions, a description ofthe emissions scenarios should specifically identify by species, location and layer any banked emissions. Also, it was indicated by the state that there is no intent to adopt a minor source offset rule for PM2.5 and its precursors within the 

### PMz

.s nonattainment areas. While we have indicated that our regulations contain no specific requirement for minor source offsets, we have also indicated that the SIP or SIP rules must specify an enforceable approach by which Utah will determine whether minor source construction or modifications will interfere with attainment or maintenance ofthe 

### PMz

.sNAAQS or the control strategy and will prohibit such construction or modification ifit would interfere with attainment or maintenance ofthe PM2.5NAAQS or the control strategy. We have suggested that the approach could consist ofa tracking system through which Utah compare actual minor source emissions growth to the attainment demonstration's projected minor source emissions growth. There may be other approaches as well. We are not suggesting that source-by-source modeling is required, although, ifUtah wishes, modeling could be required. It does not appear that the existing minor source NSR rules require any type ofimpact analysis or tracking for construction or modification in nonattainment areas. We recommend including in the modeling TSD a summary ofthe post-SMOKE modeled emissions for each year. This is a useful quality assurance product and is helpful in comparing and verifying that the emissions input to CMAQ are consistent with the raw emissions data that was input to the SMOKE emissions processing system. For example, plots ofdaily total emissions for each major emissions sources category and selected species could be included in the TSD. 2) SIP Narratives Section 5.6 and CMAQ Modeling, p. 4.d-22-23 and Appendix D. The SIP narrative and TSD for CMAQ indicate that the emission inventory factors for wood smoke were updated for the 2010 baseline inventory, which improved model performance for organic carbon (OC). OC fractions shown in figures 5.11, 5.12 and 5.13 ofthe Provo and Salt Lake City SIP narratives, for Hawthorne, Bountiful and Lindon model performance, are identical to the figures shown in 2012 for the Logan SIP, prior to the wood smoke updates. Are the figures in the 2013 public comment documents current? 3) The Provo SIP narrative for figures 5.11, 5.12 and 5.13 states (p. 36, 38):



### 47"At all 3 [Speciation Trends Network] STN sites, the percentage of simulated nitrate is over-predicted by 5 to 7%. The simulated ammonium percentage is nearly identical to the observed STN speciation. At the Hawthorne site, organic carbon looks to be underpredicted by CMAQ with a percentage ofPM2.5 at 12% and an observed organic carbon at 21%. This discrepancy in organic carbon is not apparent at the Bountiful and Lindon site. "

" Speciation and composition ofthe modeled PM2.5 matches the observed speciation quite well. Modeled and observed nitrate are between 40% and 50% ofthe PM2.5. Ammonium is between 15% and 20% for both modeled and observed PM2.5. Organic carbon is underestimated at the Hawthorne location, but is reasonably estimated at the other locations (Bountiful, Lindon) ." The speciation category " other" is not addressed in this discussion; at Hawthorne, monitored and modeled " other" agree at 15 and 14% , respectively, but at Bountiful, modeled " other" is only about**~** monitored (9% vs . 17% ) while at Lindon, the modeled " other" is 11 % ofthe mass on episode days over 25ug/m3

, while the monitor records fully 26% ofthe mass as
" other" on these days

. This is a significant fraction ofthe PM mass on high concentration days, and a significant underperformance ofthe model not discussed in the narrative or the TSD. Depending on the components represented by " other" it could represent unexplored opportunities for additional control strategies that could lead to more expeditious attainment. 4) The composition of " other" will depend on the method used to convert speciation data to simulated PM2.5 filter mass. At a minimum, " other" likely contains primary PM2.5 crustal emissions ; one way " other" could be too low from the model, would be to have a significant shortfall in primary PM2.5 emissions in the inventory. Breakdown ofthe composition of

" other" as was done in figure 3.2, for both the speciation data and the model output, would help to clarify the nature ofthe shortfall. In addition, a description and data on the mass reconstruction calculation in either the CMAQ or Weight ofEvidence TSD sections would help to allow an assessment ofthe model-to-monitor comparison. 5) To assess whether the " other" in Lindon' s pie graph was dominated by crustal, the EPA extracted elemental speciation data for several likely " other" components for winter days above 25ug/m3 for 2008-2013 at Lindon, Hawthorne and Bountiful. Peak elemental mass fractions were for chlorine, potassium and iron, rather than silicon which is usually expected to be the largest contributor by mass for crustal samples. This was true for all three speciation samplers. Potassium was the third largest contributing element by mass fraction , although potassium is often not included in the calculation offilter mass reconstruction algorithms. It is not known whether UDAQ used potassium in the reconstruction algorithm used to derive Figures 5.11-13

. Derivation information is requested to complete our review.

484.5 %

4

.0%

3

.5%

3

.0%

2.5%

2

.0%

1 1.5 %

1.0%

0.5 % Top 3 Contributor Comparison



### . / \./

..... 

# / ,.· I ./ I

I 

## /

- ProvoCI %

- Provo Fe% 

## ••

- ProvoK%

- ProvoK+ %

- · SLCCI % -41 • SLCFe% -41 • SLCK%

..... • SLCK+%

..... BountCI %

• • -·• Bount Fe % 

## •

.. ... BountK%

........ BountK+%



### I 0

.0% I 2007 2008 2009 2010 2011 2012 2013 2014 6) Speciation data from 2009 and 2010 episodes was used in generating Figures 5.11-13; Figure 5.11 for Hawthorne shows good agreement for "other" between the monitor and model. The figure above shows very marked differences, year to year, in chlorine contribution to 

### PM2.s mass on high 

### PM2.5 days. In most mass reconstruction algorithms, chlorine is assumed to be contained in sea salt particles; since ions in sea water are 55% chlorine by mass, chlorine mass is converted to sea salt mass by multiplying by 1.8 (1 /55%). Chlorine also composes approximately 55% ofthe ion mass in the Great Salt Lake, so ifthe chlorine in the Wasatch

· Front speciated 

### PM2.5 is assumed to be in salt particles derived from evaporation of Great Salt Lake droplets, multiplication by 1.8 would also be appropriate. This would imply that in 2013 , with chlorine content on high 

### PM2.5 days at Hawthorne reaching 4.18%, assumed sea/lake salt particle mass reached 7.5% oftotal 

### PM2.s mass. This variation year-to-year in a single component of " other" might suggest that the agreement between the model and monitored data in 2009 and 2010 at Hawthorne but not at Bountiful or Lindon may be more random chance than an indication that the model is replicating the actual filter chemistry for the speciation components of" other". A trend analysis of SIN " other" at the speciation sites within the weight ofevidence section might be valuable to identify, evaluate, and potentially recommend or rule out alternative control strategies that could lead to more expeditious attainment dates. 7) While most mass reconstruction algorithms assume chlorine will be in the form of sea salt on speciation filters, most speciation data for high chlorine loaded filters over 25ug/m3 at Hawthorne do not seem to support this assumption. Second high ion content in both sea water and the Great Salt Lake would be sodium at 30.8% by mass in sea water and 32.8% in Great Salt Lake water. Ifchlorine is primarily on speciation filters as salt particles from the 49lake, then the chlorine to sodium ratio should be approximately 54.55/32

.8 or 1.66 (by mass). Ifthe chlorine to sodium ratio is much larger than 1.66, chlorine would appear to be in some form other than salt (either in minerals as a portion ofcrustal or presumably as ammonium chloride as a secondary aerosol product ofgaseous chlorine or hydrochloric acid chemistry in the atmosphere). Examination ofchlorine to sodium ratios on high PM2.5 speciation sampling days in 2008-2012 shows chlorine to sodium ratios generally range from 12 to 100 or more, suggesting a robust secondary chlorine aerosol chemistry is present. This would make the assumptions of sea salt composition inappropriate for mass reconstruction, and also point to a secondary aerosol pathway not currently captured in modeling. Weight ofevidence evaluation ofchlorine speciation data would be helpful in understanding model shortcomings and mismatches (ifany) between speciation reconstruction assumptions and modeled

" other". 8) It would be helpful in assessing issues like that above, and projected model and SIP performance, ifthe CMAQ TSD included breakdowns of speciated relative response factor (RRF) by location for each ofthe future projections (2014, 2017 , and 2019). This would show which portions ofthe PM2.5 aerosol are moving toward attainment under the SIP controls expeditiously, and which are decreasing more slowly (or growing) under the SIP control measures. 9) For the SIP narrative Table 3.2, the 3-year design values are shown in whole numbers , rounded in accordance with 40 CFR Part 50, Appendix N rounding rules , but the baseline design values shown cannot be derived by averaging the design values shown. Instead, Region 8 ' s understanding ofthe MATS calculation is that the baseline design values shown are derived by averaging 3-year averages of98 1h percentile values, truncating to the right of the 0.1 ug/m3 decimal place, averaging the truncated three 3-year averages in a 5-year design value period, then again truncating to the right ofthe 0.1 ug/m3 decimal place. A note to this effect, or showing the decimal values in the table would make the table more understandable. 1

0) MATS TSD, 4

.d-3

. " Spatial interpolation options, " blank mass" amount and boundaries used OC mass estimation are left set at MATS default values (please see MATS documentation). " Presumably this should have read " and boundaries used for the OC mass estimation" ? The reference to the MATS documentation with a citation, such as Sec. 7

. 1

.2.2, p. 172 for the OC mass estimation defaults , would help our review and the public ' s review

. 11) Weight ofEvidence, Trends in Exceedance Days, p. 4.3-8 & 9. It is not clear whether the data shown in Figure 1.1 is exceedance days for all ofthe Salt Lake nonattainment area. For example, in 2000, the chart shows about 14 exceedance days, while the Air Quality System (AQS) database shows 22 separate exceedance daysjust considering the monitors in Salt Lake County. Given that, the conclusion "The number ofPMz.s exceedances between 1999 and 2012 has decreased by approximately 31% in the Salt Lake non-attainment area" is not well supported

. Is this based on a rolling average over some period oftime, the slope ofthe

. linear regression, or some other method? The conclusion should be qualified, given that the number ofmonitors operating and their sampling frequencies have changed over time. This is particularly pronounced in Logan, where in 2002 the monitor recorded 11 exceedances between January 8 and February 22 on a one day in 3 schedule, before moving to a daily schedule May 14 ofthat year; therefore measured exceedances in 2000-2002 in Logan could be approximately 113 ofthe number ofdays which actually had 

### PM z.s above the NAAQS. 50This makes the quoted decrease statistics in numbers ofexceedance days unreliable, or difficult to interpret accurately. There needs to be further discussion on the derivation ofthe data presented, since there is such a large discrepancy between what is stated in the SIP and what is in AQS. 12) Section 1.1 trends vs. Section 1.2 trends. Where section 1.1 cited trends in exceedance days based on 1999-2012 data (2001-2012 for Logan), 1.2 shows data through the first halfof 2013. Section 1.1 did not include this 2013 exceedance day data, but, ifincluded, only Salt Lake City would then have a downward trend in exceedance days since the start of monitoring; the long term trend for Utah County is essentially flat, while the long term trend for Logan (without correcting for the monitoring frequency change in 2002) is upward. Long Term Trends, Numbers of Exceedance Days, Utah PM2.5 NonattainmentAreas
45**~----~----~------,------,------.-----~-----.------,**

-- Logan**Salt** Lake City Provo

- Linear (Logan)

- Linear (Salt Lake City)

- Linear (Provo)

## 1S**;t ~~** **~t=~== \\t~** **~~f?;r\ t_** **88x-404 87** 

0

# 1998 2000 2002 2004 2006 2008 2010 2012 2014
13) 1.2.3 Meteorology, p. 4.e-20-21: "Although 2012's snow depth was nearly halfthe average and temperatures were 1.5°F warmer, 2012's snow depth and surface temperatures were not as extreme as 2013 and therefore should be included in the baseline design value period." This is a matter ofopinion without much technical support. For example, various baseline design value periods could be evaluated for their degree ofdeviation from long term temperature and snow depth means; considering the 2007-2011,2008-2012 and 2009-2013 baseline periods, 2009-2013 is nearest the means for Salt Lake County, while 2008-2012 is nearer the means for Utah County. Technical support could be quantified and should be provided for review so that the selection ofbaseline period looks less arbitrary. Salt Lake County Snow Depth Utah County Snow Depth 51Long Term Avg

. 2.7 30

.8 Long Term Avg

. 1.74 28.6 2007-2011 2.754 29.66 2007-2011 1.938 25.92 2008-2012 2.512 30.4 2008-2012 1.72 26.68 2009-2013 2.768 30.48 2009-2013 2.16 26.12 Deviation from Mean Green: Most Typical ; Red least Deviation from Mean 2007-2011 0.054 -1.14 2007-2011

-7.72867 25.92 2008-2012 -0.188 -0

.4 2008-2012 -7.94667 26.68 2009-2013 0

.068 -0.32 2009-2013 -7 .50667 26.1 2 14) Meteorology, p. 21. "The NWS launches a weather balloon twice a day, one at 12 Zulu ( 12Z) and one at 00 Zulu (OOZ). Only data from the morning sounding (12Z) (which is launched at 5 or 6 AM local time depending on whether it is Daylight Savings Time) was used." Note that the guidance for the National Weather Service (NWS) upper air sounding programs . directs that the balloons be launched as close to 1-hour earlier than the scheduled time as possible, in order to have the balloon reach the stratosphere at approximately 12Z; therefore Salt Lake City launch time is actually 12Z-8 hours, rather than 12Z

- 7 hours, or 4 or 5 AM. See http ://www.nws .noaa.gov/directives/sym/pd01014001curr.pdf : "Actual release times for the 00 and 12 UTC standard scheduled upper air observations should be as close as possible to H-60 minutes, where His one ofthe standard times." 15) Inversion Strength, p. 4.e-23. Inversion Strength is the difference in temperature at 2134 meters minus temperature at 1289 meters; as a temperature difference, conversion to degrees F is simply multiplication by 9°F/5°C, not multiplication by 9/5 

### + 32°F. Therefore converting inversion strengths of 5°C to 10°C to °F gives 9 to 18°F, not the 41 to 50°F shown. The 25°C strongest inversion in 15 years was 45 °F, not the 77 °F stated. 16)Page 4.e-22&23. The assessment ofinversion strength in 2012 versus 2013 is somewhat qualitative and therefore a matter ofopinion; the data could be assessed quantitatively. Seasonal inversion strength-day units could be calculated, or, for example, both 2013 and 2010 show 32 days with inversions

. Looking at the entire 1999-2013 data set, rather thanjust 2008-2013 would allow a more objective analysis ofthe degree to which 2013 is, or is not, an outlier compared to a greater sample size. 17) Page. 4.e-23. "Year 2013 exhibited extreme inversion periods, while 2012's inversions were more typical in terms of strength". Some objective quantitative comparisons ofthe two years with the long term means would validate this statement. 18) Unmonitored Area Analysis, p. 4.3-45. "We then compare the FDV at each grid-cell to the NAAQS**(35~g/m )."**  The highest scale level shown on Figure 1.25, p. 4.e-48 is 35.5 to 39.0; should the text actually state"

... at each grid-cell to the NAAQS**(35.4~g/m )"?**  19) Figure 1.25, p. 4.e-48. The description ofthe figure indicates that only one grid cell,just NE ofthe Kennecott Bingham Canyon mine, shows a 2019 unmonitored modeled violation. From the color scale, however, it appears that 2 grid cells in Box Elder County, probably at the ATK location, could also be the 35.5 to 39ug/m3 color. Perhaps peak modeled concentration in each county could be tabulated?

5220) Section 1.8. Could more clarification be provided on how MATS is treating the non-winter days ofTable 1.11 and 1.12? Are any RRFs for any species applied to these data by MATS (other than an RRF of 1.0)? Ifso, which species have RRFs different from 1.0, and what speciation profiles are used for the non-winter days? IfRRF outside winter months are all 1.0, please add that for clarity.



### 53ATTACHMENT 4 EPA Region 8 Comments on Mobile Sources, Transportation Conformity, Related Contingency Measures, and 1/M. Mobile Sources and Transportation Conformity I) Mobile Sources Comments on the Salt Lake Section ofthe SIP Narrative : Salt Lake Section; Control Measures for Area and Point Sources, Fine Particulate Matter, PM2

.s SIP for the Salt Lake City, UT Nonattainrnent Area Section IX. Part A.21 a) Issue 1 On-road mobile sources; the SIP Narrative states the following on page 58:

" A decentralized, test-and-repair program was evaluated for Box Elder and Tooele counties within the nonattainrnent area. For the evaluation, all model year 1968 and newer vehicles would be subject to a biennial test except for exempt vehicles. The program would exempt vehicles less than four years old as ofJanuary 1 on any given year from an emissions inspection. Year 1996 and newer vehicles would be subject to an On

-Board Diagnostics (OBD) inspection. Year 1995 and older vehicles would be subject to a two-speed idle inspection (TSI). Based on this evaluation, this program was not included because it was determined that implementation ofsuch a program would not affect PM2
.5 concentrations at the controlling monitor (Hawthorne) for the Salt Lake

-Ogden-Clearfield nonattainrnent area. " Additional information is provided in the Technical Support Document. " There would have been emission reductions ofNOxand VOCs identified with the state' s evaluation. Taken only by themselves, these I /M emission reductions may not have shown a modeled difference at the Hawthorne monitor. However, such an I /M program would likely produce viable PM2
.5 precursor emission reductions ofNOxand VOCs for the Salt Lake-OdgenClearfield nonattainrnent area. UDAQ has not provided the EPA with their evaluation, and it would be helpful in our review to see UDAQ ' s analysis, with the estimated potential emission reductions from an I /M program, to further understand the state' s conclusion. We note that Section 5

.e ofthe TSD (" Control Strategies, On-Road Mobile Sources" ) only provides the following additional paragraph regarding this question :

"UDAQ also tested the inclusion ofthe above liM programs in both Box Elder and Tooele counties within the Salt Lake nonattainrnent area. However, photochemistry model sensitivity runs revealed that the effect ofthese controls on PM2

.s concentrations at the controlling air monitor located at Hawthorne Elementary School (1675 South 600 East in Salt Lake City, Utah at an elevation of 1306 m or 4285 ft) was negligible. Therefore, the effectiveness ofan liM program was not included in the modeling in either ofthese counties

. However, liM programs already exist in Salt Lake, Davis, Utah, and Weber counties and are reflected in the inventories. " b) Issue 2 On

-road mobile sources ; the SIP Narrative states the following on page 59:

"The plans and programs produced by the transportation planning process ofthe [Wasatch Front Regional Council] WFRC are required to conform to the on-road mobile source emissions budgets established in the SIP. Approval ofconformity is determined by the FHWA and FTA. "

54To be accurate, the EPA notes the last sentence should be revised to read as follows: " Approval ofconformity is determined by the FHW A and FTA after receipt ofconcurrence on the conformity determination by EPA. " c) Issue 3 On-road mobile sources; SIP Narrative, WFRC Transportation Conformity Budgets, on page 62: There may be discrepancies between the Vehicle Miles Traveled (VMT) data developed by the Metropolitan Planning Organization (MPO) , the Wasatch Front Regional Council (WFRC), for use in the SIP and those VMT data used in the latest (August 22, 2013) conformity determination performed by the WFRC. This potential issue ofinconsistent data for VMT would have impacts on the MOVES modeling performed by the UDAQ to develop mobile sources emissions estimates for inventory data tables , the dispersion modeling, and for defining the respective nonattainment area Motor Vehicle Emissions Budgets (MVEBs)

. To illustrate this concern the EPA compared the MVEB emissions data for direct PM2.s, NOx, and VOCs contained in the SIP narrative Table 7.1 to the mobile source emissions data from the conformity determination, dated August 22, 2013 (specifically Tables 12a and 12b), as provided in the WFRC ' s Air Quality Memorandum Report No. 29 (dated August 22, 2013):

Mobile Sources Emissions MVEBs From SIP Table 7.1 (page 62); all in Tons Per Day Year PM2

.s NOx 

## voc 2014 5.01 80.00 47.50 2017 4.55 66.98 40.11 2019 3.71 51.68 30.55

Mobile Sources Emissions From WFRC Tables 12a & 12b; all in Tons Per Day Year PM2.s NOx 

## voc 2015 7.11 66.52 N/A* 2020 6.77 47.90 N/A *Not Available. Noted discrepancies;**PM~** Emissions: 1) Clarification is needed from UDAQ (and WFRC) as to why the mobile sources direct PM2.s emissions for 2015 (WFRC) would be 2

. 1 tpd more than the SIP ' s 2014 (UDAQ) figure. We further note that the 2019 (UDAQ) PM2.5 emissions of 3.71 tpd are significantly lower than the 2020 (WFRC) emissions of6.77 tpd. In addition, we note that the WFRC August 22, 2013 conformity determination did not include re-entrained road dust emissions

. Noted discrepancies; NOx Emissions: 1) Clarification is needed from UDAQ (and WFRC) as to why the mobile sources NOx emissions would be 80.00 tpd in 2014 (UDAQ) , but only 66.52 (WFRC) tpd for 2015 for the same nonattainment area. We note the SIP narrative shows the decline to a figure of66

.98 tpd would not occur until 201 7. 2) Clarification is needed from UDAQ (and WFRC) as to why the mobile sources NOx emissions would be 51.68 tpd in 2019 (UDAQ) , but 47.90 (WFRC) tpd for 2020 for the same
55nonattainment area. The SIP narrative shows a decrease of28.32 tpd ofNOxfrom 2014 to 2019 , but the WFRC only shows a decrease of 18.62 tpd ofNOxfrom 2015 to 2020

. The state needs to provide the specific VMT data (or point to the data' s exact location in the TSD) that were used for the mobile sources emissions estimates for the SIP-identified MVEBs for 2014, 2017 , and 2019 for the Salt Lake PM2
.5 nonattainment area (also refer to the EPA comment A.4 below). In addition, the state needs to provide clarification regarding the abovenoted potential inconsistencies. The EPA will use the state' s VMT data to compare to those VMT data used by the WFRC in its conformity determination ofAugust 22, 2013. Consistent, accurate VMT data and subsequent mobile sources emission calculations are a requirement for both the PM2

.s nonattainment SIP and any conformity determinations performed by the WFRC with respect to the SIP' s MVEBs. d) Issue 4 Overall Comments on VMT Data: TSD Section 3.e.iii "Technical Support Document for OnRoad Mobile Sources : PM2

.s Emissions Inventory for PM2
.5 SIP 2010 Baseline Year and Projection Years 2014, 2017 , and 2019 " The state needs to provide the specific VMT data that were used for the mobile sources emissions estimates for 2014, 2017 , and 2019 for the Salt Lake PM2
.5 nonattainment area. There may be potential discrepancies between the VMT data developed by the WFRC which was then used in the EPA' s MOVES2010a model to develop mobile sources emissions estimates for SIP inventory data tables , the dispersion modeling, and for defining the respective nonattainment areaMVEBs. The EPA considered the following information regarding VMT that was readily available in TSD Section 3

.e.iii (and welcome further direction from UDAQ to additional available data) ; the table on page 3.e.iii-3 " 2010 Winter Weekday Emissions", the table on page 3.e.iii-4 " 2014 Winter Weekday Emissions", the table on page 3.e.iii-5 " 2017 Winter Weekday Emissions", and the table on page 3.e.iii-6 " 2019 Winter Weekday Emissions". We considered the data under the heading "Distance" as being the whole-county sum total ofVMT for each county listed. We extracted the "Distance" data for Box Elder, Davis, Salt Lake, Tooele, and Weber counties and inserted those data in the table below: 

### EPA Table A-1: Daily VMT ("Distance" County 2010 2014 2017 2019 Box Elder 2,603 ,591 2,918 , 146 2,988 , 107 2,841 ,624 Davis 7,561 ,284 9,387 ,728 9,773 ,674 9,391 ,628 Salt Lake 25 ,349,568 31 ,743 ,818 33 , 152,583 31 ,922,3 24

Tooele 2,474,433 3,555 , 173 3,853 ,553 3,794,593 Weber 4,622,292 5,913 , 152 6, 196,599 5,979, 191 

### EPA Comment: Inconsistent VMT figures. From the county-by-county VMT data extracted from Section 3.e.iii ofthe TSD, there is a predicted growth, as would be anticipated, in VMT from 2010 to 2014 and to 2017 for all five counties

. However, for 2019 , all five counties ' VMT are then estimated to be 

## he!ow their 20 1 7 levels. Also, for 2019, Davis County and Weber County VMT are almost the same as their respective 2014 VMT levels, and Box Elder County is
56estimated to be less than its 2014 level. The above identified VMT inconsistencies need to be explained by the state. For an additional comparison, the EPA consulted the WFRC ' s transportation conformity "Air Quality Memorandum, Report 29, Conformity Analysis for the WFRC Amended 2040 Regional Transportation Plan" dated August 22, 2013 and found at: http://www.wfrc.org/air gualitv/AQ%20memo29 RTP2040 FINAL.pdf We looked at Tables 11a and 11 b for projected VMT figures for seasonal VMT for 2015 and 2020 for Salt Lake County only (Note: We reviewed the seasonal VMT from the PM 10 conformity determination for Salt Lake County, which was available, as it should be the same or very similar to the seasonal VMT for PM2
.5 as both are whole county and winter time seasons). The VMT appear to be inconsistent between the SIP TSD and the WFRC. For the Salt Lake County only comparison, it appears that the PM2

.s TSD daily VMT for 2014 are 31 ,743 ,818. However, from the WFRC conformity determination, Report 29, the 2015 daily VMT are only 28 ,969,518

. Typically, we would expect to see the 2014 figure to be smaller and then the 2015 figure to be larger to account for projected growth. We also note that between the SIP TSD 2019 VMT and the 2020 WFRC conformity determination Report 29 VMT, the VMT essentially show minimal growth between those two years (2019 TSD VMT 31 ,922,324 and 2020 WFRC conformity determination shows 31 ,957 ,83 7)

. As an additional comparison ofprojected VMT growth, we considered the total county data for Utah County (which includes the Provo PM2
.5 nonattainment area). Utah County data from the above noted tables in TSD Section 3

.e.iii show the following anticipated trend in growth for VMT :

2019 16,740,301 Finally, the EPA requests that UDAQ provide the specific VMT for the Salt Lake nonattainment area only for each ofthe five counties and for 2010, 2014, 2017 and 2019

. Once this information is provided, we will compare the total nonattainment area VMT for those years to the total nonattainment area VMT that were used 

### in WFRC ' s Report 29 in Tables 12a and 12b for 2015 and 2020

. This comparison is important as it should reflect the VMT that were used to calculate the mobile source emissions that led to the derivation ofthe MVEBs contained in Table 7.1 on SIP narrative page 62, the same MVEBs to which WFRC will need to demonstrate conformity

. e) Issue 5 EPA concerns with the proposed amendments to "Salt Lake County Health Department, Health Regulation #22 -Vehicle Emissions Control Program" as proposed for public comment by Salt Lake County (see: http://www.slcohealth.org/envRegs/proposedRegs

.html) EPA Comment: The EPA submitted comments on the proposed amendments to " Salt Lake County Health Department, Health Regulation #22

- Vehicle Emissions Control Program" on November 20, 2013. In our comments we identified a number ofareas ofconcern with the provisions in the proposed regulation and with Appendix A ofthe regulation. We note that 57emission reductions credit from the County ' s motor vehicle inspection and maintenance regulation were used in the modeling inventories for 2014, 2017 and 2019. Therefore, ifthe County does not address our concerns in its final, adopted version ofcounty Regulation #22, we may be unable to approve the amended regulation, and this would affect the approvability ofthe SIP as a whole. II) Comments on the Utah County Section ofthe SIP Narrative: Utah County: Control Measures for Area and Point Sources, Fine Particulate Matter, PM2

.s SIP for the Provo, UT Nonattainrnent Area. a) Issue 1

"The plans and programs produced by the transportation planning process ofthe MAG are required to conform to the on-road mobile source emissions budgets established in the SIP

. Approval ofconformity is determined by the FHW A and FT A." To be accurate, the EPA notes the last sentence should be revised to read as follows: " Approval ofconformity is determined by the FHWA and FTA after receipt ofconcurrence on the conformity determination by EPA. " b) Issue 2 

### Potential inconsistent VMT figures. The TSD Section 3.e.iii presents whole county VMT for Utah County ; we have extracted those data and they appear in the table below: 

### EPA Table B- 1: Daily VMT (" Distance") County 20 10 2014 201 7 2019

Utah 10,620,608 13 ,991 ,478 15 ,581 ,282 16,740,301 The only readily available means we have to evaluate these whole county VMT was to compare the VMT data to those provided in the most recent (20 11) Mountainland Association of Government's (MAG) transportation conformity data from the " Conformity Determination Report, Mountainland MPO , 2040 Metropolitan Transportation Plan" dated May, 2011 and found at: http://www.mountainland.org/site/downloads/planning/Transportation Plans/20 11 Metropolitan

Transportation Plan/Document/ Air Quality Conformity Determination.pdf Relevant VMT data from the table entitled "Utah County Regional Travel Model Characteristics" show that county VMT for 

### 2009 were 9,998 ,092 and for 

### 2020, 14,670,890

. While the 2009 MAG conformity determination VMT data correlate well with the SIP' s TSD Section 3

.e.iii VMT data for 2010, there is a disparity between the SIP' s Section 3.e

.iii Utah County-wide VMT of 16,740,301 for 2019 and MAG' s 2020 VMT figure of 14,670,890. The EPA would appreciate a discussion from UDAQ regarding these VMT differences

. In addition, the EPA requests that UDAQ provide the specific VMT for the Provo PM2.5 nonattainrnent area only, for 2014, 2017 , and 2019, that were used by UDAQ to estimate the emissions for the MVEBs contained in Table 7.1 on page 61 ofthe Provo SIP narrative

. This VMT information is important as it should reflect the VMT that were used to calculate the mobile source emissions that led to the derivation ofthe MVEBs and will be instrumental in our evaluation offuture PM2 .5 conformity determinations that are prepared by MAG. 58c) Issue 3 Derivation ofthe Provo PM2.5 SIP's MVEB trading ratios. The EPA requests a further discussion ofhow the MVEB trading ratios were developed for the Provo PM2
.5 nonattainment area. These ratios are discussed in the full paragraph on page 62 of the Provo SIP narrative and on pages 4.e.-58 and 59 ofthe Weight ofEvidence section (section 4.e.) ofthe TSD. The trading ratios for NOx:PM2.s of 11.26:1 and VOC:PM2
.5 of6.33:1 are significantly different than previously reported ratios. Typically, a higher ratio would be expected for VOC than for NOx. Please provide additional information on how these ratios were derived. III) TSD Comment: TSD Section 5.e., page 5.e.-1: Clarification: The state notes under the "On-Road Mobile Sources" RACM analysis that "Federal Controls (Tier II & III)" apply. To clarify, at this point in time only Tier I and Tier II apply as the EPA has not yet promulgated, by a final rule, the onroad vehicle and fuels Tier III requirements.

59ATTACHMENT 5 EPA Region 8 Comments on Emission Inventories and Area Source Rules. I) Reasonable Further Progress, Emission Inventory, and Smoke Model Comments a) Reasonable Further Progress (RFP) In the EPA's letter to UDAQ dated November 1, 2012, we pointed out that the state's draft SIP RFP plan fell short ofconstituting an approvable plan. The draft plan showed that the identified control measures did not indicate a linear progress toward attainment. The RFP columns showed what the tons per day emission value should be in order to show linear progression towards attainment. Linear progress was delayed until the later years of SIP implementation for all emissions other than VOC, as well as for projected ambient PM2

.s concentrations. In order to show linear progress, the EPA emphasized that the RFP plan would need to have additional emission reductions by both 2014 and 201 7. 

## Salt Lake Cit RFP 350



# - PM2.5 Pro 300

- Nox NOx Pro 

# - 250

- so2 io 200 

# - 502 Pro Cll >

- voc 

# - "' c:**~** 150 

# - VOC Pro

- Precursors 100 

# - Precur Pro

- Total 

### so 

# - Total Pro

02008 2010 2012 Year 2014 2016 2018 Figure 6

. 1 RFP for the Salt Lake City area. Dashed line shows the state ' s projected progress toward lowering emissions in order to reach attainment. In the state' s revised Salt Lake City PM2
.5 SIP Section IX. Part A.21 , Area and Point Source Control Measures, new projections are provided. These projections are developed using annual emissions from the year 2010 instead ofthe original baseline year of2008 and projected emissions totals from dispersion modeling in the attainment demonstration results for the interim years of20 14 and 20 17. Attainment ofthe PM2.s standard is reached in 2019. For the milestone years of2014 and 2017, the values representing straight linear progress are shown in Figure 6.1 as a solid line for five pollutants considered in the SIP. Modeled projections for the pollutants are shown as dashed lines. Emissions are held constant by the state for direct 60PM2.5 (not shown in Figure 6

. 1) and 

### SOz. Figure 6.1 shows a near linear progression in the decrease ofemissions for the interim years for NOx and VOC pollutants. The EPA had stated in our November 1, 2012 letter that in the draft Salt Lake City SIP linear progress is delayed until the later years of SIP. In order to show linear progress, the RFP plan would need to have additional emission reductions by both 2014 and 2017.



## ... 10 Cll 80
70
60


### so**~** 40 

### "' c:**~** 30
20
10

0 

## -....



# .......

2008 2010 2012 

## Provo RFP

- PM2.5 Pro**~** - Nox**~** - NOx Pro 

### .__., oti:

- so2

- so2Pro



### - voc



# -- - VOCPro



# -
- Precursors

- Precur Pro

- Total


# - - - - Total Pro 2014 2016 2018 Year Figure 6

.2 RFP for the Provo area. Dashed line shows the state's projected progress toward lowering emiss ions in order to reach attainment. Figure 6.2 shows a similar decease in emissions in the interim years as had been demonstrated for the Salt Lake City. Both demonstrations satisfy the point the EPA made in its letter that a linear decrease in emissions is needed. b) Emission Inventory Requirements In our November 1, 2012 letter to the state we said that "The state needs to show that point source emissions for the baseline year are representative ofwhat is expected for emissions emitted in the Salt Lake and Utah (Provo) nonattainment areas. (EI Guidance sec. 3.3.2). In correspondence with the EPA, the state agreed to provide sensitivity analyses to determine that emissions in 2008 represent an average emission year, but to date these analyses have not been provided to the EPA. These sensitivity analyses will determine whether the recent economic recession caused fewer emissions to be released during

.2008 because the demand for products and services was less. " Our review ofthe most recent drafts ofthe Salt Lake City and Provo SIPs shows that this analysis has not been done. Although the state chose to use 2010 rather than 2008 as its baseline year, sensitivity analyses are still needed. During 2010 the economic recession had matured to the point that the economy was improving but the downturn was still apparent and any decrease in emissions lowering the baseline concentration may still be attributed to an economy affected by the recession. 61An analysis of2010 emissions is also warranted because the state used projections from the 2008 triennial inventory to develop the 2010 inventory. An analysis should be done to determine ifthe projected emissions were consistent with actual emissions that occurred in 2010. c) Smoke Model Output We have asked the state on numerous occasions to provide an output ofthe SMOKE model for the episodic days modeled. The EPAjust received the information and we have not as yet, reviewed the data. Our review ofthe technical support document prior to receiving the SMOKE data and the state's air quality web site has shown daily emission amounts for categories rather than individual sources. The state provides a daily emission rate by category, i.e. point, area, road and non-road sources but does not provide point source inventories showing each source ' s daily emissions

. We will compare the emission inventory we recently received for consistency within the larger emission inventory in the SIP and with emissions limitations indicated in the SIP. II) Area Source Comments a) General (applicable to all): 1) While Control Technologies Guidelines (CTG) , Alternative Control Techniques documents (ACTs) , other EPA source documents, and other states rules are often appropriately referenced for RACT, there is little discussion on what was evaluated and then used in the Utah rules/requirements. More detail is needed on the evaluations ofthe rules and which were used for each rule. 2) In its TSD, UDAQ frequently refers to the " 186 Compliance Advisories" over the past 4 years. Are the advisories a subset ofthe total number ofinspections, or a separate category? It would appear that the 186 advisories cover inspections for all types offacilities. Therefore, when only one advisory is negative for a type offacility, it could still be significant ifonly two others facilities

- from that facility type were inspected. Further information is needed on Compliance Advisories. This is applicable to the rule effectiveness (RE) analysis for the area source rules within the SIP and will help with our evaluation. 3) The state references Attachment 2 : Non-Point Source Rule Effectiveness Ranges, Emissions Inventory Guidance for Implementation ofOzone and Particulate Matter National Ambient Air Quality Standards and Regional Haze Regulations , EPA 12/2005 as the basis for its RE evaluation. While this is evidenced in the state's evaluation, it would strengthen the evaluation to directly reference the applicable "most important", "other important" and

" other factors " listed in the reference document. 4) R307-307

- Road Salting and Sanding: No RE or RACM analysis was done. 5) R307-312

- Aggregate Processing Operations: We were not able to find the referenced RACM analysis or spreadsheet in the TSD for this rule. 6) R307-345

- Fabric and Vinyl Coatings: 62In the RACM analysis, EPA CTG 450/2-77-008- "Surface Coating ofCans, Coils, Paper, Fabrics, Automobiles and Light-Duty Trucks," is referenced as providing presumptive RACM. However, a 1977 CTG is arguably out ofdate and no longer presumptive RACM. An analysis ofcurrent controls that are being used nationally is needed to evaluate ifthe 1977 CTG can still be used as RACM or ifa more current control should be used for RACM. Other sources (The South Coast Air Quality Management District rule 1128 and the San Joaquin Valley Air Pollution Control District rule 4607) were referenced as having also been evaluated for RACM. However, no details ofthe analysis ofthese rules are provided. The details ofthe analysis need to be included to complete a RACM analysis for this rule. 7) R307-350- Miscellaneous Metal Parts and Products Coatings: Missing RACM Analysis with individual rule (page Sb-140). Appears to have been placed at end ofRACM analysis for R307-354 (page Sb-189). See comments for that rule below. 8) R307-353- Plastic Parts Coatings: REanalysis for this rule is somewhat weaker than the other rules reviewed. We were not able to fmd the referenced RACM analysis or spreadsheet in the TSD for this rule. Please include this information in the TSD for the plastic parts coating section as you have in other area source rules in the TSD. 9) R307-354- Automotive Refinishing: An example ofa category with one violation out of 186 Compliance Advisories, but out of how many inspections specific to the category? See General Comment (a)(2) above for explanation. After the RACM analysis for this rule, a second RACM analysis is presented that appears meant for rule R307-350- Miscellaneous Metal Parts and Products Coatings. See comment for that rule above.

63