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

DearMr. Bird: 1595 Wynkoop Street DENVER, CO 80202-1129 Phone 800-227-8917 http://www.epa.gov/region08



# NOV 012012

RE: EPA Region 8 Comments on Utah's draft PM2.5 State ImplementationPlan, Technical Support Document, and area source and other rules

Thank you for the opportunityto provide comments onthe State ofUtah's draft PM2.5 State ImplementationPlan (SIP) for the Salt Lake City, Provo and Logan areas and the technical support document (TSD), which were approved for public comment by the Utah Air Quality Board on September 5, 2012. Additionally, we are providing comments onthe proposed rules that will apply inthe PM2.5 nonattainment areas. Our comments, which are detailed inthe six enclosures to this letter, should be considered preliminary. The Division ofAir Quality (DAQ) has expressed to us directly and at the Air Quality Boardmeeting on September 5, 2012, that they are continuing to develop the draft PM2.5 SIP and that substantial additional work will be done before the PM2.5 SIP is formally submitted to EPA. Thus, ourcomments should be considered within this context. We will continue to work with DAQ as the draft PM2.5 SIP is developed further. Ourpreliminary assessment is that the draft PM2.5 SIP and associated rules need additional development and analysis as detailed inthe enclosed comments so that the PM2.5 SIP can be approved by EPA. However, we will not reach any final conclusions until the State provides a formal submittal ofthe PM2.5 SIP and after we conduct our own notice and comment rulemaking. We want to acknowledge the tremendous efforts ofthe DAQ on all ofthe hard work that has been undertaken on the draft PM2.5 SIP. 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 contactme at 303-312-6416, orhave your staffcontact Catherine Roberts, Particulate Matter Program Manager, at 303-312-6025.Enclosures (6) 

# c:!J:l

Carl Daly, Director

# 2-b

AirProgram

1) EPA Region 8 Comment for Utah PM2.s SIP SectionIX Salt Lake City PartA.21; Provo PartA.22; Logan UT /ID PartA.23 2) EPA Region 8 Comments onUtahPM2.5 SIP Draft Rules 3) EPA Region 8 Comments on Section IX.H. 11, 12, 13 4) EPA Region 8 Comments onModeling TSD for Utah SIP Control Measures for Area and Point Sources, Fine Particulate Matter, for the Salt Lake, Utah, and Logan, UT-ID NonattainmentArea 5) EPA Region 8 Comments onRACT Discussion in SIP Narratives DAQ-072-12 and DAQ074-12 and RACT Technical SupportDocument 6) EPA Region 8 Comments on Mobile Sources, Transportation Conformity, Related Contingency Measures, & I/M

2

### ATTACHMENT 1 EPARegion 8 Commentfor Utah PM2.s SIP Section IX Salt Lake City PartA.21; Provo PartA.22; Logan UTIID PartA.23 The following comments are based on40 CFRPart 51 subpart Z

- Provisions for Implementation ofPM2.sNational Ambient Air Quality Standards 1) §51.1002 Submittal ofSIP. This section includes the requirement to identify and evaluate sources ofPM2 .5 direct emissions and precursors in accordance with sections 51.1009 (RFP) and 51.1010 (RACT and RACM). This includes the identification and evaluation ofcontrol measures for each plan precursor. (72 FR20586, 20594-20597) The draft PM2 

### .s SIP has identified the relevant precursors and their current and projected emissions but only evaluates controls for VOC and some direct PM2 .5. Ourpreliminary analysis indicates that the draft PM2.s SIP has provided an appropriate technical demonstration to reverse the presumption for including VOC as a planprecursor (§51.1002(c)(3)(i)-(ii)). However, there is no evidence ofan evaluation ofcontrol measures for SOx, nor is there any evidence ofan evaluation ofcontrol measures for NOx. The draft PM2.s SIP narrative needs to include information and analysis ofthesetwo precursors. (§51.1002(c); and (c)(l); and (c)(2)). 2) §51.1004 Attainment Dates. The proposed attainment date must be as expeditious as practicable butno laterthan five years from the date ofdesignation or December 14, 20 14. However, the Administrator may extend the date to the extent she determines appropriate for a period no more than 10 years from the date ofdesignation- i.e., up to December 14, 2019

- considering the severity ofnonattainment and the availability and feasibility ofpollution control measures. Specifically, "[t]he EPA will not grant an extension ofthe attainment date beyond the initial 5 years required by section 172(a)(2)(A) for an area ifthe State has not considered the implementation ofall RACM and RACT local control measures for the area..." 72 FR 20601. The March 2, 2012 Implementation Guidance onpage 4 also states, "In order to support a requested attainment date ofmore than five years after the effective date ofdesignation, the state should ensure that it has done a thorough evaluation ofpotential RACM/RACT measures. The state analysis should demonstrate that sufficient control measures could not be adopted and implemented cumulatively in order to establish an attainment date at least one year earlier." Ourreview ofthe draft PM25 SIP has revealed:

a. In the draft PM2 .5 SIP, the State requests an attainment date extensionto January 1, 2020. If an extension is granted it can only be for five years from the attainment date ofDecember 14, 2014 to December 14, 2019. b. Itappears from boththe draft PM2 .5 SIP narrative and the TSD that the draft PM2 .5 SIP does not show attainment ofthe PM2 . 5 NAAQS by December 14,2019 for either the Salt Lake City area orthe Utah County area. The only area showing attainment by the statutory date of December 14, 2014 is the Cache/Franklin area which assumes the adoption ofthe I&M program.

c. The RACM/RACT analysis is not adequate. The draft PM2
. 5 SIP has included the expected reductions from existing programs and area source rules for controlling emissions ofVOC. The draft PM2 . 5 SIP does provide for expeditious implementation ofthe proposed VOC rules for area
1sources with compliance required by January 1, 2014. The State has generally proposed as RACM 

### existing (with some revisions) rules whose application will merely be expandedto the PM2 5nonattainment areas. However, the draft PM2.s SIP includes no RACM analysis that evaluates economic and technical feasibility for each ofthe proposedrules. Additionally, we have specific concerns regarding some ofthese rules (see attachment 2 comments onthe proposed rules). Regarding RACT, the draft PM2 .5 SIP does not include any specific dates for the implementation ofnew RACT measures with the exception ofa few sources identified inthe source-specific section ofthe draft PM2 .5 SIP (IX.H11,12,13 DAQ-075-12) (see attachment 3 source-specific comments). Thus, we have no basis to conclude that the implementation ofRACTwill be expeditious. Regarding the substance ofthe analysis, Utahhas concludedthat existing BACT determinations for stationary sources identified inthe PMw SIP are sufficientto control emissions ofSOx, VOC and NOx. We do not considerthis to be a sufficiently robust analysis of RACT. While the PM2.s SIP narrative identifies "newcontrols," later described as "candidate control measures," 

### itdoes not specify what stationary sources wouldbe affected and provides no dates for adoption or implementation ofthese controls. 72 FR20628. The PM2 .5 SIP narrative only gives general explanations ofthese new controls and associated rules. We are very concerned about the absence ofspecific dates and rule language. 72 FR20600-20602, 20612- 20614. In conclusion, the draft PM2.s SIP does not meetthe requirements of§51.1004 because it does not provide ajustificationfor an extension ofthe attainment date. There is no discussion ofthe severity ofthe nonattainment problem nor any analysis demonstratingthatreasonable measures are not available that couldbe implementedto attainthe NAAQS one year earlier. And finally, the request for an extension ofthe attainment date does notprovide a demonstration of attainment ofthePM2.s NAAQS by the extended date ofDecember 14, 2019. 3) §51.1007 Attainment demonstration and modeling requirements The requirements for approving the attainment demonstration are contingentuponmeeting the requirements of§51.112 and Appendix Wand 

### mustinclude "inventory data, modeling results, and emissionreduction analyses

..." Furthermore "The attainment datejustifiedby the demonstration 

### mustbe consistent withthe requirements ofsection §51.1004(b). The modeled strategies 

### mustbe consistent withrequirements in §51.1009 for RFP and §51.1010 for RACT and RACM. And finally, the supporting air quality modeling 

### "shouldbe consistent withEPA's PM2.s modeling guidance." 72 FR 20665. In consideration ofthe fact that modeling does not show attainment ofthe PM2.5 standard, the requirements from §51.1007 have notbeenmet. (see attachment 4 comments onmodeling) 4) §51.1008 Emission Inventory (EI) requirements Under §51.1008(a)(2) the State must "[s]ubmit any additional emission inventory information needed to support an attainment demonstration and RFP plan ensuring expeditious attainment

..." The State needs to show that point source emissions for the baseline year are representative of what is expected for emissions emitted inthe SaltLake and Utah (Provo) nonattainment areas. (EI Guidance sec. 3.3.2). Incorrespondence withEPA, the State agreedto provide sensitivity analyses to determine thatemissions in 2008 represent an average emissionyear, butto date

2these analyses have not beenprovidedto 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. This additional information is needed in orderto verify the accuracy ofthe projected actual emissions being used for the attainment demonstration. The State has not provided this additional El information needed to support the attainment demonstration and RFP plan. Currently, the draft PM2.5 SIP provides no analysis or acknowledgment ofthe allowable emissions from existingpoint sources. This issue has been the subject ofnumerous discussions with the State as outlined in an EPAmemo that we providedto Utah on July 3, 2012 (Preliminary Comments onUtah PM2.5 State Implementation Plan). In the absence ofan emission inventory onwhichto evaluate the differences betweenprojected actuals and allowable emissions, and an analysis ofthe likelihood thatprojected actuals are a reliable indicator of future emissions, the validity ofthe draft PM2.5 SIP is undermined. The inventory projections must accurately portraypotential future emissions. 5) §51.1009 Reasonable FurtherProgress (RFP) The PM2.s implementationrule specifies that a state must "

...demonstrate generally linear progress inreducing emissions betweenthe base year and the attainment date." §51.1009(d). Chapter 8 ofthe PMz.s SIP describes the required elements and information to be included in an approvable RFP planbut at this point falls short ofconstituting an approvable plan. It shows that the currently identified control measures ofthe SIP (assumed to be represented bythe "projected" columns in Tables 8.1 ofthe SLC and Utah Countynarratives) do not show linear progress toward attainment. The RFP columns showwhat the tons per day emission value shouldbe in orderto show linearprogressiontowards attainment. Linearprogress is delayed until the later years ofSIP implementation for all emissions otherthan VOC, as well as for projected ambient PMz.s concentration. In orderto show linearprogress, the RFP plan would need to have additional emissionreductions by both 2014 and 2017. The data from Table 8.1 for Salt Lake City shows the same outyear emission reduction (deviating from the RFP linearrequirement) for primary PMz.s, NOx, and for ambient projected PMz.s concentrations. Itdoes showgenerally linearprogress for VOC emissions, and Total Precursors, probably because 1) VOC forms a large fraction ofthetotal precursor inventory and 2) 2014 SOz emissions appearto be in error. If2014 S02 emissions are corrected from 2 tons/day to an assumed 12 tons/day, the total precursorreduction curve also shows less control by 2017 than a linear RFP slope wouldrequire. Whatever controls result in the large PM2.5 decreases inthe 2017 to 2019 period should be implemented sooner so that they achieve generally linearprogress. The narrative in Chapter 6 (Salt Lake City SIP) is not currently adequate to identify what controls are being implemented in 2017 that result in this large, out year emission reduction. Our analysis indicates that this pattern oflarge emissionreductions only after 2017 is not a result ofmobile source controls. Itappears that the mobile source emissions are generally linear. Ifthe late decrease in emissions are due to a hypothetical set ofas yet unidentified and unquantified controls described in Chapter 6, which are to be included in the SIP as enforceable future commitments, then it would appearthese commitments need to include additional controls both initially and in 2014 to meet linear RFP, and notjustin 2017. As quoted above, the goal ofRFP
3is for areas to achieve generally linear progresstoward attainment, as opposedto deferring implementation ofall measures until the end; the RFP shown in Chapter 8 (Salt Lake City RFP section) defers significantprogress to the end, and only with as yet unidentifiedhypothetical future controls. In addition, we note that the 2014 S02 emissions of2 tons/day shown inTable 8.1 ofthe Salt Lake City RFP section does not appear accurate inlight ofthe 2008 and 2017 S02emission levels (13.7 and 10.4 tons/day, respectively). We have assumed that they should infact be 12 tons/day. The extent to whichthis error has propagated throughthe modeling should be investigated and corrected ifneeded. Itmight be asserted that, inpart, the large reductions in PM2.s concentration occurring only after 2017 (and thus the deviation from linearprogress) are due to initialNOx disbenefits from early mobile source NOxreductions. Ifthis is asserted, robust intermediateNOx sensitivity model runs (20 14, 2017, as well as 2019) showing the modeledNOx disbenefit wouldbe needed, as well as discussion in the modeling weight ofevidence material. The fact that primary PM2 .5 emissions and S02emissions (once the Salt Lake City S02error is corrected) do not show generally linear reduction, but instead delay reductionto after 2017, suggests thatthe lackof linearprogress in ambient concentration cannotbe attributedto only complex secondary chemistry and NOx disbenefits, but also the lack ofadditional, earlier controls ondirect emissions and precursors needed to demonstrate linear RFP. 6) §51.1010 RACT/RACM §51.1010 requires a "SIP revision demonstrating that [the state] has adopted all reasonably available control measures (including RACT for stationary sources) as necessary to demonstrate ·attainment as expeditiously as practicable and to meet any RFP requirements. The SIP revision shall contain the list ofpotential measures consideredbythe State, and information and analysis sufficientto supportthe State'sjudgmentthat ithas adopted all RACM, including RACT." Furthermore, the State must "considerthe cumulative impact ofimplementing the available measures. Potential measures that are reasonably available considering technical and economic feasibility must be adopted as RACM if, considered collectively, they would advance the attainment date by one year or more." Ourpreliminary review ofthe draft PM2 .s SIP has led us to conclude thatthe State's RACM/RACT analyses need additional work. For each stationary source, or source category, the SIP needs to systematically identify and evaluatepotential measures for eachrelevant pollutant. Currently, it appears that the draft PM2
.5 SIP lacks such a systematic analysis. There is no "information and analysis" regarding technical and economic feasibility ofpotential measures, other than analyses supplied by sources (contained in the TSD). Ourpreliminary review indicates that those source-generated analyses are not sufficiently robust orreliable. (see attachment 5 RACT/TSD comments). The draft PM2 .5 SIP orthe TSD needs to have the required cumulative analysis. The draft PM2 .5 SIP must address the question whether, collectively, potential measures that are reasonably available would advance the attainment date by one year ormore. Giventhatthe State is seeking an extension ofthe attainment date for the maximumperiod allowed bythe CAA, this analysis is essential.

4The current analyses are not sufficient to allow us to conclude that the SIP measures represent RACMIRACT orthat an attainment date extensionto 2019 is reasonable. The draft PM2 .5 SIP does contain several generic statements that suggest that the State believes existing controls represent RACT. For example, Chapter 6 ofthe Salt Lake City SIP narrative has a general description ofthe Clean AirAct'sRACT requirements, along with the following statement: "Withrespect to priortechnology determinations otherthan RACT, the rule provides that prior BACT and LAERdeterminations, in many cases but not all, would assure at least RACT level controls. Where a State has determined VOC to be a significant contributor to PM2.s, compliance with MACT standards may be considered in VOC RACT determinations. EPA anticipates it will be unlikely that States can do much betterthan whatthe MACT controls currentlyrequire." (page 54 ofSalt Lake City SIP narrative; pages 53-54 ofUtah County SIP narrative). In addition, the draft PM2.s SIP narratives state that for stationary sources, Utah's requirement for BACT "is ongoing and ensures that Utah's industry is well controlled." (p. 46 Salt Lake City SIP narrative). The narrative follows this with the conclusionthat "Stationary sources are already heavily controlled." (p. 66. Salt Lake City SIP narrative). In Chapter 9, (page 77) the SIP narrative states that, "Chapter 6 shows that stationary sources already meet or exceed RACT, and represent at most about 20% ofthe emissions contributing to excessive PM2

### .s concentrations during winter." As listed below, these statements do not demonstrate that existing requirements represent RACM/RACT: a) The PM2 .5rule preamble states that "BACT/LAER analyses do not automatically ensure compliance with RACT since the regulated pollutant or source applicability may differ and the analyses may be conducted many years apart." (72 FR20630). The SIP must include evidence that priorBACTILAER determinations continue to represent RACT for each source involved and for eachpollutant ofinterest. 1 Note that this applies to major source BACT/LAER as well as Utah's minor source BACT. b) Similarly, regarding MACT standards, the preamble to the PM2.5 implementationrule states, "ForVOC sources subjectto MACT standards, States may streamline their RACT analysis by including a discussion ofthe MACT controls and relevant factors such as whether VOCs are well controlled underthe relevant MACT air taxies standard, which units at the facility have MACT controls, and whether any major new developments in technologies orcosts have occurred subsequent to establishment ofthe MACT standards." 72 FR 20630. The SIP narrative does not contain any supporting information or discussion as described in the preamble. We do not knowwhich sources, units, orpollutants may be involved and, thus, have no basis to evaluate MACT standards as surrogates for RACM/RACT.

1To the best ofourknowledge there have only been three stationary sources that have had arecent LAER level of review as follows: Pacificorp Gadsby; Pacificorp Lakeside and CER Generators, Inc. We have not had time to research which units and pollutants were coveredby those reviews. Based on the list ofstationary sources in the SIP narrative, that would leave approximately 31of34 stationary sources that have not been subject to LAER. 5c) The statement in Chapter 9, that stationary sources meet or exceed RACT, is not supportedby any substantive information in Chapter 6. Furthermore, the suggestionthat stationary source emissions may receive a less rigorous RACT analysis because they "representat most" 20% of the inventory is not sufficient, particularly since the SIP currently cannot demonstrate attainment by 2014 or 2019 for the SaltLake City or Utah County areas. d) To the extent the State is intending to rely onpriorRACT determinations for otherpollutants, the State must include a certification and supporting documentation inthe SIP, as described in the preamble to our PM2.s Implementation Rule: "Where a State adopted and EPA approved a control measure as RACT for a pollutantemitted from a specific stationary source or source category under anotherNAAQS program, the State may submit as part ofits SIP revision a certification, with appropriate supporting information, thatthe previous determinationrepresents a current RACT level ofcontrol for those emissions for purposes ofthe PM2.5 program." (72 FR 20629) The preamble also states that, "ForRACT certifications and determinations, States are to consider new information that has become available since the earlier RACT determination." (72 FR 20630). The State cannot assume that a prior determination remains valid. Also, we did not find a certification with appropriate supporting informationinthe PM2 . 5 SIP narrative. Thus, based on the draft analyses in the SIP narratives, we are unable to conclude at this time thatthe State analyses are"

... sufficiently robust in consideringpotential measures to ensure the selection ofall appropriate RACT and RACM," orthat the State has provided "areasoned justification for its analytical approach." 72 FR20612. 7) §51.1011 Mid-course Review (MCR) The draft PM2.s SIP narrative does not acknowledge that a Mid-course review mustbe submitted to EPA six years afterthe designation date orDecember 14, 2015. The requirements for the MCR are described in the preamble ofthe PM2.s ImplementationRule, which states that "where EPA finds that a MCRwould be required, the approval ofthe attainment demonstrationwouldbe contingent on a commitment by the State to conductthe MCR." 72 FR20640-20642. According to section 51.1011, the MCRis required for areas with extensions ofthe attainment date to December 14, 2019 and must include: 1) a review ofemissionreductions and progress made in implementing control measures; 2) an analysis ofchanges in ambient air quality; 3) revised air quality modeling analysis to demonstrate attainment; and 4) any neworrevised control measures adopted bythe State, as necessary to ensure attainment. 8) § 51.1012 Contingency Measures CAA section 172(c)(9) requires emissionreductions to be undertakenby a state ifthe area fails to attain the NAAQS by its attainment date or fails to make RFP toward attainment. These contingency measures must take effect without further action bythe state. Additionally, the preamble to the PM2.s Implementation Rule notes that the contingency measures "shouldprovide for emissionreductions equivalentto about one year ofreductions needed for reasonable further progress." 72 FR 20642-20645. The draft PM2.s SIP's contingency provisions do not satisfy the applicable requirements. We have identified the following issues:

6a) The draft PM2.s SIP relies on "commitments"to adopt or implement contingency measures: "As part ofthis contingencyplan UDAQ will committo revising R307-422 with respect to both the offset ratios and the levels used to trigger the requirement." (Salt Lake PM2.5 SIP narrative, page 77) Commitments for contingency measures and unspecified "additional candidates for contingency"that will "continueto be evaluated" based on a revised inventory in 2015 are not approvable. (see attachment 2 comments on R307-422). b) The draft PM2.s SIP must specifically state that the contingency measures will be triggered if the area fails to make RFP or fails to attain the PM2.s NAAQS by the attainment date. This is essential. c) The draft PM2 .5 SIP indicates that the Employer Based Trip Reduction Program is a contingency measure "with an implementation schedule to be determined." This implementation schedule must be specified. Also, the program appears to be inconsistent with CAA section 118 because it does not apply to private employers as well as federal and other governmental entities. (see attachment 6 comments ontransportation conformity) d) The draft PM2.s SIP contains no calculation ofthe emissionreductions that would be equivalentto about one year ofreductions needed for reasonable further progress, nor does it contain an estimate ofthe reductions the identified contingency measures would achieve. e) One contingency measure identified inthe draft PM2 .5 SIP is to reduce from 25ug/m3 to 15ug/m3 the ambient concentration ofPM2 .5 for calling a no bum day. In addition to other issues identified above, this measure is currently insufficient because it contains an exemption that renders the measure unenforceable and fails to specify an adequate means to enforce violations. The proposedrule, R307-302-3(2) and R307-302-3(4), exempts"

...those having no visible emissions." Also, howwould the rule be enforced and what penalties are there for violations of the no bumday rule? (see attachment 2 comment on R307-302). 9) Enforceability CAA section 110(a)(2)(A) requires that SIPs include "enforceable emission limitations" as necessary or appropriate to meet applicable CAA requirements including attainment ofthe NAAQS. CAA section 110(a)(2)(C) requires that SIPs include a "program to provide for enforcement ofthe measures described in [110(a)(2)(A)]." CAA section 172(c)(6) also requires that nonattainment area SIPs include enforceable emission limitations "as may be necessary or appropriate to provide for attainment of[the NAAQS]

...by the applicable attainment date

..." 40 CFR 51.112(a) provides that "eachplanmust demonstrate that the measures, rules, and regulations contained in it are adequate to provide for the timely attainment and maintenance of the national standard that it implements." 40 CFRpart 51, subpart K requires that SIPs include monitoring, recordkeeping, and reporting requirements, as does 40 CFRpart 51, appendix V. The preamble to the PM2.5 Implementation Rule also discusses enforcement and compliance. Forexample, the preamble states the following: "[w]e reiterate that the compliance obligations, including emissions limits and other applicable requirements, must be representative ofand accountable to the assumptions used in the SIP demonstration." 72 FR 20659. This section of the preamble specifies elements that SIP regulations must include to meet enforceability requirements.

7The preamble also emphasizes that RACT /RACM measures mustbe implemented "through a legally enforceable mechanism (e.g., a State rule approved into the SIP)" and that such mechanism must meet four criteria. 72 FR 20632-20633. Inparticular, we note the following three criteria: a) "[T]he baseline emissions from the source or group ofsources and the future year projected emissions must be quantifiable so thatthe projected emissions reductions from the sources can be attributedto the specific measures being implemented." b) [T]he control measures mustbe enforceable. c) "[T]he control measures mustbe accountable," meaning, for example, "that source-specific emission limits must be permanent and must reflectthe assumptions used inthe SIP demonstration." ld. Our preliminary review indicates that the draft PM2.s SIP does not currently meet enforceability requirements. Also, as described in attachment 3 source-specific comments, the draft PM2.s SIP contains new enforceability issues, such as director's discretion language. The entire Section 6.7 ofthe PM2.5 SIP narrative, which describes potential additional SIP controls, needs to have more detail than is presented. Generally, the absence ofdates and details ofthe measures, or whether any ofthese measures will actually be adopted, is notconsistent with an enforceable SIP commitment. Additionally, the SIP must estimatethe emissions reductions that these potential measures would achieve. We also note that Region 9's approval of commitments for the San Joaquin Valley PM2.5 SIP is currently being challenged inthe 9th Circuit Court ofAppeals. An example ofthe current lack ofdetail that we are concerned about is showninthis statement from the PM2.5 SIP SaltLake City (p. 62): "Results ofthese feasibility studies will be made available bythe completion dates also shown inthe table. Studies that point toward possible emissionreductions opportunities will be incorporatedinto theplanwith specific development schedules and emission reductions commitments." Among otherthings, to satisfy CAA requirements, the State must clearly commit in the SIP to adopt specified control measures and achieve specific amounts ofemissionreductions by fixed dates. Furthermore, the State must commit to submit such control measures to EPA for approval into the SIP by fixed dates. As currently written, this section does not meet these requirements. Finally, as mentioned before, there are numerous point sources inthe nonattainment areawith allowable emissions limits (and potential to emit) for primary PM2.5 andprecursors that are well above their current (and future projected) actual emissions. Due to the overwhelmingly local nature ofthe PM2.5problem, the State needs to evaluate whether more stringent emissions limits, consistent with projected actual emissions, are needed atthese sources. For further detail regarding this issue please see EPA's Preliminary Comments onUtah PM2.5 State Implementation Plan, July 3, 2012.

8ATTACHMENT 2 EPA Region 8 Comments on Utah PM2.5 SIP Draft Rules Our comment and preliminary determination for the area source rules listed below are that they may not be approvable ifthe rules are notrevised as supported by our comments below. We recommend that the State address our comments so that the area source rules are more defensible and to better align them with the Clean AirAct. However, this preliminary determination should not be considered our final decision. Ourformal analysis will occurthrough public notice and commentrulemaking after we receive a PM2.5 SIP submittal from the State.

Solid Fuel BurningDevices in Box Elder, Cache, Davis, Salt Lake, Tooele, Utah, and Weber Counties Utah Draft Rule R307-302 Summary ofconcerns on draft rule 1. Lack ofReasonably Available Control Technology (RACT) analysis for the source category; e.g., no information onrange ofcontrol technologies or measures considered or other state rules evaluated. For example, are there otherpotential measures the state could adopt to address wood-burning emissions. 2. Section R307-302-2(1) was revised to provide boundaries based on geographical landmarks. This section needs to be changedto either specify that the boundary is for all PM2.5 nonattainment areas orreference the CFRwhich provides the legal description for the nonattainment areaboundaries. ( 40 CFR 81.345). 3. The proposedrule requires sole source heat devices to be registered before June 1, 2013. Would it be reasonable to apply the prohibition earlier and would that, along with other measures, help advance attainment? 4. Under R307-302-3 (2) the sentence stating that "Themandatory no-bumperiods will only apply to those areas or counties impacting the real-time monitoring site registering the 120 micrograms

..." The phrase"

...only apply to those areas..." is providing too much discretion to the director for deciding which areawill have a no-bum period. The sentence should be changed to: "The mandatory no-bumperiods will apply, at a minimum, to the entire nonattainment (or maintenance) areawithin which the real-time monitoring site registering the 120 micrograms is located and to any other nonattainment areas from which emissions could be impacting such monitoring site." 5. Under R307-302-3(2) and R307-302-3(4), the phrase "

...orthose having no visible emissions" allows an exemption from the mandatory no-bum rule which undermines the intention ofthe rule to banthe use ofsolid fuel devices because ofbad air quality. Additionally, there is no provision for enforcing this rule otherthan DAQ's reliance on complaints from the public. 6. R307-302-3(4) relies on a forecast that monitors will exceed 25 micrograms. This differs from the approach for PM10, whichrelies on monitored exceedances. At a minimum, there shouldbe an objective trigger- a monitored exceedance. Thus, we recommend that the rule

1provide that a no-burn day is triggered wheneverthere is a monitored or forecasted exceedance ofthe trigger level. 7. R307-302-6(1) should delete "woodburning stove" and substitute "solidfuel burning device." Also, DAQ should consider including specifications for fuel that canbe burned in these devices. For example, the SanJoaquin Valley's Wood Burning Fireplaces and Wood Burning Heaters rule (Rule 4901) includes requirements for the sale ofwood and the test methodused for the moisture content ofthe wood. Additionally, the rule lists prohibited fuels: garbage, treated wood, plastic products, rubber products, waste petroleumproducts, paints and paint solvents, coal, or any other material not intended by a manufacturer for use as fuel in a solid fuel burning device. We would also recommend that DAQ considerprohibiting residential wood burning fireplaces for newresidential developments inthe PM2.5 nonattainment area. At a minimum, DAQ must evaluate these rule improvements as potential RACM. 8. The rule should specify what is included inthe "public announcement" and to whom itwill be distributed. For example, the San JoaquinValley'sWood Burning Fireplaces and Wood Burning Heaters rule (Rule 4901) spells out every avenue that the District couldtake to notify citizens. These include newspapers, radio or television stations, recordedtelephone messages, and messages posted onthe District's website. 9. R307-302-5 limits opacity to 20% for fireplaces and solid fuel burning devices, butthere are no enforceable provisions for monitoring, reporting, and recordkeeping in order to enforce 20% opacity. The PM2.5 SIP and rule should specify a program for enforcementby the State and local governments. See CAA 110(a)(2)(C) and (E). 10. Section R307-302-6(2) states: "Ownership ofa non EPA Phase 2 certified stove within a residential dwelling installed prior to the rule effective date

..." What is the effective date? We think you mean September 1, 2013. The rule should specify this date. Also, is there documentation that would need to be provided and is there a penalty associated with a violation ofthe rule? Additionally, R307-302-6(2) states, "

...so long as the unit remains intactwithinthe real property ofsale." What is intended by including the word "intact?"

2Generator Testing Utah Draft Rule R307-330 Summary ofconcerns on draft rule 1. Lack ofRACT analysis for the source category; e.g., no information on range ofcontrol technologies ormeasures considered or other state rules evaluated. For example, are there other potential measures the state could adopt to address back-up generator emissions? 2. The proposedrule for R307-330 currently does not have any compliance mechanisms needed to make the rule enforceable. The PM2.5 SIP and rule should specify a program for enforcement by the State and local governments. See CAA 110(a)(2)(C) and (E). 3. The sections under R307-330 need to be correctly numbered; R307-330-3 is repeated. 4. Is there a registry ofback-up generators for the nonattainment areas? Howwill DAQ know if this rule is being implemented ifthe sources do not notify DAQ ofhow many generators are in the nonattainment areas, their locations, sizes, etc? 5. "Back-up generator" needs to be defined in this rule since it is not defined in R307-101: General Requirements. 6. Are back-up generators also defined as emergency generators? 7. The two sections ofR307-330-3 seem contradictory. Please clarify what back-up generators will be regulated under this rule ifall back-up generators that are required under state or Federal regulations to test are exempt. What State and Federal regulations require the testing on specific days or dates? This exemption would seem to cover most ofthe back-up generators in the State and thus this rule would achieve minimal reductions, ifany. 8. Is it stated in Federal and/or State lawthat a test date cannotbe rescheduled? 9. The proposedrule mentions "red air quality alert days." Is this in reference to the "Red Light, Green Light" program? The rule needs to define the term "red air quality alert days."

3Appliance Pilot Light Utab Draft Rule R307-356 Summary ofconcerns on draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol technologies or measures considered or other state rules evaluated. Forexample, are there other potential measures the state could adoptto address emissions from appliance pilot lights? 2. The proposed rule for R307-356 currently does not have any compliance mechanisms that are needed to make the rule enforceable. What resources will DAQ devote to checkingup on compliance and the consequences ofnon-compliance? The PM2.5 SIP and rule should specify a program for enforcementbythe State and local governments. See CAA 110(a)(2)(C) and (E). 3. The Board Meeting Minutes ofAugust 1, 2012, mentionthat Questarprovided comments on excluding home water heaters. What was the "convincingposition" commentthat Questar provided that persuaded DAQ to exclude home waterheaters? SanJoaquinValley's Residential Water Heaters rule (Rule 4902) "applies to manufacturers, distributors, retailers, and installers of PUC quality natural gas-firedresidential water heaters withheat inputrates less than or equal to 75,000 BTU/hr." 4. R307-356-1, -2, and -4 are potentially inconsistent. R307-356-2 says the rule applies to furnaces, fireplaces, stoves, and cooktops. R307-356-1 and -4 omit cooktops. Shouldthey be included too? Or are they encompassed within stoves? A definition of"stove" wouldhelp. 5. The definition of"recreational vehicle," whichprovides the boundaries ofthe exemption in R307-356-3(2), indicates that it includes a vehicle designed for humanhabitation for "recreational, emergency, or other occupancy." "Otheroccupancy" is vague. Is it necessary? Is it possible to be more specific?

4Control ofEmissions from Aerospace Manufacture and Rework Facilities. Utah Draft Rule R307-355 Summary ofconcerns on draft rule 1. Lack ofRACT analysis for the source category; e.g., no information on range ofcontrol technologies considered, control efficiencies, orother state rules evaluated. 2. Alternative emission control device with 95% efficiency as certified by manufacturer; apparently applied to control device rather than overall control. Needs clarification ifit applies to both "control device" and "control system." 3. Insufficient monitoring, recordkeeping, reporting, and testing (MRRT). The rule only requires unspecified records to demonstrate compliant coatings or control device operation and maintenance (O&M) permanufacturer's recommendations, but no specified monitoring, reporting, test methods, orcompliance certification. 4. No break out ofprojected 2014 volatile organic compounds (VOC) reductions in tables 6.5. 1 5. The 1997 CTG states that the RACT rule should accurately describe the types ofsources that would be affected and to clearly define terms used to describe the industry or applicable control methods and provides example definitions ofpertinent terms in Appendix A (page 5-1). There is no definition for "general aviation rework facility," in the draft rule. The primer and topcoat requirements for these facilities are less stringent than SN APCD/SCAQMD. 6. VOC content standards: Itappears the State limits are more general than SCAQMD and SNUAPCD and these rules provide more specific limits for many more coating operations. The CTG includes requirements for specialty coatings, which are not covered bythe AerospaceNESHAP. Please explain ifthe State's rule covers specialty coatings. 7. Lacks capture efficiency for add-on control alternative. The SCAQMD rule requires 90% capture and 95% control ofcaptured emissions. 8. Work practices do not specify a maximum VOC content for cleaning solvent. SJVAPCD and SCAQMD specify maximum VOC content ofcleaners. 9. Technical Support Document (TSD) states they were unable to find cost information for the aerospace coatings rule, but indicated 40% control efficiency and referenced EPA's 1997 CTG, EPA-453/R-97-004. The rule does not identify a Cost Effectiveness (CE) value but indicates a control efficiency of40%. EPA's CoST Model database lists CE of$2,534/ton at 61% control efficiency (reformulation) and $165/ton at 60% control efficiency (MACT). 10. Rule effectiveness (RE) of80% is not supported due to the concerns identified and the lack ofdocumentation. Comparative materials referenced: • SN APCD Rule 4605, http://www.valleyair.org/mles/curmtmles/r4603.pdf • SCAQMD Rule 1124, http://www.aqmd.gov/mles/reg/reg11/r1124.pdf • CoST database http://www.epa.gov/ttn/ecas/cost.htm • 1997 CTG for Aerospace

1In the draft PM2.s SIP for each NAA, emission reductions in Table 6.5 compared to baseline area source emissions in Table 4.1. 5Automotive Refinishing Coatings Utah Draft Rule R307-354 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol technologies considered, control efficiencies, orother state rules evaluated. 2. Applies only to refinishing ofautomobiles, motorcycles, light and medium duty trucks and vans in facilities with**PTE~** 2.7 tpy VOC. Rule has muchnarrower applicability provisions than other contemporary rules. SCAQMD, Ozone Transport Commission (OTC), Maryland (MD), and SJVUAPCD rules have no emission cut-offand apply to refinishing ofall types ofmotor vehicles (typically self-propelled vehicles including, but not limited to, cars, trucks, buses golf carts, vans motorcycles, tanks, and armored personnel carriers) and mobile equipment (typically any device drawn or driven onrails or roadways including, butnotlimitedto, trains, railcars, truck trailers, mobile cranes, bulldozers, street cleaners, and implements ofhusbandry or agriculture). 3. Alternative emission control device with 90% efficiency as certifiedby manufacturer; apparently applied to control device rather than overall control. Needclarification if

### itapplies to both "control device" and "control system." OTC, MD, and SJVUAPCD require 85% overall control (capture and control). SCAQMD requires case-specific calculation ofequivalent control. 4. Insufficient MRRT. Only requires unspecified records to demonstrate compliantcoatings or control device O&M permanufacturer's recommendations. Lacks specificityregarding records to demonstrate compliant coatings or control device O&M; entirely lacks provisions for monitoring and test methods. Muchmore detailed in SCAQMD, OTC, MD, and SNUAPCD rules: specific records related to coatings; require records ofkeyparameters for add-on control; and test methods are identified. 5. Work practices do not specify a maximum VOC content for cleaning solvent. OTC, MD, SJVUAPCD, and SCAQMD specify maximum VOC content ofcleaners (25 giL with exceptions). 6. Lack ofrestrictions on manufacture and sale ofnoncompliant coatings, as well as labeling requirements. SCAQMD, OTC, MD, and SJVUAPCD rules all include bans onmanufacture, sale, and possession ofnoncompliant coatings, except for sources with add-on control, andVOC documentation and labeling requirements for coatings. 7. CE value of$2,740/ton "derived from EPA database" is not verifiable or supported due to lack ofdocumentation. EPA's CoST Model database lists CE of$2,534/ton for what appearto be similar measures but information for comparisonis lacking becausethe State's value is undocumented. 8. RE of80% 2 is not supported due to the concerns identified and the lack ofdocumentation.

2 Rule effectiveness value from the Utah SIP Technical Support Document published online. http://www.airquality.utah.gov/Public-Tnterest/Current-lssues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 20P/5 Control Strategies/5 b Area Source/5 b xix R307 354.pdf 6Comparative materials referenced: • Maryland- Code ofMaryland Regulations for Air & Radiation 26.11.19.23, 2012 http://www.dsd.state.md.us/comar/getfile.aspx?file=26.11.19.23.htm • SNUAPCD Rule 4612,2010 http://www.valleyair.org/rules/currntrules/Rule%204612%201010.pdf • Ozone Transport Commission model rule- MotorVehicle and Mobile Equipment NonAssembly Line Coating Operations Alternate- Technical Revisions, 2010 http://www.otcair.org/upload!Documents/Model%20Rules/OTC%20MVMERR%20Mod el%20Rule%20062811%20-%20Altemate%20Technical%20Revisions.doc • SCAQMD Rule 1151,2005 http://www.aqmd.gov/rules/reg/reg11/rl15l.pdf • 40 CFRpart 59, subpart B, 1998 (applies to coating manufacturers, not applicators)http://ecfr.gpoaccess.gov/cgi/t/text/textidx?c=ecfr&sid=6ef2dfflOf04cb94d9f91727c529c348&rgn=div6&view=text&node=40: 6.0.1.1.7.2&idno=40 • CoST database http://www.epa.gov/ttn/ecas/cost.htm

7Fabric and Vinyl Coatings Utab Draft Rule R307-345 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol teclmologies considered, control efficiencies, or other state rules evaluated. 2. VOC content standards inthe draft rule for fabric and vinyl coatings are less stringentthan comparable rules. Please provide documentation or explain why these less stringent limits were selected. SCAQMD 1128 and SJVAPCD 4607limits are more stringent at 2.2lbs/g (265 g/1) than Utah's rule for both categories. 3. Alternative emission control device with 90% efficiency as certified by manufacturer; apparently applied to control device rather than overall control. Need clarification ifit applies to both "control device" and "control system." Additionally, the rule does notprovide a requirement for capture efficiency. The SCAQMD rule requires the control device to reduce VOC emissions from an emission collection system by at least 95% and requires that the system collects at least 90%, by weight, ofthe VOC emissions generated bythe sources ofemissions. 4. Insufficient MRRT. The rule onlyrequires records from the manufacturer that demonstrate compliance. 5. VOC content standard is the same as the 1995 CTGrequirements in EPA-453/R-95-010 for fabric and vinyl coatings but is less stringent than SCAQMD and SJVAPCD rules that have limits at 2.2 lbs/g (265 g/1) for bothcategories. 6. Lack ofTransferEfficiency (TE) requirement. Where TE is typically defined as the ratio ofthe weight ofcoating solids adhering to an object to the total weight ofcoating solids used in the application process. 7. No specification for a maximum VOC content for cleaning solvent. 8. Utah states a control efficiency value of60% and CE value of$3,500/tonVOC. EPA's CoST Model database lists CE of$1,343/ton and 97% control efficiency for fabric coating. 9. RE of80% 3 is not supported due to the concerns identified and the lack ofdocumentation. Comparative materials identified • SCAQMD Rule 1128 (1996), http://www.aqmd.gov/rules/reg/reg11/r1128.pdf • CoST database http://www.epa.gov/ttn/ecas/cost.htm • Beyond VOC RACT CTG Requirements, 1995, EPA-453/R-95-010, http://www.epa.gov/ttncatcIIdir1 /byndract.pdf • SJVIAPCD rule http://www.valleyair.org/rules/curmtrules/r4607.pdf

3 Rule effectiveness value from the Utah SIP Technical Support Documentpublished online. http://www.airquality.utah.gov/Public-Tnterest/Current-Issues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 2012/5 Control Strategies/5 b Area Source/5 b xvii R307 345.pdf 

### 8Flat Wood Panel Coatings Utah Draft Rule R307-349 Summary ofconcerns on draft rule4 1. Lack ofRACT analysis for the source category; e.g., no information on range ofcontrol technologies considered, control efficiencies, orother state rules evaluated. 2. Alternative emission control device with 90% efficiency as certified by manufacturer; apparently applied to control device rather than overall control. Need clarification ifit applies to both "control device" and "control system." Additionally, the draft rule does not clearly specify overall control efficiency (capture and control device) for add-on control alternative 3. Insufficient MRRT. The rule onlyrequires unspecified records to demonstrate compliant coatings orcontrol device O&Mpermanufacturer's recommendations, but no specified monitoring, reporting, test methods, or compliance certification. Muchmore detailed in SCAQMD and SNUAPCDrules: specific records related to coatings; require records ofkey parameters for add-on control; and test methods are identified. 4. Lack ofapplication equipment and TE requirements. 5. Requirements related to specification or labeling ofcoatings was not provided. SJUAPCD rule requires labeling ofcoatings and prohibits specifying use ofnoncompliant coatings. 6. Work practices do not specify a maximum VOC content for cleaning solvent. SJVUAPCD and SCAQMD rules specify maximum VOC content ofcleaners (25 giL with exceptions). 7. CE value of$2,110/ton5 is not verifiable due to lack ofdocumentation

..EPA's 2006 CTG describes CE estimates, in 2005 dollars, for the manufacture ofexterior siding as $2,600 perton ofVOC and, for interiorpaneling/tileboard, as $1,900 perton ofVOC. Control efficiency of 34%3

, is cited as EPA's CTG, EPA-453/R-06-004, for this draft rule, but there is a lack of documentationto supportthis percentage. 8. RE of90% inDavis, Salt Lake, and Utah Counties and 80% in BoxElder, Cache, Tooele, and Weber Counties3 are not supported due to the concerns identified and the lack ofdocumentation. Comparative materials identified • SNUAPCD Rule 4606, 2008 http://www.valleyair.org/rules/currntrules/r4606.pdf • CTG for Flat Wood Paneling Coatings, 2006, http://www.epa.gov/ttn/naaqs/ozone/ctg act/200609 voc epa453 r-06- 004 wood panel coatings.pdf • SCAQMD Rule 1104, 1999 http://www.aqmd.gov/rules/reg/reg11/r1104.pdf

4 Draft rule dated August 27, 2012; Item 15 on the agenda for the September 5, 2012, Utah Air Quality Board published online. http://www.airquality.utah.gov/Air-Quality-Board/Packets/2012/September/ITEM 15 R307- 340to355.pdf 5 Cost-effectiveness, control efficiency, and rule effectiveness values from the Utah SIP Technical Support Documentpublished online. http://www.airquality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIPTSD/TSD for Public Comment 10-1-2012/5 Control Strategies/5 b Area Source/5 b viii R307 349.pdf 9Graphic Arts Utah Draft Rule R307-351 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol technologies considered, control efficiencies, or other state rules evaluated. 2. Insufficient MRRT. The rule only requires monthly records ofmaterial usage and unspecified records to demonstrate compliantcoatings or control device O&M per manufacturer's recommendations, butno specified monitoring, reporting, test methods, or compliance certification. 3. The Applicability section in the draft rule is less inclusive than SCAQMD and SJVUAPCD. 4. VOC standards under R307-351-4 Standards for Rotogravure, Flexographic, and Specialty Printing Operations may be outdated. The draft rule provides information found inthe 1978 CTG and ourreview ofSCAQMD and SJVUAPCD rules showed evidence ofa more stringent standard. 5. Minimal number oflimits onVOC content ofcleaning solvent included. 6. Lack ofrequirements related to sales orlabeling ofcoatings or solvents. 7. The draft rule does not specify a maximum VOC contentfor cleaning solvent. SJVUAPCD and SCAQMD specify maximum VOC content ofcleaners (25 giL with exceptions) for all types ofoperations at a level lowerthanthe 2006 CTG. 8. The 2006 EPA CTG recommends 90% control for control devices installed prior to the effective date ofthe rule and 95% for devices installed after butthe draft rule only specifies 90% control ofdryer emissions for all offset lithographic and letterpress printing. Please explain why the difference from the CTG. 9. Lack ofsales/specificationrestrictions. SCAQMD prohibits specifying use ofnoncompliant coatings and sale ofnoncompliant coatings except where an approved add-on control system is used. 10. CE of$5,890/ton6 is not verifiable or supported due to lack ofdocumentation. Control efficiency of65% 3 references AirControlNet pg. 111-1340, butprovides no other verifiable or supporting documentation. The rule is less stringent than SCAQMD and SJVUAPCD rules for control efficiencies, where SCAQMD and SJVUAPCD require greater control efficiency from add-on controls. 11. RE of90% in Davis, Salt Lake, and Utah Counties and 80% in Box Elder, Cache, Tooele, and Weber Counties3 are not supported due to the concerns identified andthe lack of documentation. Comparative materials identified • SJVUAPCD Rule 4607, 2008 http://www.valleyair.org/rules/curmtrules/r4607.pdf • CTG for Offset Lithographic Printing and Letterpress Printing, 2006 http://www.epa.gov/ttn/naaqs/ozone/ctg act/200609 voc epa453 r-06- 002 litho letterpress printing.pdf

6 Cost-effectiveness, control efficiency, and rule effectiveness values from the Utah SIP Technical Support Document published online. http://www.airgualitv.utah.gov/Public-Interest/Current-Issues/pm2.5/SIPTSD/TSD for Public Comment 10-1-2012/5 Control Strategies/5 b Area Source/5 b xvii R307 351.pdf 10

### • CTG for Flexible Packaging Printing, 2006 http://www.epa.gov/ttn/naaqs/ozone/ctg act/200609 voc epa453 r-06- 003 flexible package printing.pdf • SCAQMD Rule II30, I999 http://www.aqmd.gov/rules/reg/regii/rll30.pdf • CTG for Graphic Arts- Rotogravure and Flexography, I978 http:/ /www.epa.gov/ttn/naaqs/ozone/ctg act/I978I2 voc epa450 2-78- 033 graphic arts%28v8%29.pdf • CoST database http://www.epa.gov/ttn/ecas/cost.htm

IIIndustrialBaking Ovens Utah Draft Rule R307-334 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol technologies considered, control efficiencies, or other state rules evaluated. 2. Insufficient MRRT. The rule only requires certification from the manufacturer that demonstrates compliance and requires records to show operation and maintenance with manufacturers' recommendations. Phoenix, SCAQMD and SJVUAPCD require daily recordkeeping and specify test procedures. 3. VOC content standard is less stringent than similarrules. SJVUAPCD (Section 6.2) requires emissions from all oven stacks to be vented to an emission collection system andthe collected emissions are vented to an approved emission control device, whichhas a control efficiency ofat least 95% as determined by the test method. SCAQMD requires existingbakery ovens to control by at least: (A) 70 percentby weight (as carbon) for an oven with a base year average daily VOC emissions of50 pounds ormore, but less thl';ln 100 pounds; (B) 95 percentby weight (as carbon) for an oven with a base year average daily VOC emissions of 100 pounds or more. SCAQMD also requires newbakery ovens to reduce emissions by at least 95% by weight (as carbon) ifthe uncontrolled average daily VOC emissions are 50 pounds or more. 4. CE value of90% and CE estimated at $9-10,000/ton VOC removed inthe rule is according to documentation from Earthgrains Baking Companies. The control efficiency and CE needs to have additional analysis done to provide verificationbetween Utah/Earthgrains, CoST Model database, and California Districtrules. EPA's CoST Model database lists CE of$1,470/tonand 40% control efficiency by incineration. 5. RE is not provided. Comparative materials identified • SCAQMD Rule 1153 (1996), http://www.aqmd.gov/rules/reg/reg11/r1153.pdf • CoST database http://www.epa.gov/ttn/ecas/cost.htm • Bakery CTG, December 1992, EPA-453/R-92-017, http://www.epa.gov/ttnnaaqs/ozone/ctg act/ • SJVUAPCD rule http://www.valleyair.org/rules/curmtrules/r4693.pdf • Phoenix (Maricopa County) RegulationNumber 3, http://www.maricopa.gov/aq/divisions/planning analysis/rules/docs/343-9502.pdf

12Magnet Wire Coatings Utah Draft Rule R307-348 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information on range ofcontrol technologies considered, control efficiencies, or other state rules evaluated. 2. Alternative emission control device with 90% efficiency as certified by manufacturer; apparently applied to control device ratherthan overall control. Please provide a clarification if it refers to "control device" and "control system." 3. Insufficient MRRT. Only requires unspecified records to demonstrate compliant coatings or control device O&Mpermanufacturer's recommendations, but no specified monitoring, reporting, test methods, orcompliance certification. 4. No limits onVOC content ofcleaning solvent are included. 5. No specification for a maximum VOC content for cleaning solvent. SCAQMD specifies maximum VOC content ofcleaners (25 g/L with exceptions). 6. Lack ofregulation on capture efficiency for add-on control alternatives. The SCAQMD requires 90% overall control (capture and control). 7. CE of$6,560/ton at 36% control efficiency "derived from EPA database" is not verifiable or supported due to lack ofdocumentation. 8. RE of80% 7for BoxElder, Cache, Tooele, Utah, and Weber Counties are not supported due to the concerns identified and the lack ofdocumentation. Comparative materials identified • SCAQMD Rule 1126 (1995) http://www.aqmd.gov/rules/reg/reg11/r1126.pdf • NewJersey TITLE 7, CHAPTER27, SUBCHAPTER 16 http://www.state.nj.us/dep/aqrn/Sub16.pdf • Phoenix (Maricopa County) RegulationNumber 7, http://www.colorado.gov/cs/Satellite?blobcol=urldata&blobheadername1=ContentDisposition&blobheadername2=ContentType&blobheadervalue1 =inline%3B+filename%3D%22Regulation+7+- +Control+of+Ozone+Viz+Ozone+Precursors+%28Emissions+of+Volatitle+Organic+Co mpounds+and+Nitrogen+Oxides%29.pdflllo22&blobheadervalue2=application%2Fpdf&b lobkey=id&blobtable=MungoBlobs&blobwhere=1251809995374&ssbinary=true

7 Rule effectiveness value from the Utah SIP Technical Support Document published online. http://www.airquality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 2012/5 Control Strategies/5 b Area Source/5 b xi R307 348.pdf 13Metal Container, Closure, and Coil Coatings Utab Draft Rule R307-352 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol technologies considered, control efficiencies, orother state rules evaluated. 2. Insufficient MRRT. Only requires unspecified records to demonstrate compliant coatings or control device O&M per manufacturer's recommendations. Lacks specificity regarding records to demonstrate compliant coatings or control device O&M; entirely lacks provisions for monitoring and test methods. Much more detailed in SCAQMD, SNUAPCD, BAAQMD, Phoenix, and Denverrules: specific records related to coatings; require records ofkey parameters for add-on control; and test methods are identified. 3. The definition of"coating operation" should be added to the draft rule for clarification on what a coating operation is. 4. The Applicability section does notinclude coil coating operations. 5. Alternative emission control device with 90% efficiency as certifiedbymanufacturer; apparently applied to control device rather than overall control Please clarify ifitrefers to both "control device" and "control system"). 6. Lack ofapplication and TE requirements. SCAQMD (2008) and SJVUAPCD (2007) rules list various approved application methods. 7. Clarity is lacking related to inclusion ofcoil-coating and applicability size cut-offunderthe Applicability section ofthe draft rule. Rules applicable in Denver and Phoenix (ozone SIPs) have applicability cut-offs at 15 lb/day ofactual, uncontrolled emissions. Denver applies a 2 tpy cutoff, and Phoenix applies 3 lb/hr. Denver and Phoenix cut-offs apply across all subject operations atthe facility. Itis unclear howbroadlythe draft rules cut-offapplies absent definition of"coating operation." SCAQMD has an exemption ifuse< 1gal/day at a single facility, SNUAPCDhas an exemption for sources that use< 55 gal/yr, and BAAQMD has no cut-off. 8. Lack ofrequirements in the draft rule relatedto sales or labeling ofcoatings or solvents. SCAQMD prohibits specifying use ofnoncompliant coatings and sale without labeling. SJUAPCD requires labeling ofcoatings and solvents. 9. No limits on VOC content ofcleaning solvent in the rule. No specification for a maximum VOC content for cleaning solvent. 10. Does not clearly specify overall control efficiency (capture and control device) for add-on control alternative. Lack ofregulation on capture efficiency. SNUAPCDrequires 90% overall control (capture and control). Phoenix and SCAQMD require 85% overall control. BAAQMD requires equivalent control and "abatement device" efficiency of90%. 11. CE of$3,221/ton "derived from EPA database" is notverifiable or supported due to lack of documentation. 12. RE of80% 8 is not supported due to the concerns identified and the lack ofdocumentation.

8 Rule effectiveness value from the Utah SIP Technical Support Documentpublished online. http://www.airquality.utah.gov/Public-Interest/Current-lssues/pm2.5/STP-TSD/TSD for Public Comment 10-1- 2012/5 Control Strategies/5 b Area Source/5 b xvii R307 352.pdf 14Comparative materials identified • SNUAPCD Rule 4604, 2008 http://www.valleyair.org/rules/currntrules/r4604.pdf • SCAQMD Rule 1125, 2007 http://www.aqmd.gov/rules/reg/reg11/rll25.pdf • MaricopaCounty (Phoenix) Rule 336, 1999 http://www.maricopa.gov/aq/divisions/planning analysis/rules/docs/336-9904.pdf • Colorado DPHE (Denver) Regulation 7, updated 2011 http://www.colorado.gov/cs/Satellite?blobcol=urldata&blobheademame1=ContentDisposition&blobheademame2=ContentType&blobheadervalue1 =inline%3B+filename%3D%22Regulation+7+- +Control+of+Ozone+ Viz+Ozone+Precursors+%28Emissions+of+Volatitle+Organic+Co mpounds+and+Nitrogen+Oxides%29.pdfllo22&blobheadervalue2=application%2Fpdf&b lobkey=id&blobtable=MungoBlobs&blobwhere=125180999537 4&ssbinary=true • BAAQMD Regulation 8, Rule 11, 1997**http://www.baaqmd.gov/~/media/Files/Planning%20and%20Research/Rules%20and%20** Regs/reg%2008/rg08ll.ashx?la=en • CoST database http://www.epa.gov/ttn/ecas/cost.htm

15Metal Furniture Surface Coatings Utah Draft Rule R307-346 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol technologies considered, control efficiencies, or other state rules evaluated. 2. Insufficient MRRT. The rule only requires unspecified records to demonstrate compliant coatings or control device O&Mpermanufacturer's recommendations, butno specified monitoring, reporting, test methods, or compliance certification 3. Alternative emission control device with 90% efficiency as certifiedby manufacturer; apparently applied to control device ratherthan overall control. Please clarify ifit refers to both "control device" and "control system." 4. Lack ofapplication and TErequirements. 5. Lack oflimits onVOC content ofcleaning solvent. 6. Work practices do not specify a maximum VOC content for cleaning solvent. SN APCD and SCAQMD specify maximumVOC content ofcleaners (25 g/L with exceptions). 7. Lack ofrequirements and restrictions related to sales orlabeling ofcoatings or solvents. 8. Does not clearly specify overall control efficiency (capture and control device) for add-on control alternative. The CTG and SJVAPCDrequire 90% overall control (capture and control). SCAQMD requires 85% overall control. Overall control means capture systems to collectthe VOC being released at the affected facilities, coupled with control equipmentthat can achieve an overall control efficiency of90 percent (from CTG). 9. CE of$2,020/ton "derived from EPA database" is notverifiable or supporteddue to lack of documentation. EPA's CoSTModel database lists CE of$2,027/tonfor what appearto be similar measures (SCAQMD Rule), but information for comparison is lacking because the state's value is undocumented. The CEreported in the 2007 CTGfor this category is $200/tonwith a control efficiency of35%. 10. RE of80% 9 for BoxElder, Cache, Tooele, and Weber Counties and 90% 3 for Davis, Salt Lake, and Utah Counties are not supported due to the concerns identified andthe lack of documentation. Comparative materials identified • SJVAPCD Rule 4603, 2009 http://www.valleyair.org/rules/curmtrules/r4603.pdf • SCAQMD Rule 1107, 2006 http://www.agmd.gov/rules/reg/regll/rll07.pdf • Maricopa County (Phoenix) Rule 336, 1999 http://www.maricopa.govIaq/divisions/planning analysis/rules/docs/336-9904.pdf • Colorado DPHE (Denver) Regulation 7, updated 2011 http:Ilwww.colorado.govIcs/Satellite?blo bcol=urldata&blobheadername1=ContentDisposition&blobheadername2=ContentType&blobheadervalue1 =inline%3B+filename%3D%22Regulation+?+- +Control+of+Ozone+ Viz+Ozone+Precursors+%28Emissions+of+ Volatitle+Organic+Co

9 Rule effectiveness value from the Utah SIP Technical Support Document published online. http://www.airquality.utah.gov/Public-lnterest/Current-lssues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 2012/5 Control Strategies/5 b Area Source/5 b xi R307 346.pdf
16mpounds+and+Nitrogen+Oxides%29.pdf0/o22&blobheadervalue2=application%2Fpdf&b lobkey=id&blobtable=MungoBlobs&blobwhere=1251809995374&ssbinary=true • CoST database http://www.epa.gov/ttn!ecas/cost.htm • CTG for Metal Furniture (2007), http://www.epa.gov/ttnnaaqs/ozone/ctg act/200709 voc epa453 r-07- 005 metal furniture coating.pdf

17Miscellaneous Metal Parts and Products Coatings Utah Draft Rule R307-350 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol technologies considered, control efficiencies, or other state rules evaluated. 2. Insufficient MRRT. The rule only requires records from the manufacturer that demonstrate compliance. 3. Alternative emission control device with 90% efficiency as certified bymanufacturer; apparently applied to control device ratherthan overall control. Please clarify ifitrefers to both "control device" and "control system. The CTG recommends that add-on devices be coupled with capture systems to collectthe VOC being released atthe affected facilities in orderto achieve an overall control efficiency of90%. The SCAQMD rule requires the control device to reduce VOC emissions from an emission collection systemby at least 95% andrequires that the system collect at least 90%, by weight, ofthe VOC emissions generatedbythe sources of emissions. 4. No specification for a maximum VOC content for cleaning solvent. 5. Director's discretion provision in R307-350-6(8). 6. CE of$2,020/ton3 for Machinery and Special Maintenance and $238/tonfor Other Transportation at 35% control efficiency "derived from EPA database" is not verifiable or supported due to lack ofdocumentation. The 2008 CTG lists CE of$1,758/ton and control efficiency ofabout 35% (from miscellaneous metal and plastic part coating). 7. RE of80% 10 in Box Elder, Cache, Tooele, Utah, and Weber Counties and inDavis and Salt Lake Counties of90%, are not supported due to the concerns identified and the lack of documentation. Comparative materials identified • SCAQMD Rule 1107, 2004, http://www.aqmd.gov/rules/reg/reg11/rl107.pdf • Colorado's Regulation IX (for Denver), http://www.colorado.gov/cs/Satellite?blobcol=urldata&blobheadername1=ContentDisposition&blobheadername2=ContentType&blobheadervalue1 =inline%3B+filename%3D%22Regulation+7+- +Control+of+Ozone+Viz+Ozone+Precursors+%28Emissions+of+Volatitle+Organic+Co mpounds+and+Nitrogen+Oxides%29.pdfl/o22&blobheadervalue2=application%2Fpdf&b lobkey=id&blobtable=MungoBlobs&blobwhere=1251809995374&ssbinary=true • EPA's CTG for miscellaneous metal and plastic parts coatings, 2008, http://www.epa.gov/ttn/caaa/t1 ctg.html • Phoenix (Maricopa County) Rule 336, http://www.maricopa.gov/aq/divisions/planning analysis/rules/docs/336-9904.pdf

10 Rule effectiveness value from the Utah SIP Technical Support Document published online. http://www.airquality.utah.gov/Public-Interest/Current-Issues/pm2.5/STP-TSD/TSD for Public Comment 10-1- 20P/5 Control Strategies/5 b Area Source/5 b xvii R307 350.pdf 18Large Appliance Coatings Utah Draft Rule R307-347 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information on range ofcontrol technologies considered, control efficiencies, or other state rules evaluated. 2. Insufficient MRRT. Only requires unspecified records to demonstrate compliant coatings or control device O&M per manufacturer's recommendations, but no specified monitoring, reporting, test methods, or compliance certification. Lacks specificity regarding records to demonstrate compliant coatings orcontrol device O&M; entirely lacks provisions for monitoring and test methods. Much more detailed in SCAQMD and SJVAPCD rules: specific records related to coatings; require records ofkey parameters for add-on control; and test methods are identified. 3. Alternative emission control device with 90% efficiency as certified by manufacturer; apparently applied to control device rather than overall control. Please clarify ifit refers to both "control device" and "control system." The CTG and SJVAPCD require 90% overall control (capture and control). Overall control means capture systems to collect the VOC being released at the affected facilities, coupled with control equipment that can achieve an overall control efficiency of90percent (from CTG). 4. Lack ofapplication and TE requirements. SCAQMD (2006) and SJVAPCD (2009) rules list various approved application methods. The CTG recommends specific application methods. 5. Lack ofrequirements and restrictions related to sales or labeling ofcoatings or solvents. SJVAPCD and SCAQMD specify maximum VOC content ofcleaners (25 g/L with exceptions). 6. Workpractices do not specify a maximum VOC content for cleaning solvent. SJVAPCD and SCAQMD specify maximum VOC content ofcleaners (25 g/L with exceptions). 7. Lack oflimits on VOC content ofcleaning solvent. 8. CE of$2,020/ton at 30% control efficiency "derived from EPA database" is not verifiable or supported due to lack ofdocumentation. EPA's CoST Model database lists CE of$2,027/ton at 55% control efficiency for what appearto be similarmeasures (SCAQMD Rule), but information for comparison is lacking because the state's value is undocumented. The CE reported in the 2007 CTG for this category is $500/ton with a control efficiency of30%. 9. RE of80% 11 for Box Elder, Cache, Tooele, and Weber Counties and 90% 3 for Davis, Salt Lake, and Utah Counties are not supported due to the concerns identified and the lack of documentation. Comparative materials identified 

### • SN APCD Rule 4603, 2009 http://www.valleyair.org/rules/curmtrules/r4603.pdf • SCAQMD Rule 1107,2006http://www.aqmd.gov/rules/reg/reg11/r1107.pdf

11 Rule effectiveness value from the Utah SIP Technical Support Document published online. http://www.airquality.utah.gov/Public-Interest/Current-Issues/pm2.5/SJP-TSD/TSD for Public Comment 10-1- 2012/5 Control Strategies/5 b Area Source/5 b xi R307 347.pdf
19

### • CoST database http://www.epa.gov/ttn/ecas/cost.htm • CTG for Large Appliances (2007), http://www.epa.gov/ttnnaags/ozone/ctg act/200709 voc epa453 r-07- 004 lg appliance coating.pdf

20Paper, Film, and Foil Coatings Utah Draft Rule R307-344 Summary ofconcerns for draft rule 1. Lack of!{ACT analysis for the source category; e.g., no information on range ofcontrol technologies considered, control efficiencies, or other state rules evaluated. 2. Insufficient MRRT. The rule onlyrequires records from the manufacturer that demonstrate compliance. 3. Alternative emission control device with 90% efficiency as certified by manufacturer; apparently applied to control device rather than overall control. Please clarify ifit refers to both "control device" and "control system." No requirement for capture efficiency. SCAQMD requires 90% collection and 95% control. SJVUAPCD requires an overall capture and control efficiency of90%. 4. Lack ofapplication and TE requirements. 5. Lack oflimits onVOC content ofcleaning solvent. No specification for a maximum VOC content for cleaning solvent. 6. CE of$1,440/ton3 is cited as CTG, EPA 453/R-07-003 in the TSD, but provides no supporting documentation. EPA's CoST Model database lists CE of$1,200-1500/ton. 7. RE of80% 12 is not supported due to the concerns identified and the lack ofdocumentation Comparative materials identified • SNUAPCD Rule 4607, 2008 http://www.valleyair.org/rules/curmtrules/r4607.pdf • SCAQMD Rule 1128, 1996 http://www.aqmd.gov/rules/reg/reg11/r1128.pdf • http://www.epa.gov/ttn/caaa/t1/fr notices/paper film ctg fin.pdf • CoST database http://www.epa.gov/ttn/ecas/cost.htm • CTG for: paper, film and foil coatings, 2007, http://www.epa.gov/ttn/caaa/tl/fr notices/paper film ctg fin.pdf

12 Rule effectiveness value from the Utah SIP Technical Support Document published online. http://www.airquality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 2012/5 Control Strategies/5 b Area Source/5 b xvii R307 344.pdf 21Plastic Part Coatings Utah Draft Rule R307-353 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information onrange ofcontrol technologies considered, control efficiencies, orother state rules evaluated. 2. Insufficient MRRT. The rule only requires records from the manufacturerthat demonstrate compliance. 3. Alternative emission control device with 90% efficiency as certifiedby manufacturer; apparently applied to control device ratherthan overall control. Please clarify ifit refers to both "control device" and "control system." The CTG recommends that add-on devices be coupled with capture systems to collectthe VOC being released at the affected facilities in order to achieve an overall control efficiency of90%. The SCAQMD rule requires the control device to reduce VOC emissions from an emission collection systemby at least 95% and requires thatthe system collects at least 90%, by weight, ofthe VOC emissions generated bythe sources of emlSSlOnS. 4. Prohibits conventional air-atomizing spray equipment, but does not identify other application and lacks TE requirement. CTGrecommends the specified use ofone ormore ofthe following coating application methods in conjunction withthe use oflow-VOC content coatings in options 1 and 2: electrostatic application, HVLP spray, flow coat, roller coat, dip coat (including electrodeposition),**airh~ss** spray, air-assisted airless spray, orother coating application methods capable ofachieving a transfer efficiency equivalentto orbetterthan that achieved by HVLP spraying. SCAQMD rule requires specific coating equipment. 5. The draft rule's Applicability section is not as broad as the CTG and SCAQMD 1145 have bro.ader applicability (beyond auto, truck & business machine plastic parts). 6. No specification for a maximum VOC content for cleaning solvent. 7. Utah states a control efficiency value of35% and CEvalue of$2,020/tonVOC "derived from EPA database" is not verifiable or supported due to lack ofdocumentation. EPA's CoST Model database lists CE of$1,020/ton and 60% control efficiency for plastic parts coating. The 2008 CTG lists CE of$1,758/ton and control efficiency ofabout 35% (from miscellaneous metal and plastic part coating). 8. RE of80% 13 is not supported due to the concerns identified and the lack ofdocumentation. Comparative materials identified • SCAQMD Rule 1145, 2004, http://www.aqmd.gov/rules/reg/reg11/r1145.pdf • CoST database http://www.epa.gov/ttn/ecas/cost.htm • CTG for miscellaneous metal and plastic parts coatings, 2008, http://www.epa.gov/ttn/caaaltlctg.html

13 Rule effectiveness value from the Utah SIP Technical Support Document published online. http://www.airguality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 2012/5 Control Strategies/5 b Area Source/5 b xvii R307 353.pdf 22Emissions Standards for Wood Furniture Manufacturing Operations Utah Draft Rule R307-343 Summary ofconcerns for draft rule 1. Lack ofRACT analysis for the source category; e.g., no information on range ofcontrol technologies considered, control efficiencies, orother state rules evaluated. 2. Alternative emission control system with overall 90% efficiency (capture and control) as certified by manufacturer. 3. The Applicability ofthe draft rule is slightly less stringentthan otherrules. Phoenix rule (ozone SIP) is applicable> 2 tpy, buthas less stringent limits and otherprovisions if< 10 tpy. SCAQMD has an exemption ifuse< 1gal/day. SJVUAPCD has an exemption for sources that use< 20 gal/yr. CTG applicability**is~** 25 tpy. 4. VOC content standards are consistent with 1996 CTG, but are less stringent than SCAQMD and SNUAPCD. Additionally, in Table 1, the rule mistakenly lists the units ofthe standard as lb VOC/lb coating, minus water, as applied when they should be lb VOC/lb solids, as applied (perthe CTG and existing rule). SCAQMD and SJVUAPCD rules have much lower limits as well as limits for more types ofcoatings. 5. Work practice requirements are generally comparable to other contemporary rules but the draft rule does not contain many components listed in the CTG. CTG includes a workpractice implementationplan, operator training, leak inspection and maintenance plan, cleaning and washoffsolvent accounting system, and spray booth cleaning solvent VOC limit. SJVUAPCD and SCAQMD specify maximum VOC content ofcleaners (25 g/L with exceptions). Phoenix specifies maximum VOC content ofspraybooth cleaning solvent (8.0% by weight as in CTG). 6. Insufficient MRRT. Only requires certifiedproduct data sheets for coatingsplus unspecified records to demonstrate compliance when solvents are added to coatings before application and unspecified records to demonstrate control device O&M per manufacturer's recommendations. Lacks specificity regarding records to demonstrate compliant coatings, as applied or control device O&M; entirely lacks provisions for monitoring and test methods. Much more detailed in SCAQMD, SJVUAPCD, Phoenix, and CTG rules; specific records related to coatings; require records ofkey parameters for add-on control; test methods identified. CTG requires semiannual compliance reports. 7. VOC content standards are much less stringentthan Californiarules. 8. No requirements related to sales or labeling ofcoatings or solvents. SJUAPCD and Phoenix require labeling ofcoatings. 9. Lack oflimits onVOC content ofcleaning solvent. 10. CE of$2,260/ton14 is not verifiable or supported due to lack ofdocumentation. EPA's CoST Model database lists CE of$967/tonfor the 1996 CTG. 11. Control efficiency of82% 3

, which cites CTG, EPA-453/R-96-007, but provides no supporting documentation. EPA's CoST Model database lists 47% for the control efficiency for the 1996 CTG. 12. RE of80%3 is not supported due to the concerns identified and the lack ofdocumentation.

14 Cost-effectiveness, control efficiency, and rule effectiveness values from the Utah SIP Technical Support Document published online. http://www.airquality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIPTSD/TSD for Public Comment 10-1-2012/5 Control Strategies/5 b Area Source/5 b viii R307 343.pdf 23Comparative materials identified • SJVUAPCD Rule 4606, 2008 http://www.valleyair.org/rules/currntrules/r4606.pdf • SCAQMD Rule 1136, 1996 http://www.aqmd.gov/rules/reg/reg11/r1136.pdf • Maricopa County (Phoenix) Rule 342, 1996 http:/ /www.maricopa.gov/aq/divisions/planning analysis/rules/docs/342-9611.pdf • CTG: EPA-453/R-96-007, 1996, http://www.epa.gov/ttn/naaqs/ozone/ctg act/199604 voc epa453 r-96- 007 wood furniture manufacturing.pdf • CoST database http://www.epa.gov/ttn/ecas/cost.htm

24

### Aggregate Processing Operations for PM2

### .sNonattainmentAreas Utah DraftRule R307-312 Summary ofconcerns for draft rule 1. Lack ofReasonably Available Control Technology (RACT) analysis for the source category; e.g., no information onrange ofcontrol technologies considered, control efficiencies, or other state rules evaluated. 2. There are no MRRTrequirements inthe draft rule. 3. The draft rule only has seven definitions while SCAQMD rule includes 54 definitions. The term "aggregateprocessing" is not defined in the draft rule eventhough it is the primary source being regulated. Enforcement ofthe rule may be hampered by lack ofdefinition ofthe terms contained in the rule. Consideration should be given to defining more terms, such as those defined inthe SCAQMD rule. 4. Some requirements inthe Utahrule may conflict with the Utah SIP Section IX, Part H- PM 10 Emission Limits and Operating Practices 15

. The Utah SIP requires the following standards for visible emissions for the Geneva Rock Products Hansen Pit and Mount Jordan Pit: Crushers: 10% opacity; Screens: 10% opacity; All conveyor transfer points: 10% opacity; Conveyor drop points: 15% opacity. 5. The draft rule does notprovide any workpractice standards for achieving the specified visible emission limits. The SCAQMD rule specifies the use ofdust suppressants or other dust control methods to meet the visible emission standards, but does not specify specific workpractice standards. A separate SCAQMD rule (Rule 403) for fugitive dust provides detailed workpractice standards that apply to, among other sources, aggregate-related plants and cement manufacturing facilities. This rule includes workpractice standards for screening and crushing, which are not provided in the draft rule. 6. Alternative controls were notprovided in the draft rule. The SCAQMD rule requires baghouses (fabric filters) for crushing and screening equipment, and allows for the use ofdust suppressants or other dust control methods to meet visible emission standards as an alternative. 7. CE was not identified inthe draft rule. 8. RE of80% 16 is not supported due to the concerns identified and the lack ofdocumentation. Comparative materials identified • South CoastAir Quality Management District (SCAQMD) Rule 1157, http://www.arb.ca.gov/DRDB/SC/CURHTMLIR1157.PDF • SCAQMD Fugitive Dust Rule 403, http:/ /www.arb.ca.gov/DRDB/SC/CURHTMLIR403.PDF

15 Utah SIP Section IX, Part H- PM 10 Emission Limits and Operating Practices, effective May 4, 2011. Available at: http://www.airguality.utah.gov/Pianning/SIP/SIPPDF/secixh.pdf 16 Rule effectiveness value from the Control Strategies Document for Aggregate Processing Operations, contained in the Draft TSD for PM25Attainment SIPs, Section 5, Control Strategies, available for public comment 1011/2012

- 11/112012. Available at: http://www.airquality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIPTSD/TSD for Public Comment 10-1-2012/5 Control Strategies/5 b Area Source/5 b v R307 312.pdf 25• Maricopa County Air Quality Department (MCAQD) Rule 316, http://www.maricopa.gov/aq/divisions/planning analysis/rules/docs/316-0803.pdf • San Joaquin Valley Air Pollution Control District (SJVAPCD) Rule 4201, http://www.valleyair.org/rules/currntrules/r4201.pdf • CoST database http://www.epa.gov/ttn/ecas/cost.htm

26

### Permits: PM2.5 OffsetRequirements in PM2.5 NonattainmentAreas and in SaltLake County,Davis County and Portions ofUtah County Designated Nonattainmentfor PM2.5 Utah DraftRule R307-422 Summary ofconcerns for draft rule: 1. Under the Purpose section ofthe draft rule, it is not clear why the rule refers to filterable PM2.5, ratherthan total direct emissions ofPM2.5, including both filterable and condensable PM2.5. According to the 40 CFR 51.165(a)(1)(xxxvii) definition of"regulatedNSRpollutant," PM2.5 emissions include condensable emissions, which must be accounted for in applicability determinations and in establishing emissions limitations for PM2.5 in nonattainment majorNSR permits. This requirement has been in effect since January 1, 2011, perthe definition revised in the 2008 PM2.5 NSRImplementationRule (73 FR 28321, May 16, 2008). 2. Under the "Applicability" sectionthe draft rule should define howthe impact is determined (e.g., model, protocol, modeled maximum of3.0 micrograms per cubic meter anywhere inthe NAA, but 0.1 micrograms per cubic meter modeled at any monitor location). Also, the ruleshould make it clear onwhat is meant by "0.1 micrograms at any monitor." Does this mean PM2.5 monitoring data collected at an ambient monitor, or could it mean a modeled value? 3. According to §51.165(a)(2), the significant impact level for PM2.5 (i.e., when a major source ormodification is consideredto cause or contribute to violation ofthe NAAQS) is 1.2 micrograms per cubic meter for the 24-hour averaging period. (This refers to the concentration ofPM2.5 only, not precursorconcentrations.) Under the Applicability section, the 3.0 micrograms per cubic meter should be lowered to represent this cut-offlevel, at least for the PM2.5 concentration. 4. Howwas the "0.1 micrograms at any monitor" determined? This needs to be defined since the concept was not included inrule 421. Also, was this intended to be 0.1 micrograms "per cubic meter"? 5. Additional definitions are necessary, including: combined PM2.5, filterable PM2.5, and PM2.5 precursors. Rule R307-422-4 (3)(b)(i) indicates that "combined PM2.5" includes filterable PM2.5, NOx, S02 and VOC, but with no definition this may be interpreted differently. Additionally, since DAQ is seeking to demonstrate that VOC is a significant contributor to the PM2.5 nonattainment problem, the definition of"PM2.5 precursors" would likely include S02,NOx, and VOC. Butwith no definition, 40 CFR 51.165(a)(l)(xxxvii)(C)(4) states that "volatile organic compounds and ammonia are presumed not to be precursors to PM2.5 in any PM2.5 nonattainment, unless the State demonstrates to the Administrator's satisfaction or EPA demonstrates that emissions ofvolatile organic compounds or ammonia from sources in a specific area are a significant contributorto that area's ambient PM2.5 concentrations." 6. The term "Filterable PM2.5" excludes "condensable PM2.5", which is contrary to §51.165(a)(1)(xxxvii), as noted above. The requirement to include condensable PM2.5 was again confirmed on October 12,2012, whenEPA issued final amendments to its rules for the NSRprogram regarding the definition of"regulatedNSRpollutant." This action confirms that condensableparticulate matter must be included as part ofthe emissions measurements for regulation ofPM2.5 and PM10. 7. While emissionreduction credits (ERCs) are defined in the rule in terms oftons/year, given that DAQ describes this as a winter-only nonattainment issue, consideration could be given to

27defining or limiting ERC use in a seasonal manner. For example, ERCs created from predominantly summertime emission sources may be counterproductive ifthey are allowed to be used during wintertime. 8. We have concerns regarding the definitions of"offsetbaseline date" and "pre-baseline ERC." We do not understand why the offsetbaseline date potentially could vary from areato areabased on the effective date ofthe SIP. This is something thatrequires further discussion. We note, however, that we are not convinced thatthe overall approach the rule delineates for use of banked emission reduction credits that are "pre-baseline" is viable orconsistent with CAA requirements. For example, given the significant hurdles the State faces in achieving attainment, does it make sense to allow new or modified sources to use "pre-baseline" emissionreduction credits for offsets? Suchhistorical emissionreduction credits will not reduce area emissions or help the area achieve attainment. In fact, it appears to us that allowing use ofsuch credits to offset new emissions will have the opposite effect. 9. Under R307-422-4(l)(a), "

...R307-403-4, R307-403-7 and R307-403-8

..." generally address offsets and specifically address offsets for Ozone and PM10 NonattainmentAreas, butdo not have specific requirements for PM2.5. EPA has previously identified concerns regarding Utah's existing offset and banking provisions. We will need more time to revisitthose concerns to determine how they may impact R307-422. Without further review, it is not clearto us thatthe treatment ofbaseline for offsets inR307-403-7 orbanking inR307-403-8 is appropriate or that the cross-reference to R307-403 is acceptable. 10. The word "assumed" under R307-422-4(l)(b) should be revised to "deemed"to provide a more enforceable term. 11. R307-422-4(2). We need to discuss the basis for this provision, which allows an owner/operatorup to 180 days after a reduction has occurred to apply for anemissionreduction credit. Would it make more sense to have an advance application for an emissionreduction credit, followed by verification ofan actual emissionreduction and a permit conditionrestricting emissions consistent with the reduction? Whatever system is used, and regardless ofwhether we're considering new or old reductions, there mustbe some means to verify thatthe reductions to be used for offsets are real. 12. Paragraph R307-422-4(3)(a) does not specify the offsetratio, where the CAArequires at least a 1:1 ratio for PM. Also, given the use ofthe terms "major modification" and "major source," the rule should indicate that they are defined in R307-101-2. 13. The definitions for "majormodification" and "significant" need to be updated to include PM2.5 and its precursors. 14. DAQ needs to define a significant level for VOC as a precursorto PM2.5 since itis not defined in 

### §51.165. 15. Please provide an explanation ofhowthis requirement for major sources and major modifications under R307-422-4(3)(a) satisfies the offsetrequirements ofthe Act, and inconsideration ofthe Act'srequirement for reasonable further progress inthe attainment plan. 16. R307-422-4(3)(b)(i) and (ii) needs to be revised to state: "New sources ormodifications to existing sources, resulting in a combined net emissions increase (filterable PM2.5 

### + S02

### +NOx 

### + VOC) that is

...." 1

7. EPA guidance and rules do not allow interpollutanttrading for nonattainment majorNSR without a demonstration bythe State. We recognize that R307-422-4(3)(b)(i) and (ii) do not supplantthe rule's major source requirements, but allowing ERC credit for "any ofthese pollutants" found under R307-422-4(3)(b)(i) and (ii) is nonetheless questionable. Ourconcernis

28that the rule's approach couldresult in an increase in ambient concentrations, if, for example, sources wereto offset directPM2.5 with precursor reductions. Thus, it is not clear to us that the rule is consistent with CAA requirements, including those ofCAA 110(1). 18. R307-422-4(3)(c)(i) wouldbe improvedby adding the word "increases" as follows: "

... required to offsetthose emissions increases at a ...." 19. As discussed previously, the 10 tpy under R307-422-4(3)(c)(i)(A) should include emissions ofboth condensable and filterable PM2.5. 20. What is meant by "effective period oftheplan" found under R307-422-4(3)(d)(i)? What happens after thatperiod? 21. We are not convinced thatthe tracking and usage restrictions are sufficiently reliable or enforceable. Also, it may be useful to describe and review the magnitude ofthe threshold identified in the PM2.5 state implementationplan (SIP) for each nonattainment area. However, as noted previously, we have a general concernregarding the use ofpre-baseline credits to offset new emissions in the nonattainrnent areas.

29Road Salting and Sanding Utah Draft Rule R307-307 Summary ofconcerns for draft rule: 1. Section R307-307-1 was revised to provide boundaries based on geological landmarks. This section needs to be changedto either specify that the boundary is for all PM2.5 nonattainment areas or reference the CFRwhich provides the legal description for the nonattainment area boundaries. (40 CFR 81.345). 2. R307-307-4 requires a demonstration withrespectto PMlO emissions butdoes not discuss PM2.5 emissions. This provision shouldbe revised to include PM2.5. 3. We also note that the rule contains apparent director's discretion provisions. We would like to discuss these with you and explore potential revisions to address our concerns.

30

### ATTACHMENT 3 EPARegion 8 Comments PM2.5 SIP Sub Sections IX.H.11, 12, 13 General Comments Section IX lacks a description ofthe relationship between Section IX'srequirements, the State's RACT TSD determinations, and the attainment demonstration. Do these requirements in Section IX represent RACT? Were the Section IX requirements represented in the modeling for attainment? Ifso, howwere these requirements incorporated? These interconnections must be clearly described inthe PM2.5 SIP narrative. 

### Comments on DAQ-075-12, Section IX.H.ll, General Requirements: EPA notes that the General Requirements only apply to the refineries in the PM2 .5 nonattainment areas. EPA also notesthat an applicability date ofJanuary 1, 2018 seems to apply to most or all ofthe General Requirements. What precludes advancing this date? What makes January 1, 2018 reasonable or an earlier date unreasonable? 1. VOC control: ForVOC control, the State is not proposing any emission limits. Instead, the State is proposing only to cross-reference existing requirements from NSPS Subpart VV for leak check monitoring. Therefore, these proposed provisions do not appear to represent any reduction from 2008 baseline emissions for VOC. 2. PM emissions from FCCUs: The State is proposing an emission limit of 1gram perkilogram ofcoke bumoff(equivalent to 2 lbs perton). This is the same stringency as the limit in NSPS SubpartJ (and Ja). Since all refinery FCCUs are already subject to the NSPS Subpart J limit, the proposed emission limit does not appear to represent any reduction from the 2008 baseline emission inventory, for PM emissions from the FCCUs. 3. S02emissions from FCCUs: The State is proposing an emission limit of50 ppmv on a seven-day rolling average. This is the same as the limit in NSPS Subpart J, for FCCUs with an add-on control device for S02(except thatNSPS doesn't specify an averaging time, therefore presumably it is the average ofthree 1-hour stack test runs). The currentNSRpermit for at least one ofthe refineries has the same 50 ppmv limit on a seven-day rolling average, as well as a limit of25 ppmv on an annual average (the latter being the same as one ofthe limits in NSPS SubpartJa, which is not in Subpart J). The 2005 PM10 SIP submittal had a limit of9.8 kg ofS02 per 1,000 kg ofcoke burnoff, which is the same as the NSPS SubpartJ limit for FCCUs with no add-on control device for S02
. Itis unclear which ofthe five SLC refineries already have an add-on control device for S02 at their FCCUs. Thus it is uncertain whether the proposed 50 ppmv emission limitrepresents a reduction in so2 emissions from the 2008 baseline emissions inventory. 4. S02emissions from SRUs: The State is proposing an S02 emission limit of2,500ppmv. This is the same as one ofthe emission limits in NSPS Subpart Ja. For SRUs smaller than 20

1long tons per day, Subpart Ja specifies a limit of2,500 ppmv, ifthe SRU uses an oxidation control system or a reduction control system followed by incineration. For a reduction control system not followed by incineration, the Subpart Ja limit is 3,000 ppmv ofreduced sulfur compounds and 100 ppmv ofH2 S. NSPS SubpartJ specifies an emission limit of250ppmv for SRUs having an oxidation control system or a reduction control system followed by incineration. Fora reduction control system not followed by incineration, the SubpartJ limit is 300 ppmv ofreduced sulfur compounds and 10 ppmv ofH2 S.) However, neither ofthe SubpartJ limits apply to Claus sulfurrecovery plants (SRUs) with a design capacity for sulfur feed of20 long tons per day orless. The following is unclear a) which ofthe five SLC refineries have SRUs smallerthan 20 long tons per day, b) which ofthe refinery SRUs have an oxidation system orreduction control system followed by incineration, and c) which ofthe SRUs might already be subjectto Subpart Ja. Thus, it is uncertain whether the proposed 2,500 ppmv limitrepresents a reduction in S02 emissions from the 2008 baseline emissions inventory. The 2005 PM10 SIP submittal had a requirement for 95% S02 control efficiency at refinery SRUs, rather than a ppmv emission limit. The 95% efficiency requirement was carried over from the original PM10 SIP that EPA approved in 1994. EPAhad raised enforceability issues withthe 95% requirement in its December 1, 2009 FRnotice proposing to disapprove the 2005 PM10 SIP submittal. Specifically, EPA found that the 2005 SIP submittal lacked any technique for calculating SRU efficiency. It appears that the State is nowproposing to replace the 95% efficiencyrequirement with a 2,500 ppmv emission limit. Since the State's newproposal does not indicate howcompliance withthe 2,500 ppmv limit is to be demonstrated, the proposed new limit appears to be unenforceable as well. An S02 CEMS already exists at each SRU and collects emissions data. EPA stated in its December 1, 2009 proposed disapproval notice thatthe S02 CEMS shouldbe used to track emission compliance at the SRUs. No S02CEMS is mentioned inthe State's newproposal. Also, the State is proposing a new exemption from SRU emission limits, during periods of maintenance ofthe sulfur pit. This new exemption appears to be the same as inNSPS Subpart Ja, at 40 CFR 60.102a(f)(3). Generally, EPA interprets the CAA as not permitting exemptions from SIP emission limits, nor do we believe an affirmative defense provision is acceptable to address planned maintenance activities. Ourposition onthis issue was recently upheld by 5th Circuit Court ofAppeals. See 77 FR49507 (preamble to final rule for NSPS subpart 0000, dated August 16, 2012) for further explanation. 5. S02 emissions from fuel gas combustion devices: The State is proposing an S02emission limit of20 ppmv, or an alternative a limit of 162 ppmv for H2 S in fuel gas, applicable starting in 2018. These proposed limits are the same as inNSPS SubpartJa, at 40 CFR 60.102a(g)(l)(i). The NSPS Subpart J limit is 0.1 gr/dscffor H2 S in fuel gas, which is roughly equivalentto 160 ppmv. Since this limit was in the 2005 PM10 SIP submittal, the State'sproposed limit does not appearto represent a reduction in so2 emissions from the 2008 baseline emissions inventory.

2The State has, however, apparently removed the exemption from this limit during startup, shutdown ormalfunction ofthe amine plant, an exemption which was inthe 2005 PM10 SIP submittal and which was identified by EPA as an issue in its December 1, 2009 proposed disapproval ofthe 2005 submittal. We supportremoval ofthe exemption to ensure consistency with CAA requirements. 6. S02 emissions from flares: The State is not proposing any emission limits, nor investigation ofany possible ways to capture flare emissions. Instead, the State is proposing to require a flare managementplan (i.e., workpractice requirements in lieu ofemission limits), for minimizing the amount ofgases that are routed to the flares. This appears to be the same as the requirements for flares inNSPS Subpart Ja, at 40 CFR60.103a. The State'sproposal does not sufficiently address the issues about flares that EPAraised in its December 1, 2009 proposed disapproval of the 2005 PM10 SIP submittal. The issue was lack ofappropriate restrictions for flaring emissions at refineries. EPA expressed concernthat flare emissions during upsets might interfere with maintenance ofthe NAAQS and that the submitted SIP explicitly ignored such emissions for purposes ofassessing compliance with daily and annual emission caps. EPA did not say that a flare managementplan ofthe type nowproposed by the State would resolve these issues. The State'snewproposal for a flare managementplan does take some steps to quantify flare emissions, by requiring an evaluation ofbaseline flow to the flares, but does not actually require the refineries to quantify flare emissions, which was one ofthe issues raised by EPA in 2009. The newproposal also does not account for flare emissions in assessing compliance with daily S02 emission caps for the refineries, which was another issue raised by EPA in 2009. The proposed source-specific provisions for the refineries appearto be the same as the 2005 PM10 SIP submittal, as far as excluding flare emissions in demonstrating compliance with refinery S02 emission caps. In summary, the proposed General Requirements incorporate controls already required in the following: existing permits; NSPS requirements; and measures contained in the 2005 PM10 SIP submittal which EPA proposed to disapprove. Itdoes not appearthat the RACT analyses inthe TSD were used to identify any newcontrol strategies. Comments on DAQ-075-12, Sections IX.H.12 and IX.H.13, Source-specific Requirements General Comments on Sections IX.H.l2 and IX.H.13: 1. Monitoring, reporting and recordkeeping (MRR): The SIP must include adequate MRR requirements. This generally means requirements for specific test methods or CEMS, other compliance monitoring as appropriate, maintenance ofadequate records, and periodic reporting. Many ofthe source-specific provisions are deficient in this area. We have not attempted to identify all MRRdeficiencies in ourcomments. 2. PM condensables. The State is proposing PM2.5 emission limits that include condensables at Holly Refinery, at the Kennecott SmelterMain Stack, and at the Kennecott Power Plant. Please explain why no PM2 .5 emission limits are proposed for any refineries other than Holly. The proposed PM2 . 5 emissionlimit at Holly applies to external combustionprocess equipment. Since

3the same type ofequipment exists at the otherrefineries, for consistency we would expect PM2

_ 5 emission limits (including condensables) as RACT at the otherrefineries as well. Source-Specific Comments on Sections IX.H.12 and IX.H.13: In the comments below, EPArefers backto the 2005 PM 10 SIP submittal. This is done only for purposes ofcomparisonto the currentproposal, and is not meantto imply that EPA is still reviewing the 2005 submittal, which was withdrawnby the Governor ofUtah on October 7, 2011. EPA also refers backto the June 27,2011 SIP submittal for the Kennecott Bingham Canyon Mine Expansion (which included source-specific provisions for the other sources that were inthe 2005 SIP submittal), again only for purposes ofcomparisonto the currentproposal. EPA has not yet acted on the 2011 SIP submittal. 1. ATK Launch Systems:

• The proposedprovisions consist solely oflimits onthe pounds ofreactive waste and rocket motorpropellants that maybe burned "whenthe PM2.slevels exceed 35 ug/m3 at the nearest real-time monitoring station." These appearto be newprovisions that are not in any existing State rules orNSRpermits applicable to ATK. These proposed provisions are inconsistent with the CAA and EPA'sregulations ondispersiontechniques 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, ineffect, these provisions treat the area around ATK as an independent nonattainment area.

• No emission controls, or efforts to minimize the above-mentioned openburning, orto investigate alternatives to openburning, such as waste minimization or transporting the materials somewhere outside the nonattainment areabefore burning, are proposed. The proposed provisions do not appear to be based on a RACT analysis noris it clear whether these provisions represent a reduction from 2008 baseline emissions. 

### Itis also not clear what pollutant(s) these provisions are intendedto address. A meaningful RACT analysis is required for ATK. 2. Big West/Flying J Refinery: All proposed provisions appearto be the same as inthe 2005 PM10 SIP submittal, with respect to daily emission limits and associated enforceabilityprovisions. No new emission limits are proposed. Therefore, the proposedprovisions do not appearto represent a reduction from 2008 baseline emissions.

• No VOC emission limits, or surrogates for VOC limits, are proposed. EPAnotes that Table 6.3 onpages 55-56 ofthe Salt Lake County SIP narrative lists VOC emissions of 1.276 tons per day in 2008, 1.243 in 2014, 1.243 in 2017, and 0.841 in 2019. A RACT review for VOC appears warranted. 3. Bountiful City Light & Power:

4• Theproposedprovisions, which consist ofNOx emission limits at three combustion turbines, are not enforceable, as there are no enforceabilityprovisions. The proposed NOx limits for Turbine #1 are in tons per day and grams/kW-hr, and for Turbines #2 and #3 are inppm and lb/hr. Also, engine #8 is not addressed in the proposed provisions. The currentNSRpermit limits use ofengine #8 to 1,600 hours per year.

• Since the 2005 PM10 SIP submittal included a NOx emission limit for only one combustionturbine, and since the currentNSR and title V permits also list only one turbine at the facility, the proposedprovisions appear to represent an increase from 2008 baseline emissions, by allowing for two new combustionturbines. The currentNSR permit says that five existing internal combustion engines are to be replaced when the newturbines are installed. Have they beenreplaced?

• The 2005 PM10 SIP submittal also included a requirement to retest engine #8 at least once every 24 months to verify the NOx emission factor. The currentNSRpermit also includes a fuel restriction to natural gas as primary fuel for the six existing dual-fuel internal combustion engines. Please explain why these requirements are not be included inthe proposedprovisions. 4. Central Valley Water Reclamation:

• The only emission limit for this source inthe 2005 PM 10 SIP submittal, which was aNOx emission limit of0.648 tons per day, for the combined emissions ofall engines, has not been included in the proposedprovisions. Itis not clear why not. Instead, the proposed provisions basically consist only ofa workpractice requirement to "remove the biosolids from the facility." This requirement is apparently new with this proposal, not carried overfrom any existing rules orNSRpermits. No explanation has beenprovided how this requirement mightreduce emissions from 2008 baseline, or howthis requirement might relate to emissions at all. Also, a director's discretion provision is included, which would allow for alternatives to this requirement. EPAhas explained previously why director's discretion provisions are not approvable in SIPs.

• The currentNSRpermit lists three internal combustion engines and four backup generators. NOx emissions from each engine are limited to 5.95 lblhr and 1.75 grams per hp-hr. NOx emissions from eachbackup generator are limited to 7.13 lb/hr and 1.8 grams perhp-hr. Thepermit also includes the same tons-per-day NOx limit as the 2005 SIP submittal. The engines combust low Btu digester gas generated from the wastewater treatment process. Please explain why these NSRpermit limits, which cover the main emitting units at this facility, are not included in the proposed source-specific provisions.

• No VOC emission limits, or surrogates for VOC limits, are proposed. The currentNSR permit limits the VOC content inpaint to the density limits established in R307-340. EPA notes that Table 6.3 onpage 55 ofthe Salt Lake County SIP narrative lists VOC emissions of0.137tons perday in 2008, but only 0.032 tons per day in 2014. Please explain whythe State is projecting a 77% decrease in VOC emissions from 2008 to 2014 giventhe lack ofVOC limits in the SIP.

55. CER Generation: • The proposedprovisions do not include aNOx emission limitfrom the currentNSR permit of5ppmdv for eachturbine, on a 30-day rolling average. This limit was established as LAER inthe initial NSRpermits for each ofthe turbines, which were reviewed in detail by EPA when they were in draft. Please explain why this was not considered appropriate for inclusion as a RACT limit. 6. Chemical Lime Company- Grantsville Plant:

• The proposed emission limits for PM10 are 1.32 lblhr and 0.060 gr/dscfat the Hydrator Baghouse, and 24.78lblhr and 0.19 gr/dscfatthe Kiln Electroscrubber. The proposed emission limits for NOx are 75.00 lblhr and 650 ppm at the Kiln Electroscrubber. These limits are the same as in the currentNSRpermit, issued in 2006. Therefore, the proposed provisions do not appear to represent any reduction from 2008 baseline emissions.

• The proposedprovisions include headings at the Hydrator Baghouse and Kiln Electroscrubber for PM2.s, but no emission limits for PM2 .5,justblanks. Please explain when these limits will be established.

• The proposed provisions do not specify the stack test methods for PM10 and NOx nor any recordkeeping or reporting requirements, and are therefore not enforceable. 7. Chevron SLC Refinery:

• Otherthan the exceptions noted in the comments below, all proposedprovisions appear to be the same as inthe 2005 PM10 SIP submittal, with respect to daily emission limits and associated enforceability provisions.

• The proposedprovisions include a S02emission limit of0.5 tons per day, to include gasfired compressor drivers and all external combustionprocess equipment, butexcluding the SRU, the FCCU CO Boiler, and the FCCU Catalyst Regenerator. The limit inthe 2005 PM10 SIP submittal was 2.977 tons per day, which included the FCCU CO Boiler and the Catalyst Regenerator. Please explain why these two units are no longer included, considering thatthey are substantial sources ofS02emissions, and considering that 40 CFR 51.1002(c)(1) requires an evaluation ofcontrol measures for S02. The proposed provisions do not include any separate so2 limitfor these two units,justa separate so2 limit of2.128 tons per day for the SRU, same as the 2005 PM10 SIP submittal.

• Similarly, for NOx the proposedprovisions include an emission limit of2.52tons per day, to include gas-fired compressor drivers and all external combustionprocess equipment. The limit in the 2005 PM10 SIP submittal was 3.248 tons per day, which also included the FCCU CO Boiler, CatalystRegenerator and SRU-TGI. Please explain why these three units are no longer included, considering thatthey are substantial sources of NOx emissions, and considering that there is a subsection inthe proposedprovisions that says the NOx emissions from the FCCU CO Boiler and CatalystRegeneratormay be

6determined by CEM. Itis unclear why there would be a provision for determining the NOx emissions from these two units, when no NOx emission limit applicable to these two units is proposed.

• Under the heading "SulfurRecovery Unit (SRU)," item C says "Wheneverthe S02 CEM is bypassed for short periods, S02 CEM data from the previous three days will be averaged and used as an emission factor to determine emissions." Although this CEM provisionhas also beenprovided for Tesoro refinery, ithas not beenprovided for Big West Oil refinery orHolly refinery. Please explain why two refineries should need this provision when two others apparently do not. Please also explain whythe S02 CEM would need to be bypassed. Please also explain why it shouldbe reasonable to rely on CEMS data from the previous three days. This approach does not account for the possibilitythat emissions might behigherduring CEM bypass. Please also explain why special provisions for CEM bypass shouldbe necessary on a source-by-source basis, considering that R307-170 already has provisions to account for CEM unavailability.

• Overall, since the only changes in emission limits from the 2005 PM 10 SIP submittal appear to be removal ofS02 andNOx emission limits for certain large emitting units, and removal ofannual limits, the proposedprovisions do not appear to represent a reduction from 2008 baseline emissions.

• No VOC emission limits, or surrogates for VOC limits, are proposed. EPA notes that Table 6.3 on pages 55-56 ofthe Salt Lake County SIP narrative lists VOC emissions of 0.607 tons per day in 2008, 1.219 in 2014, 1.219 in 2017, and 1.219 in 2019. A RACT review for VOC would seem warranted. 8. Great Salt Lake Minerals:

• Theproposedprovisions consist only ofa requirement to replace existing wet scrubber AH-013 with a baghouse byJanuary 1, 2017, a requirement to replace existing wet scrubber HE-028 with a baghouse by January 1, 2014, PM emission limits and stack test requirements for the two newbaghouses, and a requirement to propose a PM2.5 emission limit for each ofthe two newbaghouses. Please explain why the proposed provisions do not include PM emission limits for any ofthe 13 existing PM control devices. Existing NSRpermits for this facility do include such limits. The existing limits are in lb/hr and gr/dscf. Please also explain why the proposed provisions do not include NOx emission limits of 1.30 lb/hr and 9.0 ppm for each boiler, which are in the currentNSRpermit.

• Please also explain why GSLM is given until 2017 to install one ofthe new baghouses and propose PM2.s emission limits. What precludes advancing this date? What makes January 1, 2017 reasonable or an earlier date unreasonable?

• The emission limits for the two newbaghouses are not enforceable because no stack test method is specified. Also, there are no recordkeeping or reporting requirements. 9. Hexcel:

7• The only proposed provision is to require regenerative thermal oxidizers (RTOs, also known as fume incinerators) for VOC control at any carbon fiber lines constructed after January 1, 2015, and to monitorthe oxygen content at the RTOs. Since this provision only pertains to future carbon fiber lines, it does not appearto represent a reduction from 2008 baseline emissions. Without specifying minimum oxygen content at the RTOs, the requirementto monitor for oxygen content is ofno value for minimizing emissions. The requirement to monitor is unenforceable without a specified frequency ofmonitoring and adequate recordkeeping and reporting requirements. Theprovision allows the use ofan equivalenttechnology with equivalencyto be determined bythe Director. This is an unacceptable director's discretion provision.

• The currentNSRpermit for Hexcel has parametric limits for 15 existing fume incinerators, in terms ofincineratortemperature, residence time, and minimum oxygen content, to ensure proper operation for destruction ofVOCs, as well as a requirement to route all furnace emissions to the incinerators. Please explain why the same requirements are not proposed for future carbon fiber lines. Please also explain whythe proposed provisions do not include any existing fume incinerators.

• Also, EPA notes that no VOC emission limits are proposed; however, we assume that the proposed provisionto require RTOs at all future carbonfiber lines, and to monitortheir operation, is intended to minimize VOC emissions, and therefore couldbe viewed as a surrogate for VOC emission limits. EPArecognizes that parametric monitoring is appropriate to ensure proper operation ofRTOs on an ongoing basis.

10. Holly Refinery:

• Otherthanthe exceptions noted inthe comments below, all proposedprovisions appear to be the same as inthe 2005 PM10 SIP submittal, withrespectto daily emission limits and associated enforceability provisions.

• The proposed provisions include a PM10 emission limit of0.51 tons per day (filterable plus condensable), for combined emissions from all external combustionprocess equipment, including the SRU-TGI (but apparently excluding the FCCU). Also proposed is a PM2.s emissionlimit of0.237 tons perday, (filterable plus condensable), for the same group ofemitting units. These proposed limits are apparently newwith this proposal, not carried over from any existing rules orNSRpermits applicable to Holly. EPA does not know ifthese proposed new limits are based on any newcontrols orrepresent any reduction from 2008 baseline emissions. The 2005 PM10 SIP submittal included a filterable PM10 emissionlimit of0.444tons per day for the same group ofemitting units. EPA does notknow whether the proposed emission limits represent a reduction from 2008 baseline emissions, since EPA does not know what the state is assuming, as far as whatportion ofthe PM emissions are condensables. Itdoes appear, however, thatthe State is assuming PM2 .5emissions are

8about 46% ofthe mass oftotal PM10 emissions at external combustion process equipment at this refinery. Please provide confirmation ofthis.

• The proposed S02 emission limit of4.714 tons per day does not appear to include the SRU-TGI, and there is no separate S02 emission limit proposed for the SRU-TGI, yet S02 emissions from the SRU-TGI are required to be determined daily. This does not make sense. The 2005 PMro SIP submittal said this S02emission limit includes the SRU-TGI. This appears to be an omission orerror in the proposedprovisions.

• The proposedNOx emissionlimit of2.20tons perday does not appearto include the FCCU orthe SRU-TGI. These are substantial sources ofNOx emissions. The same NOx limit inthe 2005 PM10 SIP submittal included the SRU-TGI. This also appears to be an omission orerror in the proposedprovisions.

• No VOC emission limits, or surrogates for VOC limits, are proposed. EPA notes that Table 6.3 onpages 55-56 ofthe Salt Lake County SIP narrative lists VOC emissions of 0.622 tons perday in 2008, 0.575 in 2014, 0.575 in 2017, and 0.575 in 2019. A RACT review for VOC would seem warranted. 11. Kennecott Bingham Canyon Mine and Copperton Concentrator:

• Theproposedprovisions for the Mine include a restriction to 30,000 miles percalendar day ofore and waste haul truck travel. While this potentially addresses a shortcoming that EPA identified in the 2005 PM10 SIP submittal (which was a lack ofNOx emission limits for the Mine, or surrogates for NOx emission limits such as operating restrictions), no explanationhas been provided on howthis restriction translates into NOx emissions and whether it represents a reduction from 2008 baseline emissions. Also, it is not enforceable, as there are no enforceability provisions for this restriction.

• The proposedprovisions for the Mine also include fugitive dust control measures for haul roads and otherunpaved roads, consisting ofwatering and use ofchemical dust suppressant. While this potentially addresses another shortcoming that EPA identified in the 2005 PM10 SIP submittal (which was lack ofany restriction on PM emissions at the Mine), these measures are not enforceable, as there are no recordkeeping provisions to ensure the measures are implemented. Further, since these measures are much less detailed and comprehensive than what was in the original PM10 SIP that EPA approved in 1994, these measures are less stringentthan what Kennecott has beenrequired to use since before 2008. The proposed measures therefore do not appear to represent a reduction from 2008 baseline emissions. Please explain why the more detailed dust control measures are plannedto be dropped. Also, the SIP will need to include a 110(1) analysis showing that the changes to the previously approved SIP will not interfere with attainment, reasonable further progress, or any other CAA requirement. Keep in mind that this will be necessary for any revisions to the previously approved SIP.

• Theproposedprovisions for the Mine do not include any limit on amount ofmaterial movement (ore plus waste) per 12-monthperiod, nor any limit on S02 emissions. We

9note that the 2011 SIP submittal for the Mine Expansion specified a new limit of260 million tons ofmaterial movement per 12-monthperiod, and a limit of97 tons peryear ofS02 , with the S02 emissions to be calculated onthe basis ofgallons ofdiesel fuel used at the Mine,. Please explain whether the PM2.5 NAAQS attainment demonstration assumes these levels oflimits on allowed material movement and S02 emissions, and why no limits onmaterial movement or S02 emissions are included inthe proposed source-specific provisions for the Mine.

• None ofthe S02emission limits from the 2005 PM10 SIP submittal are included, for eitherthe Mine orthe Concentrator. The 2005 SIP submittal included a limit on sulfur content in diesel fuel at the Mine of0.03 lb sulfurperMMBtu. The 2005 SIP submittal also included a limit of0.314 tons per day ofso2 for the molybenite rotary kiln atthe Copperton Concentrator. Please explain why these limits are not included.

• No VOC emission limits, or surrogates for VOC limits, are proposed. EPA notes that VOC emissions from the Mine and Concentrator are projectedto decrease by more than halffrom 2017 to 2019. (Ref: Table 6.3 onpages 55-56 ofSalt Lake County SIP narrative.) Please explain this decrease considering that no VOC emission limits are proposed. 12. Kennecott PowerPlant/Lab/Tailings Impoundment:

• There are no proposedprovisions for the Tailings Impoundment facility. Detailed fugitive dust control provisions are inthe current title V operating permit and were incorporated by reference into the 2005 PMw SIP submittal. Please explain why no such provisions are proposed for the tailings impoundment.

• For existing Boilers 1-3 at the PowerPlant, the only proposed provision is a prohibition against operation after January 1, 2018 (or after new Unit#5, a combustionturbine, commences operation, whichever is sooner). The currentNSRpermit (dated December 2011), which approved construction ofthe newturbine, prohibits operation ofBoilers 1-3 after the newturbine commences operation and does not mentionJanuary 1, 2018. Please explain why a date laterthan the PM2 

### .s attainment date of2014 has been included and why such date is reasonable. The 2005 PM10 SIP submittal, as well as the currentNSRpermit, include PM10 andNOx emission limits for Boilers 1-3. One set oflimits is for operation during wintermonths on natural gas. The other set oflimits is for operation during non-wintermonths on coal. Since these boilers will be allowed to continue to operate until possibly 2018, please explain why limits for these boilers are not included. The recent "Updated SIP Documentation" onthe state's website includes corrections for existing Boiler4, to now specify PM2 .5 andNOx emission limits, before and after January 1, 2018. Since these proposed limits are no more stringentthan the PMw andNOx limits in the 2005 PM 10 SIP submittal, the proposed limits do not appearto represent a

10reduction from 2008 baseline emissions. Also, the SIP mustjustifY the implementation date ofJanuary 1, 2018 and why measures could notbe advanced to an earlier year.

• Also, please explain why the proposed provisions (including the above-mentioned corrections) do not include limits on amount offuel use at the boilers. The following fuel restrictions, for the total ofBoilers 1-4, were included inthe 2005 PM10 SIP submittal, and are inthe currentNSRpermit (issued in 2009) and the current title V permit:

> Limit of42,706 MMBtu/day ofnatural gas usage 

### > Limit of31,510 MMBtu/day ofcoal usage during natural gas curtailments in Winter months

• Theproposed provisions include VOC, NOx and PM2.s emission limits for the anticipated newUnit#5 (a combined cycle combustionturbine). These limits are not new with this proposal, but are carried overfrom the currentNSRpermit dated Dec. 2011. The PM2.s limit of 18.8 lblhr includes condensables. (EPA notes that Table 6.3 on page 56 ofthe Salt Lake County SIP narrative lists 0.006 tons per day for 2008 and 2014, but 0.066 tons perday for 2017 and 2019. Please explain whether this is a typo.)

• Overall, the proposedprovisions for the PowerPlant do not appear to represent a reduction from 2008 baseline emissions. Priorto 2018 at least, the four existing boilers at the PowerPlant will still be allowed to operate, and for Boilers 1-3, with no emission limits in the proposedprovisions (unlike the 2005 PM10 SIP submittal). ForBoiler 4, the proposed limits are no more stringentthan the limits in the 2005 PM10 SIP submittal.

• We are also concernedthat the limits for Unit #5 appear to include an exemption for startup and shutdown and transient load conditions. Such an exemption is inconsistent with CAArequirements.

• The MRRprovisions are insufficient. No test methods are specified, and there are no recordkeeping orreporting requirements. 13. Kennecott Smelter and Refinery:

• Emission limits are proposed for S02only at the smeltermain stack and the acid plant tailgas, same as the 2005 PM10 SIP submittal, but the numerical values ofthe proposed limits at the main stackhave been updated from the 2005 SIP submittal to reflect limits in the currentNSRpermit. New limits for PM2 . 5 described below are proposed for the main stack, which are not in the currentNSRpermit. PM2.s emission limits of85 lblhr (filterable) and 434lb/hr (filterable+ condensable) are proposed for the smelter main stack, apparently to replace the PM10 limits currently in effect. These proposed limits are new with this proposal, not carried over from any existing rules orNSRpermits applicable to the smelter. After taking into account the ratio ofPM2 .5to PM10 (which EPA assumes would be less than 100%), the proposed limit for filterable PM2 .5 appears to be no more stringent than the limit for filterable PM10 in

11the 2005 PM10 SIP submittal, which was 89.5 lb/hr. Therefore, the proposed limit appears to represent little, ifany, reduction from 2008 baseline emissions. Please explain why no emission limit is proposed at the smelter main stack for NOx. The proposedprovisions include a requirement for a NOx CEM atthe main stack, which does not make sense without a NOx emission limit. The 2005 PM10 SIP submittal included a NOx limit of35.0 lb/hr, which also appears in the currentNSRpermit, dated May 2011.

• The proposed S02emission limits for acid planttailgas, which are 1,050 ppmdv ona 3- hour rolling average and 650 ppmdv on a 6-hourrolling average, are the same as inthe 2005 PM10 SIP submittal, butthat submittal was out-of-date withrespectto NSRpermit limits in effect at that time. The emission limits for acid planttailgas inthe August 2000 NSRpermit, which have been carried overinto all subsequentNSRpermits, are 250 ppmdv on a 6-hourblock average, 170 ppmdv on a 24-hour calendar day average, and 1

00 ppmdv on an annual average. Please explain why the State proposes emission limits as RACT, which are muchhigher than what the source is already requiredto meet. Is this an inadvertent error?

• The proposed S02 emission limits for the main stack and acid plant tailgas are carried over from NSRpermits dating backto August of2000 orearlier, orelse are less stringent than current limits in the case ofacid planttailgas (as explained above). The proposed so2 limits do not appear to represent any reduction from 2008 baseline emissions.

• The proposed provisions for the smelter main stack do not include the requirement from the 2005 PM10 SIP submittal to measure the main stack PM emissions continuously, but justto conduct a stack test for PM2 . 5 once a year. While EPApresumes this is because the PM measurement device atthe main stackis not designed to separate outthe fraction ofPM that is smallerthan 2.5 microns, this is not explainedbythe State.

• Please explain why the proposed provisions for the smelter do not include provisions from the 2005 PM10 SIP submittal for recordkeeping, calculationprocedures, and CEMS QA for the S02and NOx CEMS. EPA considers suchprovisions to be necessary for the smelter main stack emission limits for S02 and NOx to be enforceable. Also, no test method is specified for PM2 .5, and there are no recordkeeping orreporting requirements for any pollutants at either the smelter orthe refinery.

• Please explain why the proposedprovisions for the smelter do not include the measures in the 2005 PM10 SIP submittal for reducing escape ofpollutants to the atmosphere and to capture emissions and vent them through a stack or stacks, as well as a requirement to keep a log ofany instances where the sulfuric acid plantis bypassed.

• The only proposed emission limit at the Kennecott Refinery, which is 9.5 lbs/hr for the combinedNOx emissions oftwo boilers, is equivalentto the limit inthe 2005 PM10 SIP submittal, which was 0.057 tons per day for eachboiler. The proposed limittherefore does not appear to represent a reduction from 2008 baseline emissions.

12• Overall, the proposedprovisions for the Kennecott smelter and refinery do not appear to represent any reduction from 2008 baseline emissions for any pollutant. 14. Murray City Power:

• The proposedprovisions (NOx emission limits of95 ppmdv on a 4-hour average and 25 ppmdv on a 24-hour average, for each ofthe three 14.3 MW combustionturbines) are the same as in the currentNSRpermit, issued in 2004. Therefore, the proposedprovisions do not appear to represent any reduction from 2008 baseline emissions. • NSPS subpart GG has a limit on sulfur content inturbine fuel of0.05% by weight. This limit is included inthe current title V permit. Please explain why this limit is not included inthe proposedprovisions. • The proposed provisions lack recordkeeping and reporting requirements. 15. Nucor Steel:

• Theproposed PMz.s emission limits for the EAF baghouse (19.53 lbs/hr for filterable PMz.s and 29.53 lbs/hr for filterable+ condensable PM2.5) are apparently new limits which do not appear in any existing rules or permits applicable to Nucor. The filterable PM10 emission limit inthe currentNSRpermit (issued in June of2010) is 20.06 lbs/hr. This limithas been in effect inNSRpermits dating back to July of 1999. The proposed limit for filterable PMz.s is only slightly lower and therefore does not appear to represent a reduction from 2008 baseline emissions.

• The proposed S02 emission limits for the EAF baghouse include the 3-hour and 24-hour limits from the currentNSRpermit, but also include a S02 limit of78.54 lbs/hr on an annual average, which is apparently a new limit with this proposal that does not appear in any existing rules orpermits applicable to Nucor. Since this proposed limit is equivalent to 344 tons peryear, it is less stringentthan the limit of322 tons perrolling 12-month period inthe currentNSRpermit. The proposed S02 limits therefore do not appear to represent a reduction from 2008 baseline emissions. The proposed provisions do not include any short-termNOx emission limits for the EAF baghouse, nor does the currentNSRpermit. The only proposedNOx emission limit for the EAF baghouse, which is 59.75 lbs/hr on an annual average, is apparently a new limit with this proposal that does not appear in any existing rules orpermits applicable to Nucor. Sincethis proposed limit is equivalentto 262 tons peryear, it is less stringent than the limit of245 tons perrolling 12-monthperiod in the current NSRpermit. The proposed limit therefore does not appear to represent any reduction from 2008 baseline emtsswns. Please explainhowthe proposed S02 and NOx emission limits could constitute RACT when they are higherthan existing limits in the current NSRpermit.

13• The proposedVOC emission limit of22.2lb/hris carried over from the currentNSR permit and therefore does not appear to represent a reduction from 2008 baseline emissions.

• The proposed provisions do not specify test methods for PM2.s and VOC at the EAF baghouse stack, nor a test method for NOx atthe reheat boilers. The proposedprovisions also lackrecordkeeping andreporting requirements. 16. PacifiCorp Gadsby PowerPlant:

• The only emission limit in the proposedprovisions is a NOx limit of6.57 tons perday, for the total ofall boilers and combustionturbines. This limit is carried over from the 2005 PM 10 SIP submittal. The limit is not enforceable withrespectto the turbines because there is no indicationhowturbine emissions are to be measured,justthe boiler emissiOns.

• The proposedprovisions require NOx CEMS for the boilers, butnotfor the turbines. The 2005 PM10 SIP submittal required that emissions from boththe boilers andthe turbines be measuredby CEMS, as required by 40 CFRPart 75 (Acid Rain Program). Please explain why this requirement does not appear inthe proposedprovisions.

• Please explain why the proposedprovisions do not include the following NOx emission limits which are inthe currentNSRand title V permits:

> Boiler 1: 179 lb/hr, 336 ppmdv > Boiler 2: 204 lb/hr, 336 ppmdv > Boiler 3: 142 lb/hr, 168 ppmdv > Combustionturbines (all three combined): 22.2 lb/hr > Each combustion turbine: 5 ppmdv (30-dayrolling average); 116 ppmdv (notto exceed at any time)

• The proposed provisions also lackrecordkeeping andreporting requirements. 17. Proctor & Gamble Paper Manufacturing Plant:

• Please explain why the only emission limit inthe proposedprovisions is a PM10 limit of 6.65 lb/hr, for each ofthetwo paper machines. The proposed provisions do not include NOx emission limits in the currentNSRpermit at the four boilers (3.3 lb/hr and 45 ppm for each boiler) and at the two papermachines (13.50 lb/hr and 0.09lb/MMBtufor each machine). These are the main emitting units atthe facility.

• The proposed provisions include a heading for PM2.s, butno emissionlimit for PM2 .s,just a placeholder saying "To be determined by January 1, 2015." This is not sufficient. Please explain why a date laterthanthe PM2.s attainment date of2014has beenincluded, and why advancing the date would not be reasonable.

14• No VOC emission limits, or surrogates for VOC limits, are proposed. The VOC emissionpotential was listed inthe initial NSRpermit action as 213 tons per year. A RACTreview for VOC would seem to be warranted.

• Theproposedprovisions do not specify any stack test methods, nor any recordkeeping or reporting requirements. 18. Tesoro SLC Refinery:

• Otherthan the exceptions noted in the comments below, all proposedprovisions appear to be the same as inthe 2005 PM10 SIP submittal, with respect to daily emission limits and associated enforceabilityprovisions.

• Theproposedprovisions include a PM2.s emission limit of4 lbs/MMSCF at the FCCU/CO Boiler. This is apparently a new limit with this proposal, which does not appear in any existing rules orpermits applicable to Tesoro. The limit is not enforceable because the proposed provisions do not specify a stacktest method. There is also no indication whetherthe proposed limit includes condensables. Since there is no existing limit on PM emissions which is specific to the FCCU/CO Boiler, EPA does not know whetherthe proposed limitrepresents a reduction from 2008 baseline emissions.

• No VOC emission limits, or surrogates for VOC limits, are proposed. EPA notes that Table 6.3 onpages 55-56 ofthe Salt Lake County SIP narrative lists VOC emissions of 0.748 tons perday in 2008, 0.744 in 2014, 0.852 in 2017, and 0.796 in 2019. A RACT review for VOC would seem warranted.

• Underthe heading "S02 EmissionLimits" (which apparently pertains to the entire refinery), item E says "Wheneverthe S02 CEM is unavailable for short periods (i.e., CO boiler orESP emergency bypass, FCC start-up and shutdowns), S02 CEM data from the previous three days will be averaged and used as an emission factor to determine emissions from the FCC." Althoughthis CEMprovisionhas also beenprovided for Chevronrefinery, ithas notbeenprovided for Big West Oil refinery or Holly refinery. Please explain why two refineries should need this provision when two others apparently do not. Please also explain which S02 CEM at Tesoro refinery is being referred to. The only S02 CEM we are aware ofis the one at the SRU. We are not aware ofany reason why that CEM should be unavailable during abnormal conditions at the CO boiler, ESP, orFCC. Please also explain why it should be reasonable during abnormal conditions to rely on CEMS data from the previous three days. This approach does not account for the possibility that emissions might be higher during these abnormal conditions. Please also explain why special provisions for CEM unavailability should be necessary on a sourceby-source basis, considering that R307-170 already has provisions to account for CEM unavailability. 19. University ofUtah:

15This source in Salt Lake County did not have source-specific provisions inthe 200S PM10 SIP submittal. Nearly all emissions come from natural gas fired boilers in various buildings, ofwhich the largest boilers are in Building 302 (three boilers rated at 87.S MMBtulhr each) and Building 303 (three boilers rated at 1OS MMBtulhr each, and a combustionturbine withWHRU rated at 8S MMBtulhr).

• The proposed provisions consist ofthe following NOx emission limits:**~** Boilers #3 (sic)

- 2S lb/hr and 187 ppmdv**~** Boilers #4a & 4b

-- 3.0 lb/hr and 9 ppmdv for eachboiler**~** Boilers #Sa & Sb

-- 3.0 lb/hr and 9 ppmdv for eachboiler**~** Turbine and WHRU duct burner- 8.87lb/hr and 1S ppmdv The proposedprovisions were apparently carried over from the currentNSRpermit, dated June 2011, but with at least one apparent error. The limits of2Slb/hr and 187 ppmdvpertain to each ofBoilers 3-S inBuilding 303, not to "Boilers#3."

• The proposedprovisions require an "initial test" for Boilers #4a & 4b by 2018, and an "initial test" for Boilers #Sa & Sb by 2017. Since none oftheseboilers are listed in the currentNSR or title V permit, it appears thatthe proposedprovisions are allowing for addition offour new boilers ofunspecified size andtype. Therefore, it appears that the proposed provisions represent an increase (not reduction) from 2008 baseline emissions. Please explain how an emission increase could constitute RACT.

• The proposedprovisions specify that "Unit#3" (whichEPA assumes is Boiler#3 in Building 303, butthis is unclear) shall only be used as a backup/peaking boiler after January 1, 2019, butthat ifit is replaced with a "low-NOx boiler(s)", it may be used continuously. Please explainhowthis provision couldbe considered a reduction from 2008 baseline emissions. Please also explain why a date laterthanthe PM2.S attainment date of2014 has been included, and why advancing the date would be unreasonable.

• Please explain why the proposed provisions do not include any emission limits for the boilers in Building 302, nor the boilers inBuildings 

### SSS & 

### SS6, nor the boilers in Buildings S21/S2S/S26. Under the currentNSRpermit, the boilers inthese other buildings are allowed to consume more natural gas fuel annually than the boilers in Building 303, and therefore appear to account for the majority ofNOx emissions atthe University:**~** Boilers in Building 303

-- 12S MMSCF/yr**~** Boilers inBuilding 302- 8S8 MMSCF/yr**~** Boilers in Buildings 

### SSS & 

### SS6- 212.1 MMSCF/yr**~** Boilers in Buildings S21/S2S/S26- 200 MMSCF/yr Ofparticular note is that the boilers in Building 302 are allowed to use nearly seventimes as much fuel annually as the boilers inBuilding 303. Althoughthe currentNSRpermit does not have emission limits for the boilers inbuildings otherthan 303, please explain why the boilers at those otherbuildings should notbe subjectto RACT review and

16emission orconsumption limits (or at least the boilers in Building 302, which apparently account for the most emissions). The proposedprovisions do not specify any stack test methods, nor any recordkeeping or reporting requirements. 20. Brigham Young University:

• This reviewtakes into account the recent corrections to the proposed provisions, which are part ofthe "Updated SIP Documentation" onthe state's website. The largest emitting units are six central heating plantboilers. Boilers #1, #4 and #6 are natural gas fired. Boilers #2, #3 and #5 are coal fired. EPA notes that the proposed NOx emission limits of 5.44 lblhr and 30 ppm at Boiler#1 are more stringentthan the limits in the current NSR permit (dated June of2012), which are 9.55 lblhr and 95 ppm. However, the proposed provisions say that Boiler# 1 shall only be operated as a backup boiler to Boilers #4 and #6, and shall not be operated more than 300 hours perrolling 12-monthperiod. The proposedprovisions go onto say that ifBoiler#1 is operated more than 300 hours, then low-NOx burners withFGR shall be installed and tested. Given that Boiler#1 is operated only as a backup boiler, please explain whether the proposed newemission limits for Boiler#1 would result in any reduction from 2008 baseline emissions.

• Please explain why the proposedprovisions do not include any ofthe following emission limits or otherrequirements that have been in effect in NSRpermits dating back to 2004 orearlier:**~** NOx emission limits in lblhr and ppmdv for each ofBoilers #2, 3 and 5**~** PM 10 emission limits of 1.83 lblhr and 0.010 gr/dscffor the Central Heating Plant Baghouse.**~** Limits on sulfur content in coal and fuel oil

• The proposedprovisions do not specify any stack test methods, nor any recordkeeping or reporting requirements. 21. GenevaNitrogen:

• The proposed provisions consist ofNOx emission limits of32.4 lblhr and 267.0 ppmdv at the Montecatini Acid Plant Vent, and 19.4lblhrand 438.0 ppmdv at the Weatherly Acid Plant Vent. Also proposed is a PM 10 emission limit of0.24 tons/day at the Prill Tower. These provisions are carried overfrom the current NSRpermit, issued in 2003. The 2005 PM 10 SIP submittal specified 0.389 tons/day NOx at the Montecatini Acid Plant Vent, 0.233 tons/day NOx at the Weatherly Acid Plant Vent, and 0.24 tons/day PM10 at the Prill Tower. The proposed lblhr limits are equivalentto the tons/day limits at both acid plants that were inthe 2005 and 2011 SIP submittals. The proposed provisions therefore do not appearto represent a reduction from 2008 baseline emissions.

17The proposedprovisions do not specify any stacktest methods, nor any recordkeeping or reporting requirements. 22. Pacific States Cast Iron Pipe: The proposedprovisions include a PM 10 emissionlimit of0.015 gr/dscfat the cupola baghouse. Please explain whether this proposed limit mightrepresent a reduction from 2008 baseline emissions ofPM10, considering thatthe facility is not currently subject to any PM10 emission limits. EPA is not aware ofany plans to upgrade the baghouse, or do anything else to reduce the current PM10 emissions.

• The proposed provisions also include a plantwide VOC emissionlimit of260 tons per rolling 12-monthperiod. Monthly VOC emissions are to be determined from records of VOC emitting materials used each month, the amount ofVOC reclaimed each month, and the estimated amount ofVOC emitted monthly from combustionprocesses. The currentNSRpermit includes a VOC emission limit of355 tons perrolling 12-month period, for combined emissions from the cupola, pipe coating, and related operations. This limit has been inNSRpermits for this facility dating backto 2005 or earlier. Since the proposed new limit of260 tons is substantially lower, the new limitpotentially represents a substantial reduction from 2008 baseline emissions ofVOC. However, EPA notes that daily VOC emissions inTable 6.3 onpage 54 ofthe Utah County SIP narrative (which represents "growth and control") are projectedto increase from 0.515 tons per day in 2008 to 0.759 tons per day in 2019. Please explain whetherthe proposedreduction in the emission limit is factored into these emissionprojections. Please be aware that ifa reduction in emissions is factored into the emissionprojections used for 24-hourNAAQS attainment modeling, the reduction would need to be reflected in a short-term (daily) limit. Please also explain whetherthe required manner ofshowing compliance withthe proposed new limit is intendedto include cupolaemissions as one ofthe "combustion processes."

• The currentNSRpermit also includes aNOx emission limit for the cupolabaghouse of33 lbs/hr and a S02emission limit of0.23 lb/ton ofironmelted. Please explain why these limits are not included inthe proposedprovisions as RACT. The cupolabaghouse is the main emitting point at the facility.

• The proposedprovisions also include a requirement to propose a PM2.s emission limit, within 120 days after the stacktesting at the cupolabaghouse, which is due by January 1, 2015 (afterthe 2014 PM2 .5 attainment date). Please explain why advancing this date would be unreasonable.

• The proposedprovisions do not specify the stack testmethod for PM10 atthe cupola baghouse, nor any recordkeeping orreporting requirements for stack tests

..

1823. PacifiCorp Lakeside PowerPlant:

• Block 1ofthe plantbegan operating by September of2007. Block 2 was later permitted. The EPA does notknow whether Block 2 has begun operating, but the Statehas included Block2 as well as Block 1inthe proposedprovisions. Please explain whether Block 2 is nowoperating and whether Block 2 has been included in the 2008 baseline emissions inventory, and/or inthe projection inventory for the PM2.s nonattainment area.

• The proposedprovisions consist ofa PM2.s emission limit of 10.8 lb/hr (including condensables) for each ofthe two Block 1combustionturbines, a PM2.s emission limit of 14lb/hr(including condensables) for each ofthetwo Block 2 combustionturbines, a VOC emission limit of2.8 ppmdv at each ofthe Block 2 combustionturbines, and aNOx emissionlimit oftwo ppmdv at each ofthe Block 1 and 2 turbines. These proposed limits are the same as inthe currentNSRpermit, dated February 2012, for the overall facility. The limits reflect PSD BACT and majorNAA LAER from the initial NSR permits (dated Jan. 2005 for Block 1and May 2011 for Block 2), which EPA reviewed in detail when they were in draft. EPA has no concerns with the proposed limits.

• EPA is concerned about the director's discretion provisionrelated to the test method for VOCs- "orothertesting methods approved bythe Director"- and the lack of recordkeeping and reporting requirements. 24. Payson City Power:

• Theproposedprovisions are the same as inthe 2005 PM10 SIP submittal, with respect to short-term emission limits and associated enforceability provisions. The only emission limit inthe proposedprovisions is aNOx limit of 1.54 tons per day, from the operation of all engines combined.

• The currentNSRpermit, dated September of 1996, contains performance-based NOx emission limits, in grams perkW-hr, for each offour engines. Limits are 4.96 grams/kW-hr at two engines, 7.60 grams/kW-hr at a third engine, and 8.76 grams/kW-hr at the fourth engine. Please explain why these limits should notbe included as part of RACT.

• The proposedprovisions do not specify the stack test method for NOx, nor any recordkeeping orreporting requirements for the daily mass emission limit for NOx. 25. Provo City Power:

• The proposedprovisions are the same as in the 2005 PM 10 SIP submittal, with respect to short-term emission limits and associated enforceability provisions. The only emission limit in the proposedprovisions is a NOx limit of2.45 tons per day, from the operation of all engines and boilers combined.

19• The current NSRpermit, dated December of2004, contains performance-basedNOx emission limits, in gramslkW-hr and ppmdv, for each oftheboilers and engines. The NSRlimits are 1.46 gramslkW-hr and 155 ppmdv at each oftwo boilers, and 10.4 grams/kW-hr and 1,660 ppmdv ateachoffour engines. Please explain why these emission limits, covering the main emitting units atthe facility, should not be included as part ofRACT.

• The proposed provisions do not specify the stacktest method for NOx, nor any recordkeeping orreporting requirements for the daily mass emission limit for NOx. 26. Springville City Corporation:

• The proposedprovisions are the same as in the 2005 PM10 SIP submittal, withrespect to short-term emission limits and associated enforceability provisions. The only emission limit in the proposedprovisions is aNOx limit of 1.68 tons per day, from the operation of all engines combined.

• The currentNSRpermit, dated December of2003, contains performance-basedNOx emission limits, in lb/hr and gramslkW-hr for each ofseven engines. Limits are 27.00 lb/hr and 2.50 grams/kW-hr at the four Enterprise engines, and 24.00 lb/hr and 4.90 gramslkW-hr at each ofthe three General Motors EMD engines. Please explainwhy these emission limits, covering the main emitting units at the facility, should notbe included as part ofRACT.

• The proposed provisions lack sufficientrecordkeeping and reporting requirements.

20ATTACHMENT 4 EPA Region 8 Comments on Chapter5: "Utah State Implementation Plan Control Measures for Area and Point Sources, Fine ParticulateMatter, PM2.5 SIP for the Salt Lake, Utah, and Logan, UT-ID NonattainmentArea 1. Page 41, section 5.8: Giventhat the unmonitored area analysis (UAA) functionality in MATS is not yet available, we understand that UDAQ proposes to use the approach described in the modeling protocol to complete the unmonitored area analysis in lieu ofMATS. As discussed at ourteleconference on October 25th, we understand that the state plans to submit this analysis at a later date. EPA will need additional time to review and comment on the UAA after it is submitted. 2. Chapter 5: Note that EPA is commenting onthe CMAQ TSD, and Chapter 5 will need to be revised to be consistent with the final CMAQ TSD. 3. Additionally, UDAQ is using the MATS software for the model attainment test, but UDAQ does not make it clear whatmodeling episodes they are using in MATS. The implication in the text is that all three modeling episodes discussed are used; however, speciated model performance is only discussed for one ofthe episodes. This discrepancy makes it unclear what is being used in MATS. UDAQ should clarify this. 4. The model attainment demonstration must include any banked emissions credits. Fromthe description ofthe modeling, it is not clearifbanked emissions were included in the modeling. The description ofthe emissions scenarios should specifically identify by species, location and layer any banked emissions. 5. The modeled attainment test needs to consider all monitoredbaseline design values. Table 5.3 is incomplete and should also include Cottonwood and Highland monitors, since these have valid 2006-2010 baseline design values; the modeled attainment test needs to include these sites as well as those shown. Comments onthe MATS Technical Support Document 1. We note that the model attainment demonstration does not show attainment ofthe NAAQS at two monitor sites by 2019. The Hawthorne monitor future design value is 35.9 ug/m3 and the Lindon monitor future design value is 39.5 ug/m3. What are Utah'splans for augmenting the control strategy and re-running the model? Will this occurbefore Utah finalizes the SIP and submits itto us? 2. High wind dust event dataimpacts the baseline design value for several sites, and EPA may notbe able to concuronthis flagged datainthe near future. Therefore, the non-concurred monitor concentrations should be included inthe attainment demonstration. EPA's guidance document "Updateto the 24 HourPM2.5 NAAQS Modeled Attainment Test" dated June 28t\ 2011 addresses seasonal aspects ofthe model attainment demonstration that should be used to evaluate the projected future design value given exceedances in other seasons.

13. The "2008 Observed" column oftables 1, 2 and 3 ofSection4.'d shouldbe the baseline design values oftable 3.2 ofthe Salt Lake City SIP narrative; several oftheentries in section 4.d do not match the values intable 3.2; EPA believes the table 3.2 values are correct, and the section4.d values are incorrect. 4. Page 1 last paragraph and page 2 first paragraph: Itis unclear exactly what datasets DAQ are using. Please include a table where DAQ lists datasets thatbeing used, particularly, which model episodes. For example: Data FRM data STN data CMAQ Model Years 2006-2010 2008 Episode dates

... Use BDV (Baseline design value) BDV Speciation RRF 5. When reading DAQ's documentation, there were some unanswered questions as follows: (1) Why only use STN data from 2008, why not as many years as available? (2) Ifonlythe one episode Dec 13 2009- Jan 20 2010 was used for CMAQ modeling, why were the othertwo periods that had acceptable model performance notused? The modeling protocol listed four episodes that would be evaluated and only one was removed because ofpoormodel performance; ifonly one ofthe 4 episodes inthe modeling protocol was used for the RRF development, the reasons the two additional episodes were not used for RRF developmentneeds to be explained in the TSD. (3) Forthe FRM data, were there any days outside ofthe cold season that effected the BDV calculation? To provide clarity and allow evaluation, the TSD needs to address these questions. 6. Page 2, second paragraph: What MATS is doing with regard to the RRF calculationis a little hard to follow in the text. Please clarify the text. For example, the text says that for the base year MATS takes the top 35% ofmodeled PM2.5 days (is this regardless ofthe monitored values?), and takes the highest PM2.5 value in a 3x3 grid around the monitor. MATS also does this for the future year scenario. However, it is unclear ifMATS necessarily uses the same days in the base and future year. 7. Also, please list the range ofthe 35% highest PM2.5 values from the baseline modeling period and compare that to the 35% highest PM2.5 values from the monitor. 8. Page 2 last paragraph: EPA has some clarifying questions related to the PM2.5 speciation data DAQ used. (1) Was all ofthe STN dataused for BDV speciation from the cold seasons? (2) The top 10% ofSTN data was used, but DAQ does not say how many data points this was. Was the sample size adequate and representative ofthe PM2.5 values during exceedances? Please edit the TSD to address these questions. Comments on CMAQ Model Performance EvaluationTSD 1. Table 5.3 ofthe Salt Lake City SIP narrative shows an "attainment inventory" 2019 concentration for the Salt Lake City Hawthorne monitor of34.8 ug/m3, which appears to attain

2the NAAQS. This "attainment inventory" concentration is not explained in the SIP Narrative, and is not addressed at all inthe TSD. 2. Table 5.3 ofthe Provo SIP Narrative shows an "attainment inventory" 2019 concentration for the Salt Lake City Hawthorne monitor of35.2 ug/m3, which appears to attain the NAAQS. This "attainment inventory" concentration is not explained inthe SIP Narrative, and is not addressed at all in the TSD. 3. A detailed description ofthe baseline and control basket emissions scenarios is needed for each non-attainment area. For example, a description ofemissions by source category, species, and county for each ofthe baseline and control basket scenarios is needed to showhow emissions have changed overtime. Forthe attainment inventories, a description is needed ofthe emissions reductions estimated for each source category. 4. Page 5: Page 5 section 1.1.3: Please include additional explanation ofthe choice of0.55 albedo. Snowcover and albedo are important areas ofuncertainty both for the current modeling and future modeling efforts. Forthe current modeling, we recommend including a more specific description ofconditions during winter PM2.5 episodes, e.g.: Surface albedo can range from 0.05 for ground with no snowcoverto 0.9 for conditions with complete snow coverage. An average albedo value of0.55 was used to represent typical or average conditions with partial snow cover during winter PM2.5 episodes. 5. Page 7: Vertical advection deactivated. We recommend including in the weight ofevidence analysis a comparison ofrelative response factors with and without vertical advection. This will help in determining how much ofan effect the use ofvertical advection has on the model attainment demonstration. 6. Page 7: AmmoniaInventory Adjustments. We recommend adding some information describing the effect ofthe added ammonia onthe model NH3 concentration and how this compared with the available NH3 measurements. 7. Page 8 section 1.2, secondparagraph (and all other areas where model performance is discussed): The mainpurpose ofthis report should be to support the attainment demonstration, so it is recommended that model performance be shown for (1) all monitors that will drive the attainment demonstration calculation, (2) elevated PM2.5 concentrations representative of conditions that drive PM exceedances, (3) all episodes that will be used in the RRF calculation, and (4) all relevant chemical species needed for the attainment demonstration. We recommend that model performance for the above be 'walled off' from otherperformance analyses DAQ might perform as part ofa more general model performance analyses. Plotting the performance for all ofthe above is not as important as providing the tabulated performance statistics. Perhaps DAQ could provideplots for a representative subset ofthe data as well as the tabulated statistics for all. Specifically, interms ofmonitors (e.g., item (1)), this means all FRMs for which an attainment demo is needed and all STN monitors for which chemical speciation will be used. ForPM2.5 concentrations (item (2)), determine some PM2.5 cut point below which DAQ will not include the data. This will be a balancing act, to have a cutpointthat gives DAQ enough

3data for meaningful statistics while still being representative ofconditions that lead to elevated PM2.5. For episodes (item (3) in comment #7), it is currently not clear inthis document which episodes will be used for the attainment demonstration. There were 4 episodes discussed inthe modeling protocol, but in the TSD the focus is mainly onthe 4th (which has many episodes withinit). One ofthe episodes was removed due to poormodel performance, but what ofthe othertwo episodes? Will they be part ofthe attainment demonstration? Forchemical species (item (4) in comment#7), that's PM2.5 and the SANDWICH species (N03, S04,NH4, OC, EC, crustal). Again, this does not include other additional model performance analyses DAQ might want to do, similar to what DAQ did for the indicatorratios. 8. Page 13, Figure 1.8 and similar figures: Itwould be helpfulto addthe comparable 24 hour modeled value to see the comparisonbetter. 9. Page 19, first paragraph: 'Table 1.3' in text shouldbe 'Table 1.2'. 10. Page 28: Forthe secondary PM2.5 Precursor Performance we recommend including in an Appendix the ozone, CO, NO andN02 hourly comparison ofmodel and data for all monitors (as was shown in Figures 1.33- 1.35 for the Hawthorne site). Itwould be useful to also include a set ofplots comparing monitoredNOx=NO+N02 to modeledNOx=NO+N02 and to modeled total NOy. Becausethe NOx measurement from the chemiluminescentmethod detects some fraction ofotherNOy species, such as PAN, HN03 and organic nitrates, the measuredNOx should be boundedby the modeledNOx and NOy. 11. In the quoted text below strike through text is used to indicate corrections to grammar with suggested text shown in bold font. Page 28: "This overnight spike in NO may be due to an unknown local emission source or due to meteorological phenomenonthat is not understood and thereby by replicated therefore not well represented inthe meteorological modeling." 12. Page 28 Section 1.2.2, second paragraph: The 'bettermodel performance' for these species is not apparent from the time series plots. We recommend providing the performance statistics. Also, the colors inthe plots make ithard to distinguish the different values. 13. Page 29 section 1.2.3, last paragraph (and first onnext page): Improved model performance is not apparent; we recommend DAQ provide the performance statistics. 14. Page 30, figure 1.36: Y axis label should read 'CO'. 15. Page 32, section 1.4.1: Itis unclear ifthese scenarios will be used as part ofthemodeling for the attainment demo. Ifthey will, then it doesn'tmake sense to separatethem outfrom the general discussion ofmodel performance. Ifthey will notbe used for the attainment demo, then DAQ couldjustprovide the performance statistics (as per first main comment above) rather than plots.

416. Page 32: "The sensitivities 

### v1ill be were performed on the 2008 inventory and the 2019 inventory that has incorporated emissionreduction control strategies." 17. Page 37: Reversing the presumptive exclusion ofVOC. Page 37 includes the following text: Based on air quality modeling and other supporting information (see Section 1.4.3), Utah is proposing to reverse the presumptive exclusion ofVOC as a PM2.5 precursor. The attainment demonstration Utah has provided includes a combination ofVOC and NOx reductions to control ammonium nitrate, as well as reductions ofdirect PM2.5 and S02. This demonstration includes an evaluation oftechnically and economically feasible control measures to demonstrate expeditious attainment ofthe PM2.5 NAAQS. However, Page 34 includes this text: Much ofemission control strategy planningby UDAQ focused on the results ofthe sensitivities to the 2008 Inventory. That is, strategies that dealt with the benefit ofVOC reductions and avoided the dis-benefit ofNOxcontrols. The 2019 Control Inventory was recently developed; thereby the 2019 sensitivities are recent results. The 2019 Control Inventory sensitivity results will lead UDAQ to explore strategies that involve future year NOxreductions. We recognize that the ratio ofVOC and NOx emissions will change overtime, and that this affects ambient ratios ofVOC to NOx as well as the effectiveness ofVOC and NOx emissions reductions. Given the complex and evolving response ofthe model PM2.5 sensitivity to VOC and NOx, it will be challenging to identify the optimal mix ofVOC and NOx control strategies to achieve the most effective and expeditious reduction ofPM2.5. Additional model sensitivity simulations using the 2014 Control Basket scenario are required to further evaluate model PM2.5 sensitivity to additional reductions in emissions ofVOC and NOx in 2014 and to determine if additional NOx orVOC emissions reductions would result in additional progress in reducing PM2.5. 18. Page 55, first paragraph: Here and below, it appears DAQ is overstating the datato discuss 'trends'. DAQ can still discuss the year to year change in the data, but it is not apparent that there is enough data here to establish trends. 19. Weight ofEvidence discussion oftrends in Cache County: the EPA modeling guidance discusses that a weight ofevidence analysis is often necessary to augment the modeled prediction ofattainment, given the uncertain nature ofinput generation and chemistry for the very complex scientific issue ofsecondarypollutant formation. The guidance states (p. 98 of http://www.epa.gov/ttn/scram/guidance/guide/final-03-pm-rh-guidance.pdf) that "Supplemental evidence should accompany all model attainment demonstrations. Generally, those modeling analyses that showthat attainment will be reached in the future with some margin ofsafety (e.g., estimated concentrations below 82 ppb for ozone, 14.5 ug/m3 for annual PM2.5, and 62 ug/m3 for 24-hourPM2.5) will need more limited supporting material. Forother attainment cases, in which the projected future

5design value is closer to theNAAQS, more rigorous supporting analyses shouldbe completed." On page 99 ofthe guidance: "There are three basic types ofanalyses that are recommended to supplementthe primary modeling analysis. They are: 1) Additional modeling 2) Analyses oftrends in ambient air quality and emissions 3) Observational models and diagnostic analyses" For the Cache Valley, analysis oftrends in ambient air quality may present some issues. The figure below shows the long term datatrends for 98th percentile 24-hour PM2.5, the trend in 3 year PM2.5 design value, and the trend in 5 year Baseline DesignValue (BDV) used for modeled base year concentration:

01998 

## Logan historical 98th percentile, Design Value and Baseline DV PM2.5

2000 2002 2004 2006 2008 2010 2012 -98th 

### -ov -BDV

Examination ofthe trend, particularly withrespectto the five yearperiod from 2006 through 2010 used to establishthe BDV for modeling, shows thatthe 2006 through 2010 period includes two ofthe lowest 98th percentile values in the 11 year data set, and thatthose low values result in the 2008 centered BDV being the lowest inthe 11 yearperiod. The 98th percentile values inthe period 2008 through 2011 all lie above the 2008 centered BDV, indicating PM2.5 since 2008 has
6generally been greater thanthat observed on average inthe 2006 through 2010 BDV period used for modeled attainment. This could suggest that the controls included in the SIP may not be adequate to result in actual (monitored) attainment by 2014, contraryto what is indicated by the model. Further evaluation and discussion ofthis trend in a weight ofevidence discussion could be used to counterthis potential vulnerability inthe modeled attainment. For example, Utah could discuss the ability ofthe SIP controls to meet attainment even withhigher baseline design values, such as the 41.8 ug/m3 BDV for 2007-2011 (or Utah could use MATS to assess the RRF using these higher BDVs).

7ATTACHMENT 5 EPA Region 8 Comments on RACT Discussion in SIP Narratives DAQ-072-12 and DAQ074-12 and RACT Technical SupportDocument The PM2.5 SIP narrative does not contain an analysis or supporting information on RACT for the specific regulated pollutants for the relevant stationary sources. EPA had previously written to the State to explain its expectations based onthe PM2.5 Implementation Rule as to what an approvable RACT analysis for each source should include. (Ref: Email dated September 13, 2011, with attachment dated September 12,2011, from MonicaMorales ofEPA to Dave McNeill ofUDAQ.) Generally, these expectations have not been met in the Technical Support Document. Comments on RACT Technical Support Document: General comments:**~** The State has presented RACT analyses in the TSD for 33 sources (26 in Salt Lake County and 7 inUtah County). It appears that the RACT analyses for the 33 sources were preparedprimarily bythe sources, not bythe State. Six sources were apparently dropped from the list of34 sources that appears inthe Salt Lake County SIP narrative. The six that were dropped are: Clean Harbors Aragonite, Clean Harbors Grassy Mountain, Deseret Chemical Depot, Dugway Proving Ground, Hill Air Force Base (UTTR), and US Magnesium. Please provide an explanation as to why these sources were dropped.**~** Two sources included inthe RACT TSD do nothave RACT analyses (Interstate Brick and SilverEagle Refining). Instead, the TSD indicates that synthetic minor status has been established for Interstate Brick, and will shortly be established for SilverEagle Refining, to relieve them ofthe requirement for source-specific RACT.**~** Fornearly all ofthe RACT analyses, either no sources ofinformation on RACT are cited, orelse the only source ofinformation cited is EPA's RACT/BACT/LAER Clearinghouse (RBLC). This is not sufficient to support the RACT analyses (see September 13, 2011 email from MonicaMorales). Also, for many ofthe analyses, there is no indication whethermore than one RACT option was considered, and no cost information is presented. In the RACT analyses where multiple options are presented and costs are also presented, there is no indicationhowthe costs were calculated. For some sources, the chosen RACT options are notreflected in the proposed source-specific provisions in DAQ-075-12.**~** Please see attached reports by EC/Rfor additional concerns and recommendations on howto improve the RACT analyses. 1. ATK Launch Systems: ATKreviewed RACT options for PM, S02, NOx and VOC from their boilers, engines, mobile sources, and fugitive emissions. ATK does not propose any new

1controls. ATK's RACT analysis says they already use ultra low sulfur fuel oil intheir boilers, engines and mobile sources. With regard to openburning/testing ofwaste propellants, energetics andpyrotechnics, ATK says they are currently in the process ofconducting an openburning risk assessment under the direction ofthe State'sDivision ofSolid and Hazardous Waste (DSHW), and that openburning limits will be determined and imposedby a DSHWpermit whenthe risk assessment process is completed. ATK's proposal to only address RACT for openburning after a risk assessmentprocess is completed is not consistent withwhat the State has proposed as source-specificprovisions for ATKinthe document DAQE-075-12. Forthe period from November 1to February 28 annually, the State is proposing to limit openburning to 50% ofthe daily limit inthe DSHWpermit, when PM2

_ 5 levels exceed 35 ug/m3 atthe nearest real-time monitoring station, and to limittesting of propellant, energetics, pyrotechnics, flares and otherreactive compounds to 2,400 lbs of propellantper item during these periods, as well as prohibit testing ofrocket motors less than 1 million lbs ofpropellantpermotor during these periods. (This last provision is confusing. What about rocket motors larger than 1million lbs ofpropellantpermotor?) As we noted in our comments on draft Sections IX.H.12 and IX.H.13, these proposedprovisions are inconsistent with the CAA and EPA'sregulations on dispersion techniques and intermittent control systems (40 CFR 51.118 and 51.119) and are not creditable for purposes of demonstrating attainment or meeting RACT requirements. They are not a substitute for continuous emissions limits/controls. In addressing RACT for ATK, the State will need to explain: • Howthe State'sproposed source-specific provisions constitute RACT. The SIP or TSD needs to include an analysis oftechnical and economic feasibility. • Whether the State considered other alternatives, such as transporting waste outside ofthe NAA before burning it, and/or minimizing the amount ofwaste to be burned. • The pollutants addressed by the State'sproposal. • Whether the State'sproposal represents a reduction from 2008 baseline emissions, and if so, how the reduction was calculated. What emissionrate was assumed for the projection years out to 2019? • Whether the State's proposal could change afterthe risk assessment mentionedby ATK is completed and whether it is appropriate for the RACT determination to await/depend onthat risk assessment. 2. Big West/Flying JRefinery: We have asked EC/Rto reviewthis RACT analysis. In the meantime, we have the following preliminary comments: For PM control, Big West Oil (BWO) is proposing to install additional controls on their MilliSecond Catalytic Cracking (MSCC) Unitby fall of2015. BWO expects to achieve about 42 tons per year ofreduction in PM emissions by year 2016. How was this calculated? A table included in BWO's analysis indicates only a 29 tonperyear expected reduction inPM2.5, to be achieved between 2017 and 2019. Please explainthe discrepancy intiming and amount. The State must

2 

## ...also explain whether any other RACT options were considered and howit was determined that the proposed RACT is the lowest achievable based ontechnical and economic feasiblility. For S02, BWO is proposing to start using DeSOx additives with their catalyst at the MSCC Unit, to achieve betterthan 90 percent

## so2 control and emissions below 25 ppm 

## so2 in catalyst regenerator flue gas, resulting in a reduction of252 tons per year ofS02 emissions. BWO is also proposing to install additional fuel-gas treating technology (caustic scrubbing) that can be used during planned or unplanned outages ofthe Amine or Sulfur Recovery Units. BWO indicates this technology could reduce S02 emissions by an average of50 tons peryear. The total potential reductions are therefore about 302 tons per year. Howwas this calculated? A table included in BWO's analysis indicates only a 150 tonper year expectedreduction in S02, to be achieved between 2017 and 2019. Please explain this discrepancy. Please also explain why an earliertimeline would be unreasonable. The State must also explain whether any other RACT options were considered and howit was determined that the proposed RACT is the best achievable based ontechnical and economic feasibility. ForNOx, BWO is proposing to retrofit three existing plant boilers with Ultra Low-NOx Burners, to achieve a NOx emissionrate of0.035 lb/MMBtu or less. This is expected by BWO to achieve aNOx reduction ofabout 30 tons peryearbefore the end of2013. Howwas this calculated? A table included in BWO's analysis indicates an expected reduction of52 tons per year, to be achieved between 2017 and 2019. Please explain the discrepancy in timing and amount. The State must also explain whether it has examined the source's RACT analysis and confirm that all available RACT options were considered and how it was determined that the proposed RACT achieves the lowest emissions based on technical and economic feasibility. ForVOC, BWO is proposing to adopt more stringent leak definitions in its LDARmonitoring program, before the end of2013, consistent with recent refinery consent decrees and NSPS Subpart GGG. The definition ofleaking valve would drop from 10,000 ppm to 500 ppm. The definition ofleaking pump seal would drop from 10,000 ppmto 2,000 ppm. This is expected by BWO to result in as much as a 100 tonper year VOC emissionreduction for valves and 30 tons peryear reduction for pumps. The total potential reductions are therefore about 130 tons per year. Howwas this calculated? A table included in BWO's analysis indicates an expected reduction of 152 tons peryear, to be achieved between 2017 and 2019. Please explain the discrepancy in timing and amount. The State must also explain whether any other RACT options were considered and how it was determined that the proposed RACT achieves the lowest emissions based on technical and economic feasibility. Finally, none ofthese commitments for emissionreductions are reflected inthe source-specific provisions proposed for BWO in the document DAQE-075-12. There is no explanation why not. The provisions in that document appearto be the same as inthe 2005 PM10 SIP submittal, with respect to daily emission limits and associated enforceabilityprovisions. None ofthese commitments for newemission reductions are reflected in the General Requirements for refineries either. Please explain why these are not in the source-specificprovisions. 3. Bountiful City Light & Power: The RACT analysis only discusses two new combustion turbines and concludes that current controls are RACT for all pollutants. The two new turbines

3are currently limited in the NSRpermitto 15 ppm and 7.5lb/hrofNOxperturbine. A third turbine which already exists is limited to 0.6 grams/kW-hr ofNOx. The RACT analysis indicates there is also a dual-fuel IC engine #8 on site, butpresents no RACT discussion for it. The currentNSRpermithas no emission limits for that engine. Please provide a RACT discussion for that engine, or else provide ajustificationfor no RACT discussion. Also, the currentNSR permit lists five dual-fuel IC engines #2-6, to be replaced at some pointby the two newturbines, but the RACT analysis only mentions one IC engine. Please explainthis discrepancy. Have these engines beenreplaced? The RACT analysis does not identify any RACT option otherthan current controls, nor does it present any explanation why current controls shouldbe considered RACT. The State must explain whether it has examinedthe source's RACT analysis and confirmthat all available RACT options were considered and how it was determinedthatthe proposedRACT achieves the lowest emissions based ontechnical and economic feasibility. Also, since the currentNSRand title V permits list only one turbine at the facility, the proposed provisions appear to represent an increase from 2008 baseline emissions, by allowing for two new combustionturbines. A table included in the RACT analysis indicates that starting in 2014, PM2.s emissions will triple, S02emissions will nearly double, NOx emissions will more than quadruple, and VOC emissions will be nearly six times as high as 2008 baseline emissions. The RACT analysis indicates that withthe new turbines, the facility will operate on a more aggressive production schedule than previously. Please explain whetherthese substantial emission increases are accounted for in the attainment demonstration. In separate comments on Section IX.H.12 ofDAQE-075-12, EPA finds that the proposed sourcespecific provisions in Section IX.H.12.c for Bountiful, which consist ofNOx emission limits at the three combustion turbines, are not enforceable, as there are no enforceabilityprovisions. EPA also comments that it'snot clear why a fuel restriction to natural gas from the currentNSR permit has not been included inthe proposedprovisions. Also, engine #8 is not addressed inthe proposed provisions. The currentNSRpermit limits use ofengine #8 to 1,600 hours per year. 4. Brigham Young University: Please see attached report by EC/Rfor discussion ofthis RACT analysis. The following are additional comments from EPA: BYU operates three natural gas fired and three coal fired hot water generators (HWGs). Since BYU is not permitted to bumcoal during winter months (November 1through February 28), BYU did a RACT review only for the gas-fired HWGs. BYU claims that use ofnatural gas constitutes RACT for PM10, PM2.s, S02 and VOC. Current emissions ofeach ofthose pollutants at BYU are below 1ton for winter months. ForNOx, BYU evaluated four RACT options at HWG1 and four options at HWG4 and 6. BYU calculated the cost-effectiveness at HWG1to range from $5,400/ton for the cheapest option (replace existing burners with low-NOx burners and no FGR) to $7,819/ton for the most expensive option (replace burner spudtips and add 18% FGR). ExpectedNOx reduction for the cheapest option was about 6 tons during winter months (about a 45% reduction from current winter emissions of 13.87 tons).

4BYU calculated the cost-effectiveness at HWG4 and 6 to range from $4,668/ton for the cheapest option (replace burner spud tips and add 18% FGR) to $7,232/ton for the most expensive option (install ultra low-NOx burners and add 30% FGR). Expected NOx reduction for the cheapest option was about 13 tons perHWG during winter months (about a 65% reduction from current winter emissions of 16.86 tons at each HWG). BYU concluded that the cost effectiveness ofall NOx control options was too high tojustify as RACT. EPA has concerns about this conclusion and whether it isjustified. BYU also evaluated VOC RACT for their landfill, which is subjectto NSPS (40 CFR40 Part 60 Subpart WWW), but is not required under Subpart WWWto install a non-methane organic carbon collection and control system. BYU states that it installed a control system ofits own accord, with an estimated VOC control efficiency ofabout 80%. The captured gas is either routed to Hill Air Force Base to generate electricity, or is combusted in an enclosed flare. VOC destruction efficiency at the flare is estimated by BYU to be 99%. BYU concluded that this is RACT for VOCs at the landfill. Reported VOC emissions from the landfill were about 5 tons in 2011. Please explain whether any control systems can achieve betterthan 80% control and why 80% control should constitute RACT. The State must explain whether it has examined the source's RACT analysis and confirm that all available RACT options were considered and how it was determined that the proposed RACT achieves the lowest emissions based on technical and economic feasibility. BYU also evaluated RACT for PM at the landfill and concluded that RACT is their current practice, which involves application ofwater and dust suppressants such as magnesium chloride as needed for dust suppression, minimizing the extent ofdisturbed ground, establishing vegetation on disturbed ground as soon as practical, sweeping ofpaved roads, and minimizing dirt track-out from the landfill onto the paved road sections. BYU also evaluated RACT for mobile sources and concluded that RACT is their currentpractice ofpurchasing equipment which is either Tier 4 Transitional orTier 4 compliant. Again, the State must explain whether it has examinedthe source's RACT analysis and confirm that all available RACT options were considered and how it was determined that the proposed RACT achieves the lowest emissions based on technical and economic feasibility. The State has not proposed any source-specific provisions to make BYU's current practices, emission limits and fuel consumption limits enforceable. The current NSRpermit ihcludes NOx emission limits, in lblhr and ppmdv, for the three natural gas fired boilers that are allowed to operate in winter months, as well as a natural gas consumption limit of405 MMSCF perrolling 12-monthperiod, and a restriction to natural gas as fuel at HWGs #1, #4 and #6. HWGs #4 and #6 are also limited to a 10% annual capacity factor (i.e., no more than 876 hours ofoperation in a 12-monthperiod). 5. Central Valley Water Reclamation: The RACT analysis indicates that the digesters were redesigned in 2011, resulting in a VOC emissionreduction of85%. There is no indication how muchreduction this was in tons peryear. The RACT analysis indicates that the composting

5process was also redesigned in 2011, resulting in a VOC emissionreduction ofabout 95%, or about 36.4 tons per year ofreduction. Since VOC emissions from composting were not accounted for inthe 2008 emission inventory, the annual VOC emissions are estimatedto drop by only about 18 tons from 2008 to 2014. No change in emissions ofany other pollutants is projected afterthe 2008 baseline year. The facility's proposal for RACT basically consists only ofa work practice requirementto "remove the biosolids from the facility," or in the alternative to "Implement a Director approved composting process (active phase)," or to "Implement a Director approved alternative mitigation measure not listed above." This proposedrequirement is apparently new, not carried over from any existing rules orNSRpermits. No explanationhas beenprovidedhowthis proposed requirement might further reduce emissions from 2008 baseline, or howthisrequirement might relate to emissions at all. Also, the proposedrequirement includes "director's discretion" language. EPA has explained previously why director's discretion provisions are not approvable in SIPs. The State must explain whether it has examinedthe source's RACT analysis and confirm whether all available RACT options were considered and how itwas determinedthatthe proposed RACT achieves the lowest emissions based ontechnical and economic feasibility. None ofthe provisions from the currentNSRpermit, nor from the 2005 PM10 SIP submittal, are proposed as RACT. The currentNSRpermit includes NOx emission limits, in lb!hr and grams per hp-hr, for three internal combustion engines and four backup generators, as well as the same tons-per-day facilitywide NOx limit as the 2005 SIP submittal, as well as rolling 12-monthNOx limits for the engines and for the backup generators. Please explain why such limits are not evaluated inthe RACT analysis. 6. CER Generation: This facility consists offive combustionturbines. The RACT analysis indicates that the BACTILAER emission limits for NOx inthe original2002 constructionpermit should satisfy RACT. The limits cited are: 5 ppmdv for eachturbine, on a 30-dayrolling average, under steady state operation (not including startup and shutdown); 100 ppmdv notto be exceeded at any time; and 37 lblhr for the total ofall five turbines, on a 30-day rolling average under steady state operation (not including startup and shutdown). No emissionreduction from 2008 baseline is projected. The only emission limit proposedby the State is aNOx limit of0.44 tons perday, for the total of all five turbines. This is numerically equivalentto the 37 lblhr in the currentNSRpermit. The State must explain whether it has examined the source's RACT analysis and confirm that all available RACT options were considered andhow it was determined that the proposed RACT achieves the lowest emissions based ontechnical and economic feasibility. As part ofthis effort, the State should analyze whether there have been advancements in control measures for turbines since the construction permit was issued. Please explainwhy no other limits from the NSR permit are proposed as part ofRACT. Also, please be aware that we interpret the CAA as not allowing exceptions to SIP limits during startup and shutdown. 7. Chemical Lime Company

- Grantsville Plant: We have asked EC/Rto review Chemical Lime for RACT. Inthe meantime, we have the following preliminary comments: After a

6screening ofRACTpossibilities throughout the facility, the RACT analysis focuses on possible upgrade ofemission controls at the rotary kiln for PM 10, PM2
.5, NOx, VOC and S02 , and possible upgrade offugitive dust controls on unpaved roads. PM control options for the rotary kiln included cyclone separators, spray towers, venturi scrubber, fabric filter baghouses, and electrostatic precipitators. NOx control options for the rotary kiln included SCR, SNCR, LNB and good combustionpractices. A search ofthe RBLC was conducted for entries for lime kilns for each control option. The analysis for the rotary kiln concluded that RACT is the following: PM10 and PM2.s --use ofexisting electroscrubber control device (75% control efficiency) NOx- existing NOx limit in permit of75.00 lb/hr

### + good combustionpractices VOC- good combustionpractices and burner maintenance (existing practice) so2- inherent so2 control ofthe lime with no add-on controls (existing practice) The analysis for unpaved roads concluded that RACT is use ofwater as a control measure at the present coverage rates (estimated at 70% control). The State has proposed emission limits for PMro of 1.32 lb/hr and 0.060 gr/dscfat the Hydrator Baghouse, and 24.78 lb/hr and 0.19 gr/dscfat the Kiln Electroscrubber. The proposed emission limits forNOx are 75.00 lb/hr and 650 ppm at the Kiln Electroscrubber. These limits are the same as in the currentNSRpermit, issued in 2006. The State must explain whether it has examined the source's RACT analysis and confirm that all RACT options were considered and howit was determined that the proposed RACT is the lowest achievable based on technical and economic feasibility. 8. Chevron SLC Refinery: Please see attached report by EC/R for discussion ofthis RACT analysis. 9. Geneva Rock Products, Point-of-Mountain: Please see attached area source comment on R307-312, Aggregate Processing Operations

.. 10. Great Salt Lake Minerals: We have asked EC/Rto review GSLM for RACT. In the meantime, we have the following preliminary comments: The format ofthis RACT analysis consists entirely oftables, and the RACT review for each emitting unit consists ofonly a couple ofsentences. Formost ofthe emitting units, the key sentence is that "There are no "vendor guaranteed" controls options applicable to this process which could exceed the measured emissionrate for this unit." This statement does not make sense. We would expect it to be the reverse, i.e., that there are no vendor guarantees for an emission rate lower than the measured emission rate for this unit. The State must explain whether it has examined the source's RACT analysis and confirm that all available RACT options were considered and how it was determined that the proposed RACT achieves the lowest emissions based ontechnical and economic feasibility. 11. Hill AirForce Base- Main Base: The RACT analysis says only that emissions shall not exceed applicable requirements in40 CFR 60, 62 and 63 or any effective applicable state requirements in R307-401 (the state'sNSRpermitting rule). There is no analysis ofthe technical or economic feasibility ofany potential emissionreductions. This is insufficient for a RACT

7analysis. All potential RACT options should be identified and an explanationpresented onhow it was determined that the proposed RACT achieves the lowest emissions based ontechnical and economic feasibility. 12. Holly Refinery: We have asked EC/Rto review this RACT analysis. 13. Kennecott PowerPlant/Lab/Tailings Impoundment: Please see attachedreportby EC/R for discussion ofthis RACT analysis. 14. Kennecott Smelter and Refinery: Please see attached report by EC/Rfor discussion ofthis RACT analysis. 15. Pacific States Cast Iron Pipe: We have asked EC/Rto reviewthis RACT analysis. In the meantime, we have the following preliminary comments: The RACT analysis discusses numerous RACT options for PM2.5, S02, NOx and VOC at the cupola, annealing oven, and special lining shotblast, butthe only source ofRACT information mentioned is the RBLC, and no cost information is presented for any options. The State must explain whether ithas examined the RACT analysis and confirmthat all available RACT options were considered and how it was determined that the proposed RACT achieves the lowest emissions based ontechnical and economic feasibility. 16. Tesoro SLC Refinery: Please see attached reportby EC/Rfor discussion ofthisRACT analysis. 17. Proctor and Gamble PaperManufacturing Plant: We have asked EC/Rto reviewProctor and Gamble for RACT. In the meantime, we have the following preliminary comments: In brief, the RACT analysis asserts that the BACT evaluations inthe 2007 application for anNSR permit for initial plant construction (issued February 20, 2008) shouldbe adequate to serve as a RACT analysis (with the possible exception ofPMz.5). The only sources ofinformation cited in the RACT analysis are the prior BACT analysis andthe RBLC. While there is some discussion ofcontrol options, only one cost figure is mentioned ($23,000/ton for a venturi scrubber system for the process stack for a paper machine). The State needs to certify thatithas checked the RBLC and other appropriate sources ofinformation on control technologies. Ifthe State then concludes that the 2008 BACT determination constitutes RACT, the State needs to certify inthe SIP or TSD that there are no better controls than those adopted by P&Gthat wouldbe technically and economically feasible, and that the BACT analysis canbe relied upon as the RACT analysis, for those pollutants covered in the BACT analysis. We also note that the RACT analysis only proposes anemission limit of6.65 lblhr for PM10, at each ofthe two paper machines, and a commitmentto propose a

### PMz.s emissionlimitby January 1, 2015. Please explain why an earliertimeline wouldbe unreasonable. Also, we note that the proposal does not include NOx emission limits from the currentNSRpermit at the four boilers and two paper machines, although the RACT analysis mentions that such limits existinthe NSR permit. Please explain why no NOx emission limits are proposed as part ofRACT.

8Also, we note that the NSRpermit lists the potential to emit for VOC at 213 tons peryear. A RACT review for VOC would seem warranted. Please provide such a RACT analysis or explain whythe RACT analysis does not address VOC. 18. University ofUtah: We have asked EC/Rto review this RACT analysis. In the meantime, we have the following preliminary comments: The analysis presents a "strategy" for managing the University's air quality impact, consisting ofan "aggressive energy conservationprogram" in existing buildings, reducing the heating capacity at Building 303 by replacing three 105 MMBtulhrboilers with six 40 MMBtulhrboilers, and an undefined "study" ofthree boilers in Building 302. One RACT option for PM2.s control, one option for S02 control, one option for VOC control, and three options for NOx control are presented, Costs are presented only for NOx control. There is no indication whetherthe costs presented are capital costs orannualized costs, nor howthe costs were calculated, nor what sources ofinformation were used to identify RACT options for any pollutant. Foreach RACT option, there are headings for "Technical Feasibility," "Economic Feasibility," and "Approximate Cost," but for some ofthese headings there is no text. This RACT analysis therefore appears to be a work in progress. The State must explain whether ithas examined the RACT analysis and confirm that all available RACT options were considered and how it was determined that the proposed RACT achieves the lowest emissions based ontechnical and economic feasibility. 19. The following sources are still under review: Great SaltLake Minerals; Big West/Flying J Refinery; Hexcel; Hollyrefinery, Kennecott Bingham Canyon Mine and Copperton Concentrator; Murray City Power; Nucor Steel; Olympia Sales Company; Pacific States Cast Iron Pipe; Pacificorp Gadsby PowerPlant; Pacificorp Lakeside Power Plant; Pacificorp EnergyLittle Mountain Power Plant; Payson City Power; Pepperidge Farm; Proctor & Gamble Paper Manufacturing Plant; Provo City Power; University ofUtah; Utility Trailer; Vulcraft; Wasatch Integrated Waste Management; Springville City Corporation. We are awaiting RACTreports from EC/R on Big West/Flying J Refinery; Chemical Lime- Grantsville; Great Salt Lake Minerals; Holly Refinery; Pacific States Cast Iron Pipe; Proctor and Gamble; and University of Utah.

9Brigham Young University CentralHeating Plant Evaluation ofRACTAnalysis

This document evaluates the reasonably available control technology (RACT) analysis1 prepared for Brigham Young University (BYU) Central Heating Plant in Utah and included in the DraftTechnical Support Document (TSD) for the Utah PM2.5 State ImplementationPlan (SIP). SUMMARY OFRACT ANALYSIS Facility description BYU operates six (6) hot water generators (HWGs)/boilers attheir central heating plant. HWGs 1, 4, and 6 bum natural gas with fuel oil backup and HWGs 2, 3 and 5 bumcoal except during the wintermonths (November 1ending February 28/29), when these units are permittedto bumnatural gas or fuel oil only. BYU does not provide any information or analysis for HWGs 2, 3, and 5, eventhough these units appear to operate and bum natural gas during the winter (similar to HWGs 1, 4 and 6). Table 1provides the annual emissions in tons from this facility based on the Utah 2008 emission inventor!. Table 1. Brigham Young University 2008 AnnualEmissions in Tons
PM2.s NOx 

### voc SOx 2.24 163.00 6.49 122.32
Emission sources The emission sources evaluated in the BYU RACT analysis include (emissions based on unit's potential to emit (PTE) during winter months only): • HWG 1- natural gas fired boilerrated at 64 MMBTU/hr (13.87 tons NOx); • HWG 4- natural gas fired boiler rated at 192 MMBTU/hr (16.86 tons NOx); • HWG 6- natural gas fired boilerrated at 192 MMBTU/hr (16.86 tons NOx). Emission sources included in EC/R's evaluation This evaluation ofthe BYURACT analysis will be restrictedto HWGs 1, 4 and 6, and will only focus on emission ofNOx because it is the primary pollutant emitted from natural gas combustion. Emission sources excluded from EC/R'sevaluation HWGs 2, 3 and 5 will not be evaluated because BYU did not provide any information or analysis for these units to allow for an independent evaluation. However, it appears thatthese units are in operation during the winter and bum natural gas, which generates emissions ofNOx, a PM2.5precursor.

SUPPLEMENTALDATA SOURCES

1Control Strategies for Brigham Young University. Undated; contained in the Draft TSD for PM25Attainment SIPs, Section 5, Control Strategies, available for public comment 10/1/2012

- 11/112012. Available at: http://www.airguality.utah.gov/Public-Interest/Current-lssues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 20 12/index.html 2 Utah Statewide Emission Inventory for Point Sources. Available at : http://www.airguality.utah.gov/Planning/Emission-Inventory/2008 State/08 State List.htm 10Table 2 provides NOx control technologies for natural gas fired boilers from EPA sources. The control technologies identified in Table 2 apply to boilers with heat input capacities ranging from 0.4 to 1,500 MMBtulhr. Table2. NOx Control TechnologiesIdentified for Natural Gas-fired Boilers

Control Cost ControlTechnology Effectiveness Reference Efficiency ($/ton NOx) SCA (staged combustion air, 17-46% 210-240 ACT for ICI includes BOOS and OF A) Boilers3

, CoST 4 Flue Gas Recirculation 53-74% ACT for ICI (FGRt Boilers, CoST LowNOx burners (LNB) 50% 820 CoST, ACT for ICI boilers LNB+FGR 60% 2,560 CoST, ACT for ICI boilers Oxygen Trim and Water CoST, ACT for Injection (OT/WI) 65% 680 ICI boilers Selective Catalytic 90% 2,366 CoST, ACT for Reduction (SCR) ICI boilers SelectiveNon-Catalytic 50% 3,870 CoST, ACT for Reduction (SNCR) ICI boilers *All costs and control efficiencies are from the first reference listed. • Cost information for FGR alone is not provided in CoST or ACT for ICI boilers. BYU did not evaluate OT/WI, SCR or SNCRin their analysis ofpotential RACT options for reduction of NOx boileremissions. FINDINGS New RACT identified in the BYU analysis No additional measures were identified in the BYU analysis as RACT because no additional controls evaluated were determinedto be cost-effective. Adequacy ofdata A full RACT analysis for this source is not provided. The following are examples ofareas where the RACT analysis in the TSD does not provide adequate data: • All costs are unsupported; • The control efficiencies and emissionreductions (in tons per year) ofpotential control options are notprovided;

3 Alternative Control Techniques Document-- NO Emissions from x Industrial/Commercial/Institutional (ICI) Boilers. US EPA. EPA-453/R-94-022. March 1994. ("ACT for ICI Boilers") 4 Cost information was taken from EPA's CMDB (Control Measures Database) for Stationary Sources used in the Control Strategy Tool (CoST). A fully functional version ofCoST was developed in 2008. The CMDB is available for download at: http://www.epa.gov/ttnecasl!cost.htm. All costs in table 2 are for "small" sources, which are undefined in the CoST database, but equate to larger cost effectiveness values due to lower potential for emission reductions. 11• The review ofpotential control measures is not sufficientbecause Tesoro did not evaluate all appropriate RACT options (e.g., OT/WI, SCR, or SNCRfor HWG 1, 4, and 6). Cost effectiveness HWGJ BYU identified the following controls and cost effectiveness values for HWG 1: • FGR at $7,819/ton NOx; • LNB at $5,400/tonNOx; • LNB and FGR at $6,245/ton NOx; • ULNB and FGR at $7,000/ton NOx; HWG4or6 BYU identified the following controls and cost effectiveness values for HWG 4 or 6: • FGR at $4,668/tonNOx; • LNB at $6,387/tonNOx; • LNB and FGR at $6,124/ton NOx; • ULNB and FGRat $7,232/ton NOx It appears that BYU only evaluatedthe costeffectiveness ofcontrols with respectto wintertime emissions. However, as described in EPA'sApri125, 2007 PM2.5 implementationrule (72 FR20594), "the cost effectiveness ofatechnology is its annualized cost($/year) divided by the emissions reduced (i.e., tons/year) which yields a cost per amount ofemission reduction ($/ton)". Therefore, BYU's costeffectiveness calculations should include the year-round emissions, including non-wintertime emissions (ifany). All cost-effectiveness values estimated by BYU are high as comparedwith the EPA costeffectiveness values in Table 2, which could be a result ofthe BYU calculations potentially including wintertime emissions only. Recommendations • Requestthe State to provide a full RACT analysis including supporting documentation (see attached RACT Analysis list). • Recommend further evaluation ofthe potential emission reductions and costs to install additional NOx controls on HWG 1, 4 and 6; including a review ofthe detailed cost analyses when this information is provided by BYU. Recommend an evaluation ofwhether HWG 2, 3, and 5 should be included in a RACT analysis.

12ChevronProducts Company Salt Lake Refinery Evaluation ofRACTAnalysis

This document evaluates the reasonably available control technology (RACT) analysis5 prepared for Chevron Products Company Salt Lake Refinery in Utah and included in the Draft Technical Support Document (TSD) for the Utah PM2.5 State Implementation Plan (SIP). Additional information to support this evaluation was taken from original RACTanalysis prepared by Chevron6 on May 16, 2012, which was summarized by the state in the Draft TSD. EVALUATION OFRACT ANALYSIS Facility description The Chevron refinery processes crude oil and hydrocarbon feedstocks into transportation fuels, petroleum coke, sulfur, and various byproducts. Table 1provides the annual emissions in tons from this facility based on the Utah 2008 emission inventor/, which matches the 2008 emissions specified in Chevron's May 16, 2012 analysis, and annual emissions for 2011 based on Chevron's May 16,2012 submittal. Table 1. ChevronRefinery 2008 and 2011 Annual Emissions in Tons Year PM2.s NOx 

### voc SOx 2008 85.66 946.03 221.32 591.84 2011 35 320 453 24 According to Chevron's May 16, 2012 RACT analysis, the reduction in emission between 2008 and 2011 is a result ofthe installation ofnumerous control technologies, including: a tail gas unit for the original sulfurrecovery unit (SRU), a redundant SRU with tail gas unit, upgrades to the FCC electrostatic precipitator (ESP), upgraded coolingtower controls, and installation ofvaporrecovery for sour flares. It should also be noted that there is a discrepancy between the PM2.5 emission in the TSD RACT analysis (156.7 tons peryear (tpy)) and the PM2.5emissions in the Utah 2008 emission inventory and Chevron's May 16,2012 RACT analysis (86 tpy). Emission sources The emission sources evaluated in the Chevron RACT analysis include: • Three (3) refinery fuel gas -fired boilers rated at 55.8 MMBTU/hr (Units 1and 2) and 54.1 MMBTU/hr (Unit 4); • Two (2) refinery fuel gas -fired boilers rated at 171 MMBTU/hr equipped with low nitrogen oxides (NOx) burners (LNB) (Units 5, and 6); • Four (4) cooling towers equipped with drift eliminators with a drift loss ofless than 0.01 percent;

5 Control Strategies for Chevron Products Company. Undated; contained in the Draft TSD for PM2.5Attainment SIPs, Section 5, Control Strategies, available for public comment 10/112012

- 11/112012. Available at: http://www.airguality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 20 12/index.html 6 Response to Request for Clarification on SIP RACT applicability and Discussion on UDAQ Needs- PM2.5, John C. Krogue, Environmental Team Lead, Chevron. May 16,2012. This document included a cover letter (as titled above) and a 119 page analysis. 7 Utah Statewide Emission Inventory for Point Sources. Available at : http://www.airquality.utah.gov/Planning/Emission-Inventory/2008 State/08 State List.htm 13• Refinery fuel gas-fired furnace rated at 130 MMBTU!hr equipped withLNB; • Refinery fuel gas-fired furnace rated at 115.1 MMBTU!hrequipped with LNB; • Fluid Catalytic Cracking Unit (FCCU) Regenerator, using an electrostatic precipitator (ESP), NOx and sulfur dioxide (S02 ) catalyst additives, and feedstock hydrotreatmentto control emissions; • Three (3) flares; • Fugitive emissions; • Three (3) rich burn reformer compressor engines rated at 16 MMBTU/hr each; • Two (2) sulfurplants consisting ofa sulfurrecovery unit (SRU), a tail gastreatmentunit (TGTU), and a tail gas incinerator (TGI); • Storagetanks; • Wastewatertreatment plant; • Reformer catalystregenerator. Emission sources included in EC/R's evaluation This evaluation ofthe Chevron RACT analysis will be restricted to the following emission units and pollutants: • BoilerUnits 1, 2 (potential to emit (PTE)= 138.1 tpy NOx) andUnit4 (PTE= 133.9 tpy NOx); • Fluid Catalytic Cracking Unit (FCCU) Regenerator (PTE= 101.6 tpy fine particulate matter (PM2s); 50 tpy S02; 100 tpy NOx); • Three rich burn reformer compressor engines (PTE= 159.2 tpy NOx each) Emission sources excluded from EC/R's evaluation Several emission sourcesthat were evaluated in the Chevron RACT analysis havebeen excludedfrom this analysis for various reasons. • BoilerUnits 5 and 6, the furnaces, the flares, the sulfurplants, andthe cooling towers will notbe evaluated because these sources have lowemissions comparedtothe sources identified above, are already controlled to some extent, and/orhave overall less potential for significantreductions in emissions. • Fugitive VOC emissions from equipment leaks (PTE= 690.8 tpy) will notbe evaluated because there is insufficient data onthe types ofequipmentcomponents and the currentLDARplan operated by the refinery to suggestmore stringent control options andworkpractices. In addition, Chevron currently complies with valve and pump leak definitions of500 ppm and 2,000 ppm, respectively, which are relatively strict comparedto current limitations at otherrefineries in Utah. • VOC emissions from the wastewatertreatmentplant (PTE= 139.3 tpy) and storage tanks (PTE= 272.7 tpy) will not be evaluated becausethere is inadequate data onthe types oftanks/equipment operated by the facility and the existing controls. In addition, VOC emissions from storagetanks and wastewatertreatment processes are already controlledto some extentby regenerative thermal oxidizers and are subjectto various NSPS andNESHAP requirements. SUPPLEMENTALDATA SOURCES BoilerUnits 1, 2 and 4 Table 2 provides NOx control technologies identified for refinery fuel gas-firedboilers from EPA sources.

14Table 2. NOx Control Technologies Identified for Refinery Fuel Gas-fired Boilers

Control Cost ControlTechnology Efficiency Effectiveness Reference ($/ton NOx) Oxygen Trim (OT) and 65 680 CoST8 Water Injection (WI) LowNOxburners (LNB) 50% 820 CoST LNB and over-fire air 60% 1,052 CoST (OFA) LNB and flue gas 60% 2,560 CoST recirculation (FGR) LNB and FGR and OFA 80% 1,278 CoST Selective Catalytic 80-90% 2,366- 2,933 CoST Reduction (SCRY Selective Non-Catalytic 40% 1,052 CoST Reduction (SNCR) a •Itis assumed that SCR and SNCRcontrols are applied with a combustiOn control (e.g., OFA). Chevron evaluated Ultra Low NOx burners (ULNB) and SCR in their RACT analysis, but did not evaluate any othertechnologies identified in Table 2. Chevron defined ULNBs as a combustion staging technology that includes flue gas recirculation (FGR). Fluid catalytic cracking unit (FCCU) regenerator Table 3 provides NOx control technologies identified for FCCU from EPA sources. Table 3. NOx Control Technologies Identified for Fluid Catalytic Cracking Units

Control Cost ControlTechnology Efficiency Effectiveness Reference ($/ton NOx) LNB andFGR 55% 2,470-3,190 CoST Selective Catalytic 90% 3,457 CoST Reduction (SCR) Furthercontrol technologies for reduction ofNOx emissions from FCCUs are provided in consent decrees established with mostUS refineries through EPA'srefinery initiative. The technologies required by these consent decrees, as summarized in the Emission Effects ofRefinery Cases and Settlements document 9; include: • SCRto achieve 20 ppmvd; • SNCR/optimize existing SNCR system;

8 Cost information was taken from EPA's CMDB (Control Measures Database) for Stationary Sources used in the Control Strategy Tool (CoST). A fully functional version ofCoST was developed in 2008. The CMDB is available for download at: http://www.epa.gov/ttnecasllcost.htm. All costs in table 2 represents costs for "small" sources, which are undefmed in the CoST database, but equate to larger cost effectiveness values due to lower potential for emission reductions. 9Including the Emission Effects ofRefmery Cases and Settlements in Projections for the EPA's CAAA Section 812 Analysis, E.H. Pechan & Associates. Available at: http://www.epa.gov/ttnchie1/conference/ei15/session4/wilson.pdf 15• Scrubber-based NOx emission reduction technology to achieve 20 ppmvd; • Low NOx CO combustion promoters • Catalyst additives • LoTOx system It should be noted that in the TSD RACT analysis for Tesoro Refinery10

, LNB is rejected as a potential control option because regeneratortemperatures are generally nothigh enough for significantthermal NOx formation. LNB stages the combustion process to reduce thermalNOx, which occurs in the high temperature flame zone nearthe burners. The EnvironmentAgency (EA), which is a British nondepartmental public body, published a document on oil and gas processes11 that supports Tesoro's conclusion thatthermal NOx from regenerators is not normally excessive due to lower operating temperatures. The EA document further states that fuel NOx can be significant. One potential RACT option for NOx control ofFCC regenerators that Chevron did notevaluate is selective non-catalytic reduction (SNCR). Inthe RACT analysis for the Tesoro refinery, SNCRwas evaluated for their FCC regenerator and consideredthis technology to betechnically feasible. The EA document also supports the use ofSNCR, and cites emission reductions of50-60%. In addition, Chevron did not evaluate a low temperature oxidation system (LoTOx), which was also considered a technically feasible control option in the RACT analysis for Tesoro Refinery that can achieve the highestNOx reduction levels ofall options identified, equivalentto SCR 6

. LoTOxwas also vetted by the California Air Resources Board (CARB) for use on a furnace flue gas stream and is described as a NOx removal system that injects ozone into the flue gas stream to oxidize insoluble NOxto soluble oxidized compounds 12• LoTOx requires installation ofa wet gas scrubber downstream. The following technologies for reduction ofS02 emissions from FCCU are required in multiple EPA consent decrees with refineries: • Wet gas scrubber to achieve 25 ppmvd; 

### • so2 catalyst additive; • Feedstock hydrotreating. Technologies for reduction ofPM emissions from FCCU identified inthe EA document include: • ESP; • Wet scrubbers; • Cyclones. The EA document also identifies bag filters (fabric filters), but states that this technology is notfavored for FCCU, which are particularly sensitive to the pressure drop changes associated with bag filters. The document also noted that cyclones are primarily used to remove largerparticles and have limited effectiveness on particle sizes ofPM10 and smaller. In the EA document, a wetscrubber is considered a best available technique (BAT) for SOx and PM control for FCCUs, especially when releases from bothpollutants are high.

10 Tesoro Refining and Marketing Compamy- Salt Lake City Refmery PM2.5 SIP RACT Template Submittal. Tesoro Refining and Marketing Compamy. September 24,2012. 11 Oil and Gas Processes Supplementary Guidance Note, IPC S3 1.02, Environment Agency. First published 2000. 12 Low Temperature Oxidation System CARB GrantNumber ICAT 99-2. California Air Resources Board (CARB). Webpage updated November 18,2005. Available at: http://www.arb.ca.gov/research/icat/projects/boc.htm 16Rich bum compressor engines As stated in the Chevron RACT analysis, the 4-stroke rich bum compressor engines are currently equipped with automated air-to-fuel ratio (APR) controls to optimize combustion efficiency and emission performance. Chevronevaluatedthe use ofNSCRfor additional NOx reduction. Itis assumed thatthe engines are natural gas-fired; however, the engine fuel type is not provided in the RACT analysis. Table 4 provides NOx control technologies identified for the compressor engines from EPA sources. Table 4. NOx Control Technologies Identified for Natural Gas-Fired Rich Burn Engines

Control Technology Control CostEffectiveness Reference Efficiency ($/ton NOx) Adjust air-to-fuel ratio 20% 380-1,570 CoST, ACT (APR) for RICE13 Ignition timing retard (IR) 20% 550-1,020 CoST, ACT for RICE Adjust APR and IR 30% 460-1,440 CoST, ACT for RICE Low Emission 87% 380-1,680 CoST, ACT Combustion (LEC) for RICE Prestratsified charge (PSC) 87% 150-300 ACT for RICE NSCR 90% 521 CoST, ACT for RICE *All costs and control efficrencres are from CoST, except PSC data rs from ACT for RJCE Chevron only evaluated NSCR and APR for the compressor engines, and did not consider any ofthe other control technologies identified in Table 4. FINDINGS Sources ofRACT information Chevron only referenced one source ofRACT information in their analysis, the RACT/BACT/LAER Clearinghouse (RBLC) database. NewRACT identified in the Chevron analysis Inthe RACT analysis, Chevron states thatthey will install non-selective catalytic reduction (NSCR) on each ofthe compressor engines "within one year ofthe date ofentry ofthe pending draft agreement with the EPA". Adequacy ofdata A full RACT analysis for this source is not provided in the TSD. The RACT analysis provided by the state in the TSD does not include all ofthe information found in the May 16, 2012 RACT analysis provided by Chevron. The following are examples ofareas where the RACT analysis in the TSD does not provide adequate data: • Costs ofcontrols and cost effectiveness values are unsupported; • The size and emissions ofboilerUnits 1, 2 and 4 are not provided;

13 Alternative Control Techniques Document-- NOx Emissions from Stationary Reciprocating Internal Combustion Engines, US EPA, EPA453R-93032. July 1993. 17• The emissions from the cooling towers are not provided; • A table on page 19 ofthe analysis appears to be out ofplace or missing inthe "Results of Analysis" section; • The fuel type ofthe compressorengines and emissions from the engines are not provided; • The review ofpotential control measures is not sufficientbecause Chevron did not evaluate all appropriate RACT options (e.g., OT/WI and SNCRfor boilerUnits 1, 2 and 4; LoTOx and SNCR for FCCU; and IR, LEC and PSC for the compressor engines). Cost effectiveness Boiler Units 1, 2 and4 Chevron identified the following controls and cost-effectiveness values for boilerUnits 1, 2 and 4: • ULNB for Unit 1and 2 at $2,831/ton NOx and ULNB for Unit 4 at $2,917/tonNOx; • SCRfor Unit 1and 2 at $2,608/tonNOx and SCRfor Unit4 at 2,695/tonNOx. The cost effectiveness values identified by Chevron in their RACT analysis are similar as compared with the EPA values shown in Table 2, Chevron identified ULNB and SCRfor all units as technically feasible; however, these technologies are rejected on the basis thatthey are economically unreasonable (i.e., not cost effective). In the May 16, 2012 RACT analysis provided by Chevron, Chevronasserts that PM2.5precursors do not correlate directly to emissions ofPM25, and NOx and S02 emissions from Chevron SaltLake Refinery sources do not significantly contribute to PM2.5concentrations in nonattainment areas. Chevron concludes that PM25 $/ton cost effectiveness may be ten (10) times more costly than what was calculated as the $/ton cost effectiveness for the PM2.5precursors. However, as described in EPA's April25, 2007 PM2.5 implementation rule (72 FR20594), "States are required to address NOx as a PM2.5 attainmentplan precursor and evaluate feasonable controls for NOx in PM2.5 attainment plans, unless the State and EPA make a finding that NOx emissions from sources in the State do not significantly contribute to PM25 concentrations in the relevant nonattainment area." Fluidcatalytic cracking unit (FCCU) regenerator Chevron identified the following controls and cost effectiveness values for the FCCU: • Wet gas scrubber at $16,021/ton PM 10 and $17,409/ton PM2 5; • Wet gas scrubber at $35,374/ton S02; • SCR at $8,205/ton NOx. The cost effectiveness value identified by Chevron for SCR appears high as compared with the EPA value in Table 3 ($3,457/ton NOx)· Chevron dismissed all ofthe potential control options identified above on the basis that they are economically unreasonable. Rich burn compressor engines Chevron identified airto fuel ratio controls and NSCRat $876/ton NOx for each rich bum compressor engine. The cost effectiveness of$876/tonNOx is only slightly higherthan the EPA value provided in Table 4 ($521/ton NOx). Chevron stated thatthey would agreeto install NSCR, although they asserted that NSCR is economically unreasonable. Recommendations • Request the State to provide a full RACT analysis including supporting documentation (see attached RACT Analysis list). • Based on the Chevron RACT analysis, SCRfor boilerUnits 1, 2 and 4 maybe RACT due to technical feasibility and cost effectiveness less than $2,700/ton. 18• Recommend further evaluation ofthe costto install a wet gas scrubber for control ofPM and S02 emissionsfrom the FCCU; including a review ofthedetailed cost analysis submitted by Chevron (May 16, 2012) and a review ofFCCU rules adopted by state and local agencies. Recommend further evaluation ofthe cost to install SCR for control ofNOx emissions from the FCCU; including a review ofthe detailed cost analysis submitted by Chevron (May 16, 2012) and a review of FCCU rules adopted by state and local agencies.

19KennecottUtah CopperLLC PowerPlant Evaluation ofRACTAnalysis

This document evaluates the reasonably available control technology (RACT) analysis14 prepared for Kennecott Utah Copper (KUC) for their facility in Utah and included in the DraftTechnical Support Document (TSD) for the Utah PM2.5 State Implementation Plan (SIP). SUMMARY OFRACT ANALYSIS Facility description The KUC facility includes a tailings impoundment, power plant and laboratory. The powerplant supplies powerto KUC operations and the laboratory is used to perform tests for permitting compliance and operations optimization. Table 1provides the annual emissions in tons from this facility based on the Utah 2008 emission inventory 15• Table 1. KennecottPowerPlantAnnual Emissions in Tons PM2.s NOx 

### voc SOx 38.90 2,555.18 14.72 3,144.97 Emission sources The emission sources evaluated in the KUC RACT analysis include: • Three (3) wall natural gas and coal-fired boilers rated at 431.4 MMBTU/hr (coal) and 453 MMBTU/hr (natural gas) equipped with low NOx burners (LNB) and electrostatic precipitators (ESP) (Units 1through 3); • One (1) tangential natural gas and coal-fired boilerrated at 838 MMBTU/hr (coal) and 872 MMBTU/hr (natural gas) equipped with an ESP (Unit 4); • Four (4) noncontact water cooling towers equipped with drift eliminators with drift loss rated at 0.002 percent; • Natural gas-fired space heaters rated at less than 5 MMBTU/hr ea. equipped with LNB; • Fugitive dust emissions from wind erosion ofthe tailings embankment; controlled by a dust control plan. Emission sources included in EC/R's evaluation This evaluation ofthe KUC RACT analysis will include Unit 4. Emission sources excluded from EC/R's evaluation Several emission sources that were evaluated in the KUC RACT analysis have been excluded from this analysis for various reasons. • Units 1, 2 and 3 were not evaluated because they are slated to be replaced by a natural-gas fired combustion turbine (275 MW). KUC plans to limit emissions from the turbine through installation ofdry lowNOx combustors, selective catalytic reduction, and catalytic oxidation.

14 RACT Determinations for the Utah Power Plant, Tailings and Laboratory, CH2M HILL. August, 2012; contained in the Draft TSD for PM25Attainment SIPs, Section 5, Control Strategies, available for public comment 10/1/2012- 1111/2012. Available at: http://www.airquality.utah.gov/Public-lnterest/Current-Issues/pm2.5/SIPTSD/TSD for Public Comment 10-1-2012/index.html 15 Utah Statewide Emission Inventory for Point Sources. Available at : http://www.airquality.utah.gov/Planning/Emission-Inventory/2008 State/08 State List.htrn 20• Fournoncontact water coolingtowers, natural gas fired space heaters, and fugitive dust emissions from wind erosion ofthe tailings embankment were not evaluated because these sources have low emissions comparedto Unit4, are already controlled to some extent, and have overall less potential for significant reductions in emissions. The New Source Review (NSR) permit16 for the KUC facility restricts Unit 4 to only burning natural gas during the winter (i.e., November I to the last day in February on the following year). Because the draft Utah SIP (August 27, 2012) characterizes PM2.5 exceedances in Utah nonattainment areas as a winter problem, the analysis ofUnit 4 will be restricted to NOx, which is the primary pollutant from the combustion ofnatural gas. However, any additional controls identified in this analysis for NOx reduction may also apply to coal-fired boilers to allow for use ofthe technology year-round. SUPPLEMENTALDATA SOURCES Table 2 provides NOx control technologies identified for natural gas and coal-fired boilers from EPA sources. The control technologies identified in Table 2 apply to boilers with heat input capacities ranging from 0.4 to 1,500 MMBtu/hr. Table 2. NOx Control Technologies Identified for Natural Gas/Coal-fired Boilers

Control Cost Control Technology Efficiency3 Effectiveness Reference Notes ($/ton NOx) 3 SCA (staged combustion ACT for ICI Assumes air, includes BOOS, biased B '1 17 watertube boiler 17-46% 01 ers , firing or over-fire air CoST18 (OFA)) LowNOx burners (LNB) 50% 1,090 CoST, ACT Assumes coalfor ICI boilers fired boiler LNB andOFA 65% 306 CoST, ACT Assumes coalfor ICI boilers fired boiler Selective Catalytic 90% 2,366 CoST, ACT Assumes natural Reduction (SCR)b for ICI boilers gas-fired Selective Non-Catalytic 50% 1,570 CoST, ACT Assumes natural Reduction (SNCR)b for ICI boilers gas-fired

aThe control efficiency and from the first reference hsted. bIt is assumed that SCR and SNCR controls are applied with a combustion control (e.g., OFA).

16 State ofUtah DEQ Approval OrderNumber DAQE-AN105720026-11. December 1, 2011. 17Alternative Control Techniques Document-- NO Emissions from x IndustriaVCommerciaVInstitutional (ICI) Boilers. US EPA. EPA-453/R-94-022. March 1994. ("ACT for ICI Boilers") 18 Cost information was taken from EPA's CMDB (Control Measures Database) for Stationary Sources used in the Control Strategy Tool (CoST). A fuiJy functional version ofCoST was developed in 2008. The CMDB is available for download at: http://www.epa.gov/ttnecasl/cost.htm. 21FINDINGS RACT identified in the KUC analysis KUC identified the following controls as RACT in their analysis. • Addition ofLNB with OFA for Unit 4 at an estimated cost effectiveness of$1,231/ton. KUC estimates that 421 tons peryearreduction in NOx could be achieved by implementation ofthis control based on Unit 4's PTE. • Addition ofLNB with OFA was also identified as RACT for Units 1, 2 and 3 at an estimated cost effectiveness of$2,876/ton, however, these units are slated to be replaced. Adequacy ofdata A full RACT analysis for this source is not provided (e.g., insufficient data for cost calculations: the analysis states that costs and time ofinstallation are based on estimates from "CH2M Hill's Power Group", but no supporting data is given). Cost effectiveness KUC identified the following controls, control efficiencies, and cost-effectiveness values for Unit 4: • LNB with OFA at 38% control efficiency and $1,231/ton; • LNB with OFA and SNCRat 53% control efficiency and $1,517 /ton; • LNB with OFA and SCR at 82% control efficiency and $2,087/ton. Although the control efficiencies and cost-effectiveness values identified by KUC in theirRACT analysis differ somewhat as compared with EPA values shown in Table 2, all scenarios appearto be cost effective. While KUC identifies SNCR and SCRas economically feasible, these post-combustion controls are rejected on the basis that it will take three years for design and installation, and this is "beyondthe EPA guidance time frame ofone year andtherefore

....are chronologically infeasible". Recommendations • Requestthe State to provide a full RACT analysis including supporting documentation (see attached RACT Analysis list). • Based on the KUC RACT analysis, LNB with OFA and SCRappears to be RACT due to the reasonable cost effectiveness. Regarding KUC's point of"chronologically infeasible", request the State to determine whetherthese measures are necessary for attainment as expeditiously as practicable. The State may exclude those reasonable measures that, considered collectively, would not advancethe attainment date by at least one year (PM2.5 implementation rule at 72 FR20617).

22Kennecott Smelter and Refinery Evaluation ofRACTAnalysis

This document evaluates the reasonably available control technology (RACT) analysis 19 prepared for Kennecott Utah Copper (KUC) LLC Smelter and Refinery in Utah and included in the Draft Technical SupportDocument (TSD) for the Utah PM2.5 State Implementation Plan (SIP). SUMMARY OFRACTANALYSIS Facility description The KUC facility includes a refinery, smelter and molybdenum autoclave process (MAP). At the smelter, copper concentrates are processed by flash smelting and converting furnaces. The 99.5 percent pure copper is sentto the refinery where the copper is fused to a steel sheet to form a copperplate. The facility includes over 74 individual emission sources. Table 1provides the annual emissions in tons from this facility based on the Utah 2008 emission inventory20• Table 1. Kennecott Smelterand Refinery 2008 Annual Emissions in Tons

PMz.s NO, 

## voc so, 149.52 154.25 8.66 970.08
Emission sources The emission sources evaluated in the KUC RACT analysis are provided below. Refinerysources: • Natural gas fired boilers are rated at 82 MMBtu/hr each, emissions ofNOx are limited with Flue Gas Recirculation and Low NOx burners (LNB); • Combined heat and power (CHP) unit with a duct burner equipped with LNB and a turbine equipped with SoLoNOx burners; • Diesel-fired emergency generator equipped with turbo chargers and after coolers; • Natural gas-fired space heaters equipped with LNB rated at< 5 MMBTU/hr each; • Noncontactwater cooling towers equipped with drift eliminators with drift loss rated at 0.002 percent; • Precious metals recovery scrubber. Smelter sources: • PowerhouseHolmanboilerrated at 187 MMBTU/hr; • Main Stack: includes the matte granulator, slag granulator, acid plant, powerhouse, furnaces, dryers and grinding circuits, each ofthese sources ofemissions have their primary control devices (baghouse, scrubbers, etc.); • Diesel-fired emergency generators equipped with turbo chargers and after coolers;

19 RACT Determinations for the Refinery, Smelter and Molybdenum Autoclave Process, CH2MHILL, August 2012.; contained in the Draft TSD for PM2.5Attainment SIPs, Section 5, Control Strategies, available for public comment 10/112012- 1111/2012. Available at: http://www.airquality.utah.gov/Public-Interest/Current1ssues/pm2.5/SIP-TSD/TSD for Public Comment I0-1-2012/index.html 20 Utah Statewide Emission Inventory for Point Sources. Available at : http://www.airquality.utah.gov/Planning/Emission-Inventory/2008 State/08 State List.htm 23• Wet feed baghouse that controls particulate emissions from the loading ofwet flux and concentrate and from transfer points ofthe conveyor; • Slag and matte granulators vented through a stack with a wet scrubber; • Feed storage building, stores wetcopper concentrate feed in an enclosed building, particulate emissions are vented to a baghouse; • Three noncontact water cooling towers equipped with drift eliminators with drift loss rated at 0.006 percent; • Anode area fugitives; • Smelter fugitives. MAP sources: • Combined Heat and Power (CHP) unit with a duct burner equipped with LNB and a turbine equipped with SoLoNOxburners; • Product drying, storage, packing, and reagent storage, vented through a baghouse. Emission sources included in EC/R's evaluation This evaluation ofthe KUC RACT analysis will be restricted to the following emission units and pollutants (the combined emissions from all pollutants for each source are included from the KUC RACT analysis and represent the potential to emit (PTE) in tons peryear (tpy)): • Refinery and MAP combined heat and powerunits (46.5 tpy and 39.77 tpy combined total emissions, respectively) • Powerhouse Holman boiler (52.8 tpy combined total emissions) • Main stack (1,411 tpy combinedtotal emissions) • Smelter fugitives (157 tpy combined total emissions) Emission sources excluded from EC/R's evaluation All emission sources atthe KUC plantthat were not identified as being included in EC/R's analysis above have been excluded from this evaluation because these sources have low emissions comparedtothe sources identified above, are already controlled to some extent, and/or have overall less potential for significant reductions in emissions. SUPPLEMENTALDATA SOURCES Refine1y and MAP combined heat and power (CHP) units Table 2 provides NOx control technologies identified for natural gas-fired turbine cogenerationunits from EPA sources. The KUC analysis does not identify the fuel source ofthe CHP units, which is assumed to be natural gas in this evaluation.

24Table 2. NOx Control Technologies Identified forNatural Gas-fired Turbine Cogeneration Units

Control Technology Control Cost Effectiveness Reference Efficiency ($/ton NOx) LNB 68% 490 CoST 21 Steam injection 80% 1040 CoST Water injection 76% 1,510 CoST SCRandLNB 95% 2,470 CoST SCR and steam injection 95% 2,010 CoST SCRand water injection 95% 2,730 CoST KUC identifies the existing controls on each CHP unit (i.e., LNB on duct burner and SoLoNOx on turbine) as RACT, and does not evaluate any ofthe other potential RACT options identified in Table 2. SoLoNOxtechnology is a form ofstaged combustion or LNB used to control NOx emissions from natural gas fired turbines. Powerhouse Holman boiler The New Source Review permit for the KUC facility22 identifies the Powerhouse Holman boiler as a natural gas-fired boilerrated at 187 MMBTU/hr. Table 3 provides NOx control technologies identified for natural gas fired boilers from EPA sources. All controls in Table 3 apply to sources that are I00 MMBTU/hr or larger.
Table 3. NOx Control Technologies Identified for Natural Gas-fired Boilers

Control Cost ControlTechnology Efficiency Effectiveness Reference ($/ton NOx) SCA (staged combustion air, 17-46% 210-240 ACT for ICI includes BOOS and OFA) Boilers23

, CoST Flue Gas Recirculation 55-76% ACT for ICJ (FGRt - Boilers, CoST Low NOxBurners (LNB) 50% 820 CoST, ACT for JCI boilers LNB+FGR 60% 2,560 CoST, ACT for ICI boilers Oxygen Trim and Water 65% 680 CoST, ACT for Injection (OT/WI) ICI boilers Selective Catalytic 90% 2,366 CoST, ACT for Reduction (SCR) ICI boilers

21 Cost information was taken from EPA's CMDB (Control Measures Database) for Stationary Sources used in the Control Strategy Tool (CoST). A fully functional version ofCoST was developed in 2008. The CMDB is available for download at: http://www.epa.gov/ttnecas1/cost.htm. All costs in table 3 represents costs for "small" sources, which are undefined in the CoST database, but equate to larger cost effectiveness values due to lower potential for emission reductions. 22 State ofUtah DEQ, Approval OrderNumber: DAQE- AN0103460049-11. May 3, 2011. 23 Alternative Control Techniques Document-- NO Emissions from x Industrial/Commercial/Institutional (ICI) Boilers. US EPA. EPA-453/R-94-022. March 1994. ("ACT for ICI Boilers") 25Selective Non-Catalytic SO% 3,870 CoST, ACT for Reduction (SNCR) ICI boilers 

### *The control efficiency and cost effectiveness values are from the first reference listed.

a Cost information for FGR alone is not provided in CoST or ACT for ICI boilers. KUC identifies the existing controls onthe boiler (i.e, LNB) as RACT, and does not evaluate any ofthe other potential RACT options identified in Table 3. TheNewJersey State ofthe Art (SOTA) Manual for Boilers and Process Heaters24 identifies LNB with FGRand/or SCRas control technolgiesthat correspond to SOTA performance emission limits for natural gas fired boilers rated 75 MMBTU/hror greater. Main stack In the summary ofemission source table in the RACT analysis, KUC identifies the following smelter emission sources as being routed through the main stack: • Concentrate dryer; • PH superheater; • Matte grinding; • Anode furnace; • Shaft furnace; • Holding furnace; • Vacuum cleaning system; • North and south matte granulator exhaust scrubber. KUC provides no information on any ofthese emission sources, including unit characteristics (i.e., type, size), current controls, individual unit emissions, or potential RACT options. According to the summary ofemission source table, the Main StackPTE combined emissions of 1,114 tpy is 73.7% ofthe total facility emissions. Based onthe NSRpermit emission limits forthe main stack, summarized in Table 4, it appears thatthe bulk ofthese emissions are S02• Table 4. NSRPermit Limits for KUC SmelterMain Stack

Pollutant Emission limit Averaging (lbs/hr) Time PMw 89.5 24 hour 

### so2 552 3 hour 

### so2 422 24 hour 

### so2 211 Annual NOx 35 Annual Lead 1.3 Annual Smelter fugitives The KUC analysis identifies RACT as current design ofprocessesthat have been engineered/designedto reduce fugitives, but does not specify any specific sources ofRACT emissions orpotential controls for these emissions. Table 5 provides examples ofprocess fugitive emission control techniques that could be considered to reduce emissions from copper smelting operations.

24 State ofthe Art (SOTA) Manual for Boilers and Process Heaters, NJ DEP. Revised February 22, 2004. 26Table5. Process FugitiveControlTechniques for Copper Smelting Operations
Process Fugitive ControlTechniques Ref. #3 Local Ventilation (localized hooding and enclosure), including movable hoods 1, 2, 3, 4, 5, 6, 7 Total building enclosure/evacuation 1, 2, 3, 5, 7 Use clean scrap in metal melting furnaces 1 Implement a leak detection/prevention/repairprogram 1 Improve leak detection/repair, including improved detection through use ofoptical gas 8 imaging Prompt repairs ofexhausthood leaks 7 Increase exhaust rate ofprimary control system 7 Add curtains to increase hood capture efficiency 7 Capture system that collects the gases and fumes from transfer ofmolten materials from 6 smelting and converting vessels Capture systems thatcollects the gases from each vessel used to refine blister copper, remelt 6 anode copper, orremelt anode scrap •References corresponding to each number (1 through 8) are in Attachment 2. FINDINGS Sources ofRACT information KUC only referenced one source ofRACT information in their analysis, the RACT/BACT/LAER Clearinghouse (RBLC) database. NewRACT identified in the KUC analysis No additional measures were identified in the KUC analysis as RACT. The analysis identifies all existing controls and practices as RACT. Adequacy ofdata A full RACT analysis for this source is not provided. The following are examples ofareas where the RACT analysis does not provide adequate data: • A completeRACT analysis is not provided for any emission sources except the refinery boilers. • The costs provided in the RACT for NOx controls for refinery boilers are unsupported. • The review ofpotential control measures is not sufficientbecause KUC did not evaluate all appropriate RACT options (e.g., OT/WI and SNCR for refinery boilers). Cost effectiveness KUC provided a cost analysis for only one emission source, the refinery boilers (NOx PTE=4.16 tpy), which are currently equipped with FGRand LNB. KUC estimated a cost of$26,790/ton NOx to install SCR. An 80% control efficiency was estimated for SCR, which is low comparedto the typical value of 90% for SCRon natural gas fired boilers, as show in Table 3. No costs ofadditional controls were provided for the Powerhouse Holman boiler, although it appears that the Holman boiler is less controlled than the refinery boilers and has larger potential to emit.

27KUC asserts that current controls and practices constitute RACT for every emission source. However, as described in EPA's April25, 2007 PM2.5 implementationrule (72 FR20594), the EPA defines RACT as "the lowest emissions limitation that a particular source is capable ofmeeting by the application of control technology that is reasonably available considering technological and economic feasibility". RACT must also be measures that contribute to attainment as expeditiously as practicable in a state's nonattainment area. KUC did not evaluate the cost effectiveness ofadditional controls for any emission sources (with the exception ofrefinery boilers) to determine ifthere exists any reasonably available control technology to achieve the lowest emission limitation that the source is capable ofmeeting. Recommendations • Request the State to provide a full RACT analysis including supporting documentation (see attached RACT Analysis list). • Recommend further evaluation ofthe costto install controls on the following emission sources after a full RACT analysis is provided by KUC: refinery and MAP CHP units, Powerhouse Holman boiler, main stack, and smelter fugitive sources.

28Tesoro SaltLake City Refinery Evaluation ofRACTAnalysis

This document evaluates the reasonably available control technology (RACT) analysis25 prepared for Tesoro Refining and Marketing Company Salt Lake City Refinery in Utah and included in the Draft Technical SupportDocument (TSD) for the Utah PM25 State ImplementationPlan (SIP). Throughout this document, the emission sources and controls at Tesoro may be compared withthose at other refineries in Utah PM2.5 nonattainmentareas that were previously evaluated by EC/R, including Chevron, Holly, and Big West Oil. SUMMARY OFRACTANALYSIS Facility description The Tesoro refinery processes and refines crude oil into more useful products. Table 1provides the annual emissions in tons from this facility based on the Utah 2008 emission inventory26

. Table 1. Tesoro Refinery 2008 Annual Emissions in Tons
PM2.s NOx 

### voc SOx 94.47 412.20 243.10 931.90
Emission sources The emission sources evaluated in the Tesoro RACT analysis include: • Fluid catalytic cracking unit (FCCU) and CO boiler that uses an electrostatic precipitator (ESP) and sulfur dioxide (S02) reduction additives to control emissions; • Six refinery fuel gas -fired process heaters/furnaces equipped with ultra-low nitrogen oxides (NOx) burners (ULNB) or low NOx burners (LNB); • Two natural gas and refinery fuel gas-fired cogeneration units (CG1and CG2), each with one 11.8 MWturbine with SoLoNOxcontrols and one 157.8 MMBTU/hrheat recovery steam generating unit; • Sulfurrecovery unit (SRU); • Storagetanks; • Fugitive equipment and wastewater system; • Flares; • Cooling towers equipped with drift eliminators; • Natural gas-powered compressor engines. Emission sources included in EC/R's evaluation This evaluation ofthe Tesoro RACT analysis will be restricted to the following emission units and pollutants (tons per year (tpy) baseline emissions estimated based on available data):

25 Tesoro Refining and Marketing Compamy- Salt Lake City Refinery PM2.5 SIP RACT Template Submittal. Tesoro Refming and Marketing Compamy. September 24, 2012.; contained in the Draft TSD for PM2.5Attainment SIPs, Section 5, Control Strategies, available for public comment I011/2012

- 11/112012. Available at: http://www.airguality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIP-TSD/TSD for Public Comment 10-1- 2012/index.htrnl 26 Utah Statewide Emission Inventory for Point Sources. Available at : http://www.airquality.utah.gov/Planning/Emission-Tnventory/2008 State/08 State List.htm 29• FCCU for particulate matter (PM) (80 tpy), S02(670 tpy) and NOx (170 tpy); • Process heaters for NOx (0.04

- 0.1 lb/MMBTU); • Cogeneration units for NOx (60 tpy); • Sulfur Recovery Units for S02 (> 250 tpy) Emission sources excluded from EC/R's evaluation Several emission sources that were evaluated in the Tesoro RACT analysis have been excluded from this analysis because these sources have low emissions compared tothe sources identified above, are already controlled to some extent, and/or have overall less potential for significantreductions in emissions. These sources include: the storage tanks, the fugitive equipment and wastewater system, the flares, the cooling towers, and the compressorengines. SUPPLEMENTALDATA SOURCES Fluid catalytic cracking unit CFCCU) and CO boiler Table 2 provides NOx control technologies identified for FCCU from the EPA CoST database27

. Table 2. NOx Control Technologies Identified for Fluid Catalytic Cracking Units

Control Cost ControlTechnology Efficiency Effectiveness Reference ($/ton NOx) LNB andFGR 55% 2,470-3,190 CoST Selective Catalytic 90% 3,457 CoST Reduction (SCR) Further control technologies for reduction ofNOx emissions from FCCUs are provided in consentdecrees established with most US refineries through EPA'srefinery initiative. The technologiesrequired bythese consent decrees, as summarized in the Emission Effects ofRefinery Cases and Settlements document28; include: • Selective catalytic reduction (SCR) to achieve 20 ppmvd; • Selective non-catalytic reduction (SNCR)/optimize existing SNCR system; • Scrubber-based NOx emission reduction technology to achieve 20 ppmvd; • Low NOx CO combustionpromoters; • Catalyst additives; • LoTOx system. It should be noted that in the Tesoro RACT analysis, LNB is rejected as a potential control option because regenerator temperatures are generally nothigh enough for significantthermal NOx formation. LNB stages the combustionprocess to reduce thermal NOx, which occurs in the high temperature flame zone near the burners. The EnvironmentAgency (EA), which is a British non-departmental public body, published a document on oil and gas processes29 that supports Tesoro's conclusion thatthermalNOx from

27 Cost information was taken from EPA's CMDB (Control Measures Database) for Stationary Sources used in the Control Strategy Tool (CoST). A fully functional version ofCoST was developed in 2008. The CMDB is available for download at: http://www.epa.gov/ttnecasl/cost.htm. 28 Including the Emission Effects ofRefinery Cases and Settlements in Projections forthe EPA's CAAA Section 812 Analysis. E.H. Pechan & Associates. Available at: http://www.epa.gov/ttnchieI/conference/ei15/session4/wilson.pdf 29 Oil and Gas Processes Supplementary Guidance Note, IPC S3 1.02, Environment Agency. Firstpublished 2000. 30regenerators is not normally excessive due to lower operating temperatures. The EA document further states that fuel NOx can be significant. Tesoro also considers NOx reduction additives to be technically infeasible because they operatetheirFCCU in partial bum mode. It appearsthat the Tesoro refinery does not operate any NOx control technologies on theirFCCU as all technologies were determined to be technically or economically infeasible. The Chevron refinery currently applies feedstock hydrotreatment and NOx reducing additives to control FCCU NOx emissions. The Holly refinery operates scrubberbased NOx emission reduction technology to comply with a consent decree emission limit of40 ppm. Itis unknown whattechnologies, ifany, are used to control NOx emissionsfrom the FCCU at the Big West Oil (BWO) Refinery. The following technologies for reduction ofS02emissions from FCCU are required in multiple EPA consentdecrees with refineries: • Wetgas scrubberto achieve 25 ppmvd; • so2 catalyst additive; • Feedstock hydrotreating. Tesoro rejects hydrotreatment on the basis that it is technically infeasible to hydrotreat FCCU feed that contains residual oil, andthe refinery does nothave a vacuum towerto separate the residual oil from vacuum gas oil. Tesoro currently uses catalyst additives to control FCCU S02emissions. BWO proposes the use ofS02catalyst additives in their RACT analysis, and the Chevron refinery currently uses catalyst additives. The Holly refinery currently operates a wet scrubberto comply with a consent decree emission limit of24 ppm S02. According tothe Tesoro RACT analysis, S02catalyst additives typically achieve 20-60% emission reduction, while wet scrubbers can achieve 95% emission reduction. The EA document cites a wet scrubber S02removal efficiency of90% orbetterfrom the FCC flue gas. Technologies for reduction ofPM emissions from FCCU identified in the EA document include: • ESP; • Wet scrubbers; issues with scrubbers WWTP • Cyclones; The EA document also identifies bag filters but states that this technology is not favored for refineries due in parttotheirpressure drop, as FCCU are particularly sensitive to pressure drop changes. In addition, cyclones are primarily usedto remove largerparticles and have limited effectiveness on particles sizes of PM10 and smaller. The Tesoro refinery currently operates an ESP to control FCCU PM emissions. The Chevron refinery also operates an ESP, whilethe Holly refinery operates a wet scrubber. BWO operates a bank ofcyclones in combination with a fabric filter on the cyclone underflow, and proposesto install a stack gas filter. In the EA document, a wet scrubber is considered a best available technique (BAT) for SOx and PM control for FCCUs, especially when releases from both pollutants are high. In their RACT analysis, Tesoro states that the Salt Lake City publicly ownedtreatment works (POTW) would not receive the purge stream from a wet scrubber due tothe high total dissolved solids (TDS) concentration, and other more costly disposal options would have to be pursued; including direct discharge via an NPDES permit or deep well injection.

31Process heaters Table 3 provides NOx control technologies identified for gas-fired process heaters from EPA sources. Table 3. NOx Control Technologies Identified for Refinery Fuel Gas-Fired Process Heaters

ControlTechnology Control CostEffectiveness Reference Efficiency ($/ton NOx) LNB 50% 2,200 CoST, ACT for PH30 ULNB 75% 1,500 CoST, ACT for PH LNB and flue gas 55% 4,200 CoST, ACT for PH recirculation (FGR) SCR 75% 12,040 CoST, ACT for PH SNCR 60% 2,850 CoST, ACT for PH LNB and SCR 90% 12,378 CoST, ACT for PH LNB and SNCR 80% 3,520 CoST, ACTfor PH *All costs and control efficiencies are from CoST. Table 4 provides the size and current controls and emission rates ofthe process heaters identified by Tesoro Refinery in their RACT analysis. Table 4. Tesoro Refinery Process HeaterInformation Process HeaterUnit# Current CurrentEmission (heat input capacity) Control Rate (lb/MMBTU) H-101 (162 MMBTU/hr) ULNB 0.04 F-1 (86.6 MMBTU/hr) LNB 0.10 F-15 (6.3 MMBTU/hr) LNB 0.10 F-680 (15.6 MMBTU/hr) ULNB 0.04 F-681 (22.1 MMBTU/hr) ULNB 0.04 F-701 (8.0 MMBTU/hr) LNB 0.07 Tesoro does not evaluate process heaters H-101, F-680 orF-681 because these units are identified as well controlled and satisfy RACT. The NewJersey State ofthe Art (SOTA) Manual for Petroleum Refineries31 provides SOTAperformance.emission levels for refinery fuel gas-firedprocess heaters. These emission levels are usually accomplished with combustion controls and are 0.05 lb NOxiMMBTU for new units and 0.07lbNOx/MMBTU for burnerreplacements. Because Units H-101, F-680 and F-681 operate below these emission limits, Tesoro's contention thatthese units are well controlled appears to be reasonable. Tesoro also does not evaluate process heaters F-701 and F-15 because these are small units with heat input capacities less than 10 MMBTU/hr. According to EPA's April25, 2007 PM2.5 implementation rule (72 FR20594), a complete RACT analysis should include all reasonably available control measures, and Tesoro does not evaluate any additional control measures beyond the current control ofLNB.

30 Alternative Control Techniques Document-- NOx Emissions from Process Heaters. US EPA, EPA-453/R-93-034. September 1993. 31 New Jersey State ofthe Art (SOTA) Manual for Petroleum Refmeries, NJ DEP. July 1997. 32However, becausethese units are small, have low emissions, and are already controlled by LNB, the incremental cost ofadditional controls would likely be high and may notbe economically feasible. Tesoro states thatULNB and SCR for unit F-1 is currently being evaluated with the assistance ofvendors, and cost information should be available by the end ofOctober. In their RACT analysis, Tesoro does not state their intent to evaluate LNB with FGR, SNCR, or SCR/SNCRwith LNB, as potential RACT options for any oftheir process heaters. Cogeneration Units Table 5 provides NOx control technologies identified for natural gas-fired turbine cogeneration units from EPA sources. Table5. NOx Control Technologies Identified for Natural Gas-fired Turbine CogenerationUnits

Control Technology Control CostEffectiveness Reference Efficiency ($/ton NOx) LNB 68% 490 CoST Steam injection 80% 1040 CoST Water injection 76% 1,510 CoST SCRand LNB 95% 2,470 CoST SCRand steam injection 95% 2,010 CoST SCR and water injection 95% 2,730 CoST In their RACT analysis, Tesoro only evaluates SCR and does not evaluate any ofthe othertechnologies identified in Table 5. Based on information from theNew Source Review (NSR) permit for this facility32

, the turbines are currently equipped with SoLoNOxtechnology, a form ofstaged combustion orLNB. In their RACT analysis, Tesoro stated thatthe cogeneration units are guaranteed to meet 32 ppm@ 15% 0 2, which met BACT at time ofinstallation in 2003. The guaranteed emission limit of32 ppm is below the Massachusetts Department ofEnvironmental Quality Engineering Rule 31 0 CMR 7.1933 emission limit of42 ppmv NOx, which is defined as RACT by Massachusetts for combined cycle stationary combustionturbines (similarto cogeneration units). However, the 32 ppm emission limit does not meet the SOTA performance level emission limit of 15 ppmv for cogeneration cycle gas-fired turbines34

. Sulfur Recovery Units (SRU) Tesoro currently operates SRU and a tail gas incinerator (TGI). In their RACT analysis, Tesoro states their intention to install a tail gas treatment unit (TGTU) as part ofthe Waxy Crude Processing Project by late 2014. Tesoro asserts that a TGTU satisfies RACT, and conducts no additional emissions orcost analyses. The Chevron refinery currently operates a TGTU and a TGI. One technology that was not considered by Tesoro is proposed at the Holly refinery, and includes routing emissionsfrom the tail gas incinerator (TGI) to a wet scrubber. Another potential control that was not considered by Tesoro is proposed atthe BigWest Oil (BWO) refinery, and includes redundant sulfur

32 State ofUtah DEQ, Approval OrderNumber: DAQE- AN103350056-12. January 18,2012. 33 Massachusetts Department ofEnvironmental Quality Engineering Rule 310CMR 7.19 Reasonably Available Control Technology (RACT) for Sources ofOxides ofNitrogen (NOx). Available at: http://www.epa.gov/regionl/topics/air/sips/ma!MA 7 19.pdf 34 State ofthe Art (SOTA) Manual for Stationary Combustion Turbines, NJ DEP. Last Revised December 21, 2004. 33capture technology for use during planned and unplanned outages ofthe amine units and SRU. The alternative technology would include separate caustic gas scrubbers for sourfuel gas and sour-water stripper gas. It appears that Tesoro, Chevron, and Holly operate (or proposes to operate) a treatment unit in addition to a TGI, such as the wet scrubber at Holly and the TGTU at Chevron and Tesoro, while BWO does not. However, BWO proposes to install redundant sulfurtechnology to account for potential increased S02 emissions during outages ofthe SRU, which may notbe accounted for at Tesoro and other refineries. Tesoro states that their TGTU willreduce emission to levels better than NSPS SubpartJa, whichrequires that SRUs with a capacity less than 20 tons per day meet a limit of2,500 ppmvd S02 at 0%02• Tesoro contends that this limit is equivalentto RACT. However, as described in EPA's April25, 2007 PM2.5 implementation rule (72 FR20594), the EPA defines RACT as "the lowest emissions limitationthat a particular source is capable ofmeeting by the application ofcontrol technology that is reasonably available considering technological and economic feasibility". RACT must also be measures that contribute to attainment as expeditiously as practicable in a state's nonattainment area. Therefore, RACT is determined on a case-by-case basis and anNSPS emission limit cannotbe universally applied as RACT to all SRU emission sources. In addition, the limit of2,500 ppmvd S02 is well above the NJ SOTA performance emission limitof300ppmvdtotal reduced sulfur (TRS) (measured as S02) at 0% 0/, FINDINGS Sources ofRACT information Tesoro only referenced one source ofRACT information in their analysis, the RACT/BACTILAER Clearinghouse (RBLC) database. New RACT identified in the Tesoro analysis In their RACT analysis, Tesoro states thatthey are proposing to install a tail gas treatment unit (TGTU) to control emission ofS02by 259 tpy. The TGTU is part ofthe Waxy Crude Processing Project and is expected to be installed in late 2014. Adequacy ofdata A full RACT analysis for this source is not provided. The following are examples ofareas where the RACT analysis in the TSD does not provide adequate data: • A RACT analysis is not provided for the SRU; • All costs are unsupported; • The analysis does not explicitly specify baseline emissions in tons per year for any emission sources; • The review ofpotential control measures is not sufficientbecause Tesoro did not evaluate all appropriate RACT options (e.g., LNB with FGR, SNCR, or SCR/SNCRwith LNB for process heaters; TGI for SRU; steam injection and water injection for cogeneration units). Cost effectiveness Fluidcatalytic cracking unit (FCCU) andCO boiler Tesoro identified the following controls and cost effectiveness values for the FCCU: • Wet gas scrubber at $401,000/ton PM2.5 (36% control) and $560,000/ton PM25 (25% control); • wet gas scrubber at $18,800/ton 

### so2 (95% control) and $20,100/ton 

### so2 (88% control); • SCR at $36,000/ton NOx, Wet Scrubber+LoTOx at $108,000/tonNOx (86% control) and $117,000/ton NOx (73% control), Wet scrubber+ SCRat $115,000/tonNOx, and SNCRat $22,000/ton NOx.

34The cost effectiveness values identified by Tesoro for SCR are much higherthan the values identified in Table 2. In the cost effectiveness analysis for PM control with wet scrubbers, Tesoro uses low control efficiency values as comparedto the EA document, which states that wet scrubbing will provide a high particulate removal up to 95% on FCCUs. Process heaters Tesoro estimated a cost of$12,000/ton for ULNB on furnace H-10I. This cost is well above the cost effectiveness value for ULNB identified in Table 3. Cogeneration units Tesoro estimated a cost of$12,000/ton for SCRfor each cogeneration unit. This cost is well above the cost effectiveness values for SCRidentified in Table 5. SulfurRecovery units Tesoro did not provide any cost effectiveness calculations for the SRU. Recommendations • Requestthe State to provide a full RACT analysis including supporting documentation (see attached RACT Analysis list). • Recommend further evaluation ofthe costto install a wet gas scrubber for control ofPM and S02 emissions from the FCCU; including a review ofthe detailed cost analysis when this information is provided by Tesoro. • Recommend further evaluation ofthe cost to install SCR or SNCR for control ofNOx emissions from the FCCU; including a review ofthe detailed cost analysis when this information is provided by Tesoro. • Recommend further evaluation ofthe cost to install NOx emission controls for process heater F-1, including ULNB and SCRand SNCR, when this information is provided by Tesoro. • Recommend further evaluation ofadditional controls beyond the proposed TGTU for the SRU, including wet scrubbers afterthe TGI orthe potential for redundant sulfur capture technology in the event ofplanned and unplanned outages.

35ATTACHMENT 6 EPARegion 

### 8 Comments on Mobile Sources, Transportation Conformity, Related Contingency Measures, & I/M A.) Mobile Sources Comments on the SaltLake Section ofthe SIP Narrative: SaltLake Section: ControlMeasures for Area and Point Sources, Fine ParticulateMatter, PM2.5 SIP for the SaltLake City, UT NonattainmentArea Section IX. PartA.21 1.) On-road mobile sources; the SIP Narrative states the following on pages 61 and 62 ofthe Salt Lake section: "Adecentralized, test-and-repairprogram was evaluated for Box Elder and Tooele counties within the Salt Lake-Ogden-Clearfield nonattainment area. Forthe evaluation, all model year 1968 and newervehicles would be subject to a biennial test except for exemptvehicles. The program would exempt vehicles less than four years old as ofJanuary 1on 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 (TSl). Based on this evaluation, this program was not included because it was determined that implementation ofsuch a program would not affect PM 2.5 concentrations at the controlling monitor (i.e. Hawthorne) for the Salt Lake-Ogden-Clearfield nonattainment area." EPA commentA.l.: There would have been emission reductions ofNOx and VOCs identified with the State's evaluation. Whilejusttaken onlyby themselves, these liM emissionreductions may not have shown a modeled difference at the Hawthorne monitor. However, such an liM program would likely produce viable PM2.5 precursor emissionreductions for the Salt Lake-Odgen-Clearfield nonattainment area. Utah has not providedus withtheir evaluation and it would be helpful to see their analysis, with the estimatedpotential emissionreductions from an liM program, to further understand the State's conclusion. 2.) On-road mobile sources; the SIP Narrative states the following on page 65 ofthe SaltLake section: (EPA notes that UDAQ is currently evaluating the following additional control strategies for on-road mobile sources) "Reduction in the Reid vaporpressure (RVP) ofgasoline: UDAQ is currently working with the Utah petroleum refining industry and other fuel suppliers to evaluate the effectiveness ofseeking a mandatory or voluntary reduction in the Reid vaporpressure (RVP) ofgasoline, thereby making the fuel less volatile and helping to reduce VOC emissions. In preliminary modeling, this strategy has been shown to reduce total inventory VOC emissions between 0.3 and 0.5 percent. UDAQ will continue to evaluate this control strategy. Voluntary and emergingmobile source strategies: EPA guidance allows up to 3percent ofthe total reduction required to achieve attainment to come from voluntary and emerging mobile source strategies. Examples ofsuch strategies include, but are not limited to: •trip reduction programs • alternative fuels • diesel retrofits 1• episode-triggered/inversion-specific measures" "UDAQ will work with the WFRC and other stakeholders to assess various voluntary and emerging strategies for their emissions reduction potential in the Salt Lake-Ogden-Clearfield nonattainment area. Specific strategies and their associated characteristics (e.g. responsibility for implementation, funding sources, statutory or rule-making requirements, and other details) have not yet been specified and would need to be developed in consultation withrelevant agencies, authorities, and stakeholders." EPA Comment A.2.: The above two potential control strategies are a commontheme for all three nonattainment areas. EPA was advised earlier that the State was evaluating emissionreductions from the possible lowering ofthe gasoline RVP (from approximately 13 psi to 12 psi), buthad also noted on a conference call that the Utah Petroleum Associationhad indicated that the wintertime gasoline sold inthe three nonattainment areas was already at a lower level than estimatedby the State. Therefore, ifthis RVP option is no longer viable, it should be removed from the table. In addition, the State has not shared any specific information with regard to the potential voluntary and emerging mobile source strategies being considered. 3.) Transportation Conformity PM2.5 components, section 7.6; the SIP Narrative states the following on pages 70 and 71 ofthe SaltLake section: "The transportation conformity requirements found in 40 CFR 93.102 require that the PM2.5SIP include motor vehicle emissions budgets for directly emitted PM2.5; motor vehicle emissions from tailpipe, brake and tire wear; and emissions ofnitrogen oxide (NOx), a gaseous PM2.5 precursor. Because UDAQ has identified volatile organic compounds (VOCs) as a PM2.5 precursor that significantly impact PM2.5 concentrations, the SIP will need a VOC motorvehicle emissions budget for transportation conformitypurposes. The UDAQ conducted are-entrainedroad dust study that concludedthat PM2.5 re-entrained road dust emissions are negligible in Salt Lake City, Utah PM2.5 nonattainment area and meetthe criteria of40 CFR 93.102(b)(3). EPA Region 8 reviewed the study and concurred with the UDAQ's findings." "Currently the UDAQ is in negotiations with EPA Region 8 regarding the establishment ofa direct PM2.5 budget in the transportation conformity budget section ofthe SIP. The State ofUtah has concluded that only NO, and VOC emissions from on-road motor vehicles warrant consideration for potential emissionreduction controls to peakPM2.5 levels in the nonattainment areas." EPA CommentA.3.: 40 CFR 93.102(b)(1) requires a motorvehicle emissionbudget (MVEB) be identified for direct PM2 .5 (that includes tailpipe, brake wear, and tire wear). True, the State has considered emission controls for the PM2 .5precursors ofNOx and VOCs; however, direct PM2 .5must be evaluated for transportation conformity purposes. Withregard to the "negotiations" with EPA, Utah has briefly discussed the consideration of40 CFR 93.109(f) regarding "Areas with insignificantmotorvehicle emissions". However, the State and/or WFRC (the MPO) have not provided any information. In addition, the State does actually provide a direct PM2.s MVEB inTable 7.1 also on Salt Lake document page 71 (see EPA CommentA.4. below). 4.) Transportation Conformity PM2.5 Budgets, section 7.6; the SIP Narrative presentsthe following on pages 27, 71, 74, and 75 ofthe SaltLake section:
2"Thisplan includes reasonable further progress demonstrations for 2014 and 2017 and attainment ofthePM2.5 standard is projected by 2019. Transportation conformity budgets have been established for the years 2014, 2017, and 2019. In this maintenance plan, the State is establishing transportation conformity motor vehicle emissionbudgets (MVEB) for NOx and VOC for 2014, 2017, and 2019." 

### WFRC Transportation Conformity Budgets (tons peraveragewinterday) 2014 2017 2019 DirectPM2.5 NOx VOC 5.0 80.0 47.5 4.6 67.0 40.1 4.0 55.2 32.6 Table 7.1, Emissions Budgets for Transportation Conformity Purposes 

### "RFP: Motor Vehicle Emissions: 40 CFR 51.1009 also requires that State shall include in its RFP submittal an inventory ofon-road mobile source emissions inthe nonattainment area. This requirement is for the purposes ofestablishing motor vehicle emissions budgets for transportation conformitypurposes (as required in 40 CFRpart 93). Table 8.2 presents emissions totals for on-road mobile sources. These are the same totals that factor into the overall emissions reported in the preceding RFP table. However, because the geographic extent ofthe nonattainment area exceeds the urbanized area characterizedby the local Metropolitan Planning Organization, these emissions also include contribution from the surrounding rural areas. For a more specific discussion ofmotor vehicle emissions budgets for transportation conformity purposes, see Chapter 7 ofthis Plan."

Mobile Source Emissions

'<

..... , -- ..**~~! ~~e_** City.

# u:r**~~2.~ !f()f'!a!t~i** **nnu~nt**Area 

# I

•emissions 

### I Year 2008 2014 2017 I 2019 6.1 4.6 4.1 3.5 I I

w**"~** c NOx 119.0 81.1 68.0 ' 56.1**~** ' ' ! 

## voc 70.9 47.3 40.4 33.4

·- ·-·· - - .- .,_ .. - - ·- ... ' 

### *.**En:!i~sio.n~_~r~ _P.rt!~~nt~d** **i~ ~()OS**  per**ave~~ge_ ~!'lte** r**~ay** 

### ... . ..; •• PM2.5 emissions include: tailpipe PM2.5, 504, brakewear, and tire-wear 

### EPA CommentA.4.: There are inconsistencies, which the State needs to explain and/or reconcile, with the SIPNarrative identified PM2

### .s, NOx, and VOC MVEBs as compared to the SIP emission inventories and RFP identified MVEBs. The following table presents the mobile sources MVEBs inconsistencies that the State needs to address (all emission figures are intons per day). The "Inventory" and "RFP" MVEBs appear to track almost exactly, while the SIP Narrative identified MVEBs showvariations: 

### 2014 2017 2019 PM2.5 Inventory* 4.61 4.11 3.50 3SIP** 5.0 4.6 4.0 RFP*** 4.6 4.1 3.5

NOx Inventory* 81.15 68.02 56.10 SIP** 80.0 67.0 55.2 RFP*** 81.1 68.0 56.1



## voc Inventory* 47.33 40.36 33.38 SIP** 47.5 40.1 32.6 RFP*** 47.3 40.4 33.4 *Emission Inventories as presented in Table 4.2 on Salt Lake sectionpage 27. ** SIP identified MVEBs as presented in Table 7.1 on Salt Lake sectionpage 71. ***RFP MVEBs as presented in Table 8.2 on Salt Lake section page 75. 5.) Contingency Measures and Implementation Schedules for the NonattainmentArea, section 9.2, the SIP Narrative presents the following on page 77 ofthe SaltLake section: "Transportation ControlMeasures (TCMs)- On-RoadMobile Sources account for most ofthe NOx and VOC emissions that lead to fine particulate formation in winter months. The controls affecting on-road mobile sources already accounted for inthe attainment and RFP demonstrations are liM programs and Tier II ofthe federal motor vehicle control program. Additional control measures are available for contingency purposes, and they fall into the category known as TCMs. The most promising ofthese measures is Employer Based Trip Reduction, during wintertime periods when conditions warrant. Itis herein identified as a contingency measure for the purpose ofthis Plan, with an implementation schedule to be determined." EPA CommentA.5.: The State needs to provide the specific adopted rule language for this particular contingency measure and a schedule for implementation. The contingency measures, that are designed to meet the requirements ofCAA section 1 72(c)(9), are to be identified and adopted up front with the SIP so they can be automatically implemented, with no further action by the State, ifneeded. The above statement; "Itis herein identified as a contingency measure for the purpose ofthis Plan, with an implementation schedule to be determined." is insufficient. B.) Comments on the Logan/Cache County Section ofthe SIP Narrative: Cache Section: ControlMeasures for Area and PointSources, FineParticulateMatter, PM2.5 SIP for the Logan, UT

- ID NonattainmentArea. 1.) The following SIPNarrative discussion is provided on page2 oftheLogan section andis in regard to the dispersion modeled attainment demonstration and an 1/M program for Cache County: "Inthe enclosed SIP, we identify control strategies we have been able to develop throughthis process and the impact they will have on PM2.5 concentrations in the nonattainment area. Of special note in this SIP is that, throughthe stakeholderprocess and our analysis, it became apparent that the implementation ofa vehicle inspection/maintenance (liM) program inthe Cache Valley would allowthe areato meet the standard by 2014 as required inthe Clean AirAct.

4However, the Cache County Council recently rejected a proposal to delegate the statutory authority to the BearRiver Health Departmentto develop and implementthis strategy. We have looked at other strategies thatthe Board has the authority to implement and that could possibly result inreductions nearthose that would result from an liM program, and have concluded thatthey are notreasonable. Therefore, this section ofthe SIP requires Cache County to implement a program by December 14, 2013, and within 90 days ofthe effective date ofthe SIP, to submit a schedule to the Directorfor developing the program with enforceable milestones that canbe incorporated into the SIP and submittedto EPA. In speaking with the county leadership, we have also offered an alternative that, ifduring the public commentperiod, the county canidentify control strategies that will result in verifiable equivalent emissions reductions and be approvable by EPA, we will recommend using those strategies to replace the 1/M program requirements in the final SIP that will come to the Board in December." EPA CommentB.l.: Itis EPA's understanding that the dispersion modeled attainment demonstration for the Logan PM2.5 nonattainment areausedNOx and VOC emissionreduction credit from an liM program (two-speed idle and OBD) implemented in 2013 to demonstrate attainment in 2014. This will be an issue ifthe County Council stands behindtheir decision to implement an 1/M program that would achieve fewer emissionreductions. 2.) On-road mobile sources, the SIP Narrative states the following on page 60 oftheLogan section: "As supportedby the analysis conducted by UDAQ, a motor vehicle emission inspection and maintenance (liM) program is a necessary control strategy for Cache County to attain the PM2.5 NAAQS as expeditiously as practicable. This analysis canbe found in the TSD. Therefore, pursuant to Utah Code Annotated 41-6a-1642(1), Cache County must implement an liM program by December 14, 2013, and within 90 days ofthe effective date ofthe SIP, must submit a schedule to the Directorfor developing the program with enforceable milestones that can be incorporated into the SIP and submitted to EPA. Specifically, Cache County must implement a decentralized, test-and-repair program. All model year 1968 and newer vehicles are subjectto a biennial test except for exempt vehicles. The program will exempt vehicles less than four years old as ofJanuary 1 on any given year from an emissions inspection. Year 1996 and newer vehicles will be subjectto an On-Board Diagnostics (OBD) inspection. Year 1995 and oldervehicles will be subjectto a two-speed idle inspection (TSl). The anticipated emissions reductions associated with this program for the year 2014 are 0.24 tons perday for NOx and 0.22 tons perday for VOC." EPA CommentB.2.: EPAnotes this section ofthe SIP Narrative again states that an liM program will be implemented in Cache County and that the State may exercise its statutory authority to do so. As the attainment demonstration for Cache County for 2014 relies on emission reductions from an liM program, the final disposition ofthe potential Cache County liMprogram needs to be indicated by the State. 3.) On-road mobile sources, the SIP Narrative states the following on page 63 ofthe Logan section: (EPA notes that UDAQ is currently evaluating the following additional control strategies for on-road mobile sources) 5"Reduction in the Reid vaporpressure (RVP) ofgasoline: UDAQ is currently working with the Utah petroleum refining industry and other fuel suppliers to evaluate the effectiveness ofseeking a mandatory or voluntary reduction inthe Reid vaporpressure (RVP) ofgasoline, thereby making the fuel less volatile and helping to reduce VOC emissions. Inpreliminary modeling, this strategy has been shown to reduce total inventory VOC emissions between 0.3 and 0.5 percent. UDAQ will continue to evaluate this control strategy. Voluntary and emergingmobile source strategies: EPA guidance allows up to 3 percent ofthe total reduction required to achieve attainment to come from voluntary and emerging mobile source strategies. Examples ofsuch strategies include, but are not limited to: • trip reduction programs • alternative fuels • diesel retrofits • episode-triggered/inversion-specific measures" (Logan document page 63) EPA CommentB.3.: Same as EPA comment "A.2." above from the Salt Lake section. 4.) Transportation Conformity PM2.5 components, section 7.6; the SIP Narrative states the following on pages 67 and 68 ofthe Logan section: "The transportation conformity requirements found in40 CFR93.102 require that the PM2.5 SIP include motor vehicle emissions budgets for directly emitted PM2.5; motor vehicle emissions from tailpipe, brake and tire wear; and emissions ofnitrogen oxide (NOx), a gaseous PM2.5 precursor. Because UDAQ has identified volatile organic compounds (VOCs) as a PM2.5 precursor that significantly impact PM2.5 concentrations, the SIP will need a VOC motor vehicle emissions budget for transportation conformitypurposes. The EPA conformityrule presumes that PM2.S re-entrained road dust does not need to be included inthe interim conformitytest orhave an established motor vehicle emissions budgetunless either the State or EPA decides that reentrained road dust emissions are a significant contributor to the PM2.5 nonattainment problem. The UDAQ conducted are-entrained road dust study that concluded that PM2.5 re-entrained road dust emissions are negligible in the Utah portion ofthe Cache Valley PM2.5 nonattainment area. EPA Region 8reviewed the study and concurred with the UDAQ's findings. Currently the UDAQ is in negotiations with EPA Region 8 regarding the establishment ofa direct PM2.5 2 budget in the transportation conformity budget section ofthe SIP." EPA CommentB.4.: Region 8 has been approached by UDAQ to request EPA's interpretation and evaluation ofthe potential 2014 Logan PM2.s MVEB of0.33 tons per day and the aspects/options ofour conformity rule from sections; 40 CFR 93.109(f)Areas with insignificantmotor vehicle emissions, 40 CFR 93 .124(a) which addresses the identification and assignment ofsafety margin to MVEBs, and 40 CFR 93.124(c) which addresses the SIP requirements for the identification and assignment ofemission trading. In an email from Tim Russ ofEPAto Joe Thomas (UDAQ) and Rick McKeague III (UDAQ), dated October 10, 2012 and entitled "DirectPM 2.5 Issues for Cache County MVEBs: EPA Responses to State Questions", EPA presented answers, information, and options for UDAQ to considerfor the Cache County transportation conformity MVEBs questions. In this referenced email, EPA also concluded that a direct PM2.5 MVEB is necessary for the Cache County PM2.5nonattainment area. The State needs to review this email, advise ifthere are further questions, and revise this section ofthe SIP Narrative as appropriate.

65.) Transportation Conformity PM2.5 Budgets, section 7.6; the SIP Narrative states the following on page 68 oftheLogan section:

"Inthis maintenance plan, the State is establishing transportation conformity motor vehicle emissionbudgets (MVEB) for NOx and VOC for 2014 and 2019 for the nonattainment portions of Cache County, Utah. DirectPM2.5 2014 TBD 2019 TBD NOx VOC 4.82 3.45 3.61 2.48 Table 7.1, Emissions Budgets for Transportation Conformity Purposes"

EPA CommentB.S.: EPA has questions that the State needs to address regarding the MVEBs identified for 2019, the potential PM2 . 5 MVEB shown inTable 4.1 onpage 26 ofthe Logan section ofthe SIP Narrative, and inconsistencies betweenthe NOx and VOC MVEBs in Table 7.1 as compared to the emissions inventory data inTable 4.1 (both tables are from the Logan section ofthe SIP Narrative). a.) Assuming the Cache County I/M program is implemented, as stated in the Logan section ofthe SIP Narrative, and the Logan/Cache County area is shownto demonstrate attainment by 2014, there is no need for the State to identify PM2. 5, NOx, and VOC MVEBs for 2019 (unless there is a specific desire to do so by the State and/or Cache MPO). See 40 CFR 93.118. MVEBs could certainly only be identified for the 2014 attainment year. b.) Table 4.1 onpage 26 ofthe Logan section ofthe SIP Narrative displays PM2 .5mobile sources in 2014 as 0.33 tons per day. This should essentially be identified as the 2014 PM2 . 5MVEB. c.) The 2014 mobile source NOx and VOC emissionsshown inTable 4.1 (Logan section page 26 of the SIP Narrative), which shouldbecomethe 2014 NOx and VOC MVEBs are inconsistent with those same MVEBs shown in Table 7.1 (Logan sectionpage 68 ofthe SIP Narrative). The State needs to provide an explanation and/or reconcile these MVEBs concerns. Please see the EPA providedtable below (all emissions intons per day): 2014 PM2.5 NOx 

## voc Logan SIP Table 4.1 0.33 5.42 4.35 Logan SIP Table 7.1 "TBD" 4.82 3.45 6.) ContingencyMeasures and Implementation Schedules for the Nonattainment Area, section 9.2; the SIPNarrative states the following on page 71 ofthe Logan section: "Transportation Control Measures (TCMs)- On-Road Mobile Sources account for most ofthe NOx and VOC emissions that leadto fine particulate formation in winter months. The controls affecting on-road mobile sources already accounted for in the attainment and RFP demonstrations are liMprograms and Tier II ofthe federal motor vehicle control program. Additional control measures are available for contingency purposes, and they fall into the category known as TCMs. The mostpromising ofthese measures is Employer Based Trip Reduction, during wintertime periods when conditions warrant. Itis herein identified as a contingency measure for the purpose ofthis Plan, with an implementation schedule to be determined." EPACommentB.6.: Same as EPA comment "A.5." above from the Salt Lake section. 7C.) Comments on the Utah County Section ofthe SIP Narrative: Utah County: Control Measures for Area and Point Sources,FineParticulateMatter, PM2.5 SIP for the Provo, UT NonattainmentArea. 1.) On-road mobile sources; the SIP Narrative states thefollowing on page 64 oftheProvo section: (EPA notes that UDAQ is currently evaluating the following additional control strategies for on-road mobile sources) "UDAQ is currently evaluating the following additional control strategies for on-road mobile sources: Reduction in the Reid vaporpressure (RVP) ofgasoline: UDAQ is currently working withthe Utah petroleum refining industry and other fuel suppliers to evaluate the effectiveness ofseeking a mandatory or voluntary reduction inthe Reid vaporpressure (RVP) ofgasoline, thereby making the fuel less volatile and helping to reduce VOC emissions. In preliminary modeling, this strategy has been shown to reduce total inventory VOC emissions between 0.3 and 0.5 percent. UDAQ will continue to evaluate this control strategy. Voluntary and emerging mobile source strategies: EPA guidance allows up to 3percent ofthe total reduction required to achieve attainmentto come from voluntary and emerging mobile source strategies. Examples ofsuch strategies include, but are not limited to: • trip reduction programs • alternative fuels • diesel retrofits • episode-triggered/inversion-specific measures" (Provo document page 64) EPA Comment C.l.: Same as EPA comment "A.2." above for the Salt Lake section. 2.) Transportation Conformity PM2.5 components, section 7.6; the SIP Narrative states the following on page 69 ofthe Provo section: "Currentlythe UDAQ is in negotiations with EPARegion 8 regarding the establishment ofa direct PM2.5 budget in the transportation conformity budget section ofthe SIP. The State ofUtah has concluded that onlyNOx and VOC emissions from on-road motor vehicles warrant consideration for potential emissionreduction controls to peak PM2.5 levels inthe nonattainment areas." EPA Comment C.2.: 40 CFR93.102(b)(l) requires a motor vehicle emissionbudget (MVEB) be identified for direct PM2.5 (that includes tailpipe, brake wear, and tire wear). True, the State has considered emission controls for the PM2.5 precursors ofNOx and VOCs; however, direct PM2.5 must be evaluated for transportation conformity purposes. With regard to the "negotiations" with EPA, Utah has briefly discussed the consideration of40 CFR 93.109(f) regarding "Areas with insignificant motor vehicle emissions". However, the State and/or MAG (the MPO) have not provided any information. In addition, the State does actually provide a direct PM2.5MVEB inTable 7.1 also onpage 70 ofthe Provo section of the SIP Narrative (see EPA "Comment C.3."below).

8

### 3.) Transportation Conformity PM2.S Budgets, section 7.6; the SIP Narrative states the following on pages 70, 73, and 74 ofthe Provo section:

RFP: "This planincludes reasonable further progress demonstrations for 2014 and 2017 and attainment ofthePM2.5 standard is projectedby 2019. Transportation conformity budgets have been established for the years 2014, 2017, and 2019. In this maintenance plan, the State is establishing transportation conformity motor vehicle emissionbudgets (MVEB) forNOx and VOC for 2014,2017, and 2019." 

### MAG Transportation ConformityBudgets (tons peraveragewinterday) 2014 2017 2019 DirectPM2.5 NOx VOC 1.4 22.1 13.0 1.3 18.2 10.2 1.2 16.6 9.0 Table 7.1, Emissions Budgets for Transportation Conformity Purposes"

"MotorVehicle Emissions: 40 CFR 51.1009 also requires that State shall include in its RFP submittal an inventory ofon-road mobile source emissions in the nonattainment area. This requirement is for the purposes ofestablishing motor vehicle emissions budgets for transportation conformitypurposes (as required in 40 CFRpart 93). Table 8.2 presents emissions totals for on-road mobile sources. These are the same totals that factor into the overall emissions reported inthe preceding RFP table. However, because the geographic extent ofthe nonattainment area exceeds the urbanized area characterized by the local Metropolitan Planning Organization, these emissions also include contribution from the surrounding rural areas. For a more specific discussion ofmotor vehicle emissions budgets for transportation conformitypurposes, see Chapter7ofthis Plan."

Mobile Source Emissions Provo, UT PM2.S NonattainmentArea
*Emissions 

### I Year 2008 2014 2017 2019

..PM2.S 

### 1.6 1.3 1.1 1.1

NOx 31.8 22.4 18.4 16.9 

### voc 18.0 13.0 10.4 9.3

• Emissions are presented intons peraverage winterday •• PM2.5emissions include:tailpipe PM2.5, 504, brakewear, andtire-wear Table8.2.. MotorVehide Emissionsfor PuroosesofRFP

9EPA Comment C.3.: There are inconsistencies, whichthe State needs to explain and/orreconcile, with the SIP Narrative identified PM2.5, NOx, and VOC MVEBs as compared to the SIP emissioninventories and RFP identified MVEBs. The following table presents the mobile sources MVEBs inconsistencies that the State needs to address (all emission figures are intons per day). The "Inventory" and "RFP"MVEBs appear to track almost exactly, while the SIP Narrative identified MVEBs showvariations: 

### 2014 2017 2019 PM2.5 Inventory* 1.31 1.14 1.08 SIP** 1.4 1.3 1.2 RFP*** 1.3 1.1 1.1

NOx Inventory* 22.38 18.44 16.87 SIP** 22.1 18.2 16.6 RFP*** 22.4 18.4 16.9



## voc Inventory* 13.02 10.41 9.31 SIP** 13.0 10.2 9.0 RFP*** 13.0 10.4 9.3 *Emission Inventories as presented in Table 4.2 onProvo sectionpage 27. ** SIP identified MVEBs as presented in Table 7.1 on Provo sectionpage 70. ***RFP MVEBs as presented in Table 8.2 on Provo section page 74. 

### 4.) Contingency Measures and Implementation Schedules for theNonattainmentArea, section 

### 9.2, the SIP Narrative presents the following on page 76 oftheProvo section: "Transportation Control Measures (TCMs)- On-Road Mobile Sources account for most ofthe NOx and VOC emissions that lead to fine particulate formation in wintermonths. The controls affecting on-road mobile sources already accounted for inthe attainment and RFP demonstrations are liM programs and Tier II ofthe federal motor vehicle control program. Additional control measures are available for contingency purposes, and they fall into the categoryknown as TCMs. The most promising ofthese measures is Employer Based Trip Reduction, during wintertime periods when conditions warrant. Itis herein identified as a contingency measure for the purpose ofthis Plan, with an implementation schedule to be determined." EPA Comment C.4.: Same as EPA comment "A.5." above for the Salt Lake section. D.) Comments on SIP Section X- I/M: (The following was excerpted by EPA from the first two pages oftheUDAQ memorandum to the UAQB.) "SUBJECT: PROPOSE FORPUBLIC COMMENT: Repeal and ReenactUtah State Implementation Plan SectionX, Vehicle Inspection and MaintenanceProgram,PartA, General Requirements and Applicability; SectionX, Vehicle Inspection and MaintenanceProgram,PartB, Davis County; Section X, Vehicle Inspection and Maintenance Program, PartD, Utah County; Section X, Vehicle Inspection and MaintenanceProgram,PartE,Weber County; Add new Section X, Vehicle Inspection and Maintenance Program, PartF, Cache 10

### County; andAmend R307-110. GeneralRequirements: StateImplementation Plan. Background Utah Code Annotated 41-6a-1642 gives authority to each countyto design and manage a vehicle inspection and maintenance (liM) programto attain and maintain any national ambient air quality standard (NAAQS). Davis, Salt Lake, Utah, and Weber counties are required under Section 182 and 187 ofthe Clean AirAct (CAA) to implement an I/M programto attain and maintain the ozone and carbon monoxide NAAQS. An I/Mprogram has been identified as a necessary control strategy for Cache County to attain the PM2.5 NAAQS. 

### Proposed Changes to the Utah StateImplementation Plan We are proposing to repeal and reenact SectionX, Part A to summarize current liM requirements that are common among all liMprograms. The Air Quality Board last adopted SectionX, Part A onMarch 31, 2004. In addition, we are proposing to repeal and reenact SectionX Parts B, D, and E to update each ofthese parts to reflect the current liMprograms inDavis, Utah, and Weber counties. We are not amending SectionX, Part C at this time because Salt Lake County officials are inthe process ofrevising the county's I/M regulation. We will bring Part C to the Board when Salt Lake County has completed its revisions. Finally, we are proposing to add a new Part F that will incorporate a timeframe for Cache County to begin its liMprogram. We have attached the current State Implementation Plan (SIP) Section X, Part A, B, D, and E along with the proposed new Part F. StaffRecommendation: Staffrecommends that the Boardpropose for public comment the repeal and reenactment ofSectionX, Parts A, B, D, and E ofthe SIP and add Part F, Cache County liM programto SectionX. Staffalso recommends that the Boardpropose for public comment the amendments to R307-110 to update the date these Parts ofthe SIP are adopted by the Air Quality Board." 

### EPA CommentD.l.: As EPA has not seen the proposed changes to SIP Section 

### X, Part C for Salt Lake County, we will need to wait until those documents are provided by UDAQ. We are also aware that UDAQ is preparing a CAA section 110(1) analysis to evaluate the 1/M programs for Davis and Utah counties (since our last Federal approval) and all four liMprograms as perthe minor changes from Utah HB 407 (1/M) ofthe 2012 Legislative Session. Itis ourunderstanding that this CAA section 110(1) analysis will be available at the time the proposed revisions to SIP Section X, Part C are made available for public review. E.) 

### Overall Comments on Vehicle Miles Traveled (VMT), MVEBs, and ContingencyMeasures EPACommentE.l.): The State needs to provide the specific VMT data that were used for the mobile sources emissions estimates for 2014, 2017, and 2019 (as appropriate) for each ofthe three PM2.s nonattainment areas. There may be potential discrepancies betweenthe VMT data developed by the MPOs which was then used inEPA's MOVES2010a model to develop mobile sources emissions estimates for inventory data tables, the dispersion modeling, and for defining the respective nonattainment areaMVEBs.

11EPA had prior questions regarding the VMT used by the State and bythe MPOsto generate the mobile sources PM2 .5, NOx, and VOC emissions. EPA reviewed the SIP modeling VMT data as shownbelow for the Wasatch Front Regional Council (WFRC) area ofresponsibility (also see:http://www.airquality.utah.gov/Public-Interest/Current-Issues/pm2.5/SIPTSD/TSD for Public Comment 10-1-2012/3 Baseline and Projected Inventories/3 e Onroad Mobile Sources/3 e iiii ProjectionYearlnventories 2014 2017 2019.pdf):

2014 Winter VMT 2019 Winter VMT Box Elder 2,918,146 Box Elder 3,034,745 Davis 9,387,728 Davis 10,029,895 Salt Lake 31,743,818 Salt Lake 34,091,811 Tooele 3,555,173 Tooele 4,052,477 Weber 5,913,152 Weber 6,385,539 Total: 53,518,017 Total: 57,594,467

EPA then compared the above VMT datato those presented inthe August, 2012 2011-2040 RTP air quality conformity analysis as provided in WFRC's Air QualityMemorandum 28 1 • From the "AQ memo 28" file above, we looked at Table 11b for projectedVMT figures for seasonal VMT for 2015 and 2020 for Salt Lake County only (Note: We reviewed the seasonal VMT from the PM10 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 wintertime seasons). The VMT appear to be inconsistent betweenthe SIP and the WFRC. Forthe Salt Lake County only comparison, it appears that the PM2.s SIP daily VMT for 2014 are 31,743,818. However, from the WFRC conformity determination, 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. The same situation occurs with 2019 SIP VMT when comparedto the 2020 draft conformity determination in that for 2019 the PM2.s SIP daily VMT are 34,091,811; yet for 2020, the WFRC conformity determination shows 31,911,634. As all ofthese VMT figures are for the entire county, they shouldbe very similar for 2014 compared to 2015 and 2019 compared to 2020. Forthe Salt Lake Five CountyNonattainment Area, EPAreviewed the clarifications (revisions to Tables 12a and 12b to address minor clerical errors) for Air Quality Memorandum 28 (see the file above) as was provided in an email to FHWA-UT from Kip Billings (WFRC) on September 13, 2012. The VMT differences betweenthe SIP and draft conformity determination are even more pronounced for the larger Salt Lake Five County Nonattainment Area. For2014 the PM2.s SIP daily VMT are 53,518,017; yet from the WFRC conformity determination for 2015, the daily VMT are only47,502,009. The same situation occurs with 2019 SIP VMT when comparedto the 2020 draft conformity determination in that for 2019 the PM2 

### .s SIP daily VMT are 57,594,467; yet for 2020, the WFRC conformity determination shows only 52,556,601.

1 Air Quality Memorandum REPORT NO. 28 CONFORMITY ANALYSIS FOR THE WFRC AMENDED 2040 REGIONAL TRANSPORTATION PLAN (also as amended on 9/13/12 by Kip Billings,WFRC email to Steve Call, FHWA).

12EPA Comment E.2.) SIP Contingency Measures; deficiencies with the Transportation Control Measure (TCM). In all three nonattainment area sections ofthe SIP Narrative, the State provides the following language withregard to TCM contingency measures: "Additional control measures are available for contingency purposes, and they fall into the category known as TCMs. The mostpromising ofthese measures is Employer Based Trip Reduction, during wintertime periods when conditions warrant. Itis herein identified as a contingency measure for the purpose ofthis Plan, with an implementation schedule to be determined." Clean Air Act (CAA) section 172(c)(9) contingency measures are to be adopted by the State and if triggered, are designed to take effect with no further action by the State. The referenced SIP Narrative language is insufficient for a CAA section 172(c)(9) contingency measure as it merely identifies a potential contingency measure, lacks specific rule language, lacks a schedule for implementation, and is not adopted bythe State into the SIP. Is Utah considering modifying the State's rule R307-320 "Ozone Maintenance Areas and Ogden City: Employer-Based Trip Reduction Program" to be such a contingency measure and would this be withrespect to a CAA section 108 TCM? We note though, the current State version ofR307-320 is inconsistent with CAA section 118 because it does not apply to private companies. Finally, EPAnotes that we have never approved R307-320 into the Federal SIP.

13