UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGION 8 

Ref: 8P-AR 

Bryce Bird, Director 

Utah Division of Air Quality 

P.O. Box 144820 

Salt Lake City, Utah 84114-4820 

Dear Mr. Bird: 

1595 Wynkoop Street 

DENVER, CO 80202-1129 

Phone 800-227-8917 

http://www.epa.gov/region08 

NOV 012012 

RE: EPA Region 8 Comments on Utah's draft 

PM2.5 State Implementation Plan, Technical 

Support Document, and area source and 

other rules 

Thank you for the opportunity to provide comments on the State of Utah's draft PM2.5 State 

Implementation Plan (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 on the proposed rules 

that will apply in the PM2.5 nonattainment areas. 

Our comments, which are detailed in the six enclosures to this letter, should be considered 

preliminary. The Division of Air Quality (DAQ) has expressed to us directly and at the Air 

Quality Board meeting 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, our comments should be considered within this context. We will 

continue to work with DAQ as the draft PM2.5 SIP is developed further. 

Our preliminary assessment is that the draft PM2.5 SIP and associated rules need additional 

development and analysis as detailed in the 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 of the PM2.5 SIP and after we conduct our own notice and comment 

rulemaking. 

We want to acknowledge the tremendous efforts of the DAQ on all of the 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. If you have any 

questions, please contact me at 303-312-6416, or have your staff contact Catherine Roberts, 

Particulate Matter Program Manager, at 303-312-6025. 
Enclosures ( 6) 

c:!J:l 

Carl Daly, Director 2-b 

Air Program 

1) EPA Region 8 Comment for Utah PM2.s SIP Section IX 

Salt Lake City Part A.21; Provo Part A.22; Logan UT /ID Part A.23 

2) EPA Region 8 Comments on Utah PM2.5 SIP Draft Rules 

3) EPA Region 8 Comments on Section IX.H. 11, 12, 13 

4) EPA Region 8 Comments on Modeling TSD for Utah SIP Control Measures for Area and 

Point Sources, Fine Particulate Matter, for the Salt Lake, Utah, and Logan, UT-ID 

N onattainment Area 

5) EPA Region 8 Comments on RACT Discussion in SIP Narratives DAQ-072-12 and DAQ074-12 and RACT Technical Support Document 

6) EPA Region 8 Comments on Mobile Sources, Transportation Conformity, Related 

Contingency Measures, & I/M 

2 
ATTACHMENT 1 

EPA Region 8 Comment for Utah PM2.s SIP Section IX Salt Lake City Part A.21; Provo 

Part A.22; Logan UTIID Part A.23 

The following comments are based on 40 CFR Part 51 subpart Z - Provisions for 

Implementation ofPM2.s National Ambient Air Quality Standards 

1) §51.1002 Submittal of SIP. This section includes the requirement to identify and evaluate 

sources of PM2.5 direct emissions and precursors in accordance with sections 51.1 009 (RFP) and 

51.1010 (RACT and RACM). This includes the identification and evaluation of control 

measures for each plan precursor. (72 FR 20586, 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. Our preliminary analysis 

indicates that the draft PM2.s SIP has provided an appropriate technical demonstration to reverse 

the presumption for including VOC as a plan precursor (§51.1 002( c )(3)(i)-(ii)). However, there 

is no evidence of an evaluation of control measures for SOx, nor is there any evidence of an 

evaluation of control measures for NOx. The draft PM2.s SIP narrative needs to include 

information and analysis ofthese two precursors. (§51.1002(c); and (c)(l); and (c)(2)). 

2) §51.1 004 Attainment Dates. The proposed attainment date must be as expeditious as 

practicable but no later than five years from the date of designation 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 of designation- i.e., up to December 14, 2019 -

considering the severity of nonattainment and the availability and feasibility of pollution 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 if the State has not considered the 

implementation of all RACM and RACT local control measures for the area ... " 72 FR 20601. 

The March 2, 2012 Implementation Guidance on page 4 also states, "In order to support a 

requested attainment date of more than five years after the effective date of designation, the state 

should ensure that it has done a thorough evaluation of potential 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." 

Our review of the draft PM25 SIP has revealed: 

a. In the draft PM2.5 SIP, the State requests an attainment date extension to January 1, 2020. If 

an extension is granted it can only be for five years from the attainment date of December 14, 

2014 to December 14, 2019. 

b. It appears from both the 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 or the 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 of the proposed VOC rules for area 

1 
sources with compliance required by January 1, 2014. The State has generally proposed as 

RACM existing (with some revisions) rules whose application will merely be expanded to the 

PM2 5 nonattainment areas. However, the draft PM2.s SIP includes no RACM analysis that 

evaluates economic and technical feasibility for each of the proposed rules. Additionally, we 

have specific concerns regarding some of these rules (see attachment 2 comments on the 

proposed rules). 

Regarding RACT, the draft PM2.5 SIP does not include any specific dates for the implementation 

of new RACT measures with the exception of a few sources identified in the source-specific 

section of the 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 ofRACT will be 

expeditious. Regarding the substance of the analysis, Utah has concluded that existing BACT 

determinations for stationary sources identified in the PMw SIP are sufficient to control 

emissions of SOx, VOC and NOx. We do not consider this to be a sufficiently robust analysis of 

RACT. While the PM2.s SIP narrative identifies "new controls," later described as "candidate 

control measures," it does not specify what stationary sources would be affected and provides no 

dates for adoption or implementation of these controls. 72 FR 20628. The PM2.5 SIP narrative 

only gives general explanations of these new controls and associated rules. We are very 

concerned about the absence of specific dates and rule language. 72 FR 20600-20602, 20612-

20614. 

In conclusion, the draft PM2.s SIP does not meet the requirements of §51.1 004 because it does 

not provide a justification for an extension of the attainment date. There is no discussion of the 

severity of the nonattainment problem nor any analysis demonstrating that reasonable measures 

are not available that could be implemented to attain the NAAQS one year earlier. And finally, 

the request for an extension of the attainment date does not provide a demonstration of 

attainment ofthe PM2.s NAAQS by the extended date of December 14, 2019. 

3) §51.1 007 Attainment demonstration and modeling requirements 

The requirements for approving the attainment demonstration are contingent upon meeting the 

requirements of §51.112 and Appendix Wand must include "inventory data, modeling results, 

and emission reduction analyses ... " Furthermore "The attainment date justified by the 

demonstration must be consistent with the requirements of section §51.1 004(b ). The modeled 

strategies must be consistent with requirements in §51.1 009 for RFP and §51.1 010 for RACT 

and RACM. And finally, the supporting air quality modeling "should be consistent with EPA's 

PM2.s modeling guidance." 72 FR 20665. In consideration of the fact that modeling does not 

show attainment of the PM2.5 standard, the requirements from §51.1007 have not been met. (see 

attachment 4 comments on modeling) 

4) §51.1008 Emission Inventory (EI) requirements 

Under §51.1 008(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 in the Salt Lake and Utah (Provo) nonattainment areas. 

(EI Guidance sec. 3.3.2). In correspondence with EPA, the State agreed to provide sensitivity 

analyses to determine that emissions in 2008 represent an average emission year, but to date 

2 
these analyses have not been provided to 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 

order to verify the accuracy of the 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 of the allowable 

emissions from existing point sources. This issue has been the subject of numerous discussions 

with the State as outlined in an EPA memo that we provided to Utah on July 3, 2012 

(Preliminary Comments on Utah PM2.5 State Implementation Plan). In the absence of an 

emission inventory on which to evaluate the differences between projected actuals and allowable 

emissions, and an analysis of the likelihood that projected actuals are a reliable indicator of 

future emissions, the validity of the draft PM2.5 SIP is undermined. The inventory projections 

must accurately portray potential future emissions. 

5) §51.1 009 Reasonable Further Progress (RFP) 

The PM2.s implementation rule specifies that a state must " ... demonstrate generally linear 

progress in reducing emissions between the base year and the attainment date." §51.1 009( d). 

Chapter 8 of the PMz.s SIP describes the required elements and information to be included in an 

approvable RFP plan but at this point falls short of constituting an approvable plan. It shows that 

the currently identified control measures of the SIP (assumed to be represented by the 

"projected" columns in Tables 8.1 of the SLC and Utah County narratives) do not show linear 

progress toward attainment. The RFP columns show what the tons per day emission value 

should be in order to show linear progression towards attainment. Linear progress is delayed 

until the later years of SIP implementation for all emissions other than VOC, as well as for 

projected ambient PMz.s concentration. In order to show linear progress, the RFP plan would 

need to have additional emission reductions by both 2014 and 201 7. 

The data from Table 8.1 for Salt Lake City shows the same out year emission reduction 

(deviating from the RFP linear requirement) for primary PMz.s, NOx, and for ambient projected 

PMz.s concentrations. It does show generally linear progress for VOC emissions, and Total 

Precursors, probably because 1) VOC forms a large fraction ofthe total precursor inventory and 

2) 2014 SOz emissions appear to be in error. If2014 S02 emissions are corrected from 2 

tons/day to an assumed 12 tons/day, the total precursor reduction curve also shows less control 

by 2017 than a linear RFP slope would require. Whatever controls result in the large PM2.5 

decreases in the 2017 to 2019 period should be implemented sooner so that they achieve 

generally linear progress. The narrative in Chapter 6 (Salt Lake City SIP) is not currently 

adequate to identify what controls are being implemented in 201 7 that result in this large, out 

year emission reduction. 

Our analysis indicates that this pattern oflarge emission reductions only after 2017 is not a result 

of mobile source controls. It appears that the mobile source emissions are generally linear. Ifthe 

late decrease in emissions are due to a hypothetical set of as yet unidentified and unquantified 

controls described in Chapter 6, which are to be included in the SIP as enforceable future 

commitments, then it would appear these commitments need to include additional controls both 

initially and in 2014 to meet linear RFP, and not just in 2017. As quoted above, the goal ofRFP 

3 
is for areas to achieve generally linear progress toward attainment, as opposed to deferring 

implementation of all measures until the end; the RFP shown in Chapter 8 (Salt Lake City RFP 

section) defers significant progress to the end, and only with as yet unidentified hypothetical 

future controls. 

In addition, we note that the 2014 S02 emissions of2 tons/day shown in Table 8.1 of the Salt 

Lake City RFP section does not appear accurate in light of the 2008 and 2017 S02 emission 

levels (13.7 and 10.4 tons/day, respectively). We have assumed that they should in fact be 12 

tons/ day. The extent to which this error has propagated through the modeling should be 

investigated and corrected if needed. 

It might be asserted that, in part, the large reductions in PM2.s concentration occurring only after 

2017 (and thus the deviation from linear progress) are due to initial NOx disbenefits from early 

mobile source NOx reductions. If this is asserted, robust intermediate NOx sensitivity model 

runs (20 14, 2017, as well as 20 19) showing the modeled NOx dis benefit would be needed, as 

well as discussion in the modeling weight of evidence material. The fact that primary PM2.5 

emissions and S02 emissions (once the Salt Lake City S02 error is corrected) do not show 

generally linear reduction, but instead delay reduction to after 2017, suggests that the lack of 

linear progress in ambient concentration cannot be attributed to only complex secondary 

chemistry and NOx disbenefits, but also the lack of additional, earlier controls on direct 

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 of potential measures considered by the State, and information and analysis 

sufficient to support the State's judgment that it has adopted all RACM, including RACT." 

Furthermore, the State must "consider the cumulative impact of implementing 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." 

Our preliminary review of the draft PM2.s SIP has led us to conclude that the State's 

RACM/RACT analyses need additional work. For each stationary source, or source category, the 

SIP needs to systematically identify and evaluate potential measures for each relevant 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 of potential measures, 

other than analyses supplied by sources (contained in the TSD). Our preliminary review 

indicates that those source-generated analyses are not sufficiently robust or reliable. (see 

attachment 5 RACT/TSD comments). 

The draft PM2.5 SIP or the 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 or more. Given that the State is seeking 

an extension of the attainment date for the maximum period allowed by the CAA, this analysis is 

essential. 

4 
The current analyses are not sufficient to allow us to conclude that the SIP measures represent 

RACMIRACT or that an attainment date extension to 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 of the Salt Lake City SIP narrative 

has a general description of the Clean Air Act's RACT requirements, along with the following 

statement: 

"With respect to prior technology determinations other than RACT, the rule provides that 

prior BACT and LAER determinations, 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 better than 

what the MACT controls currently require." (page 54 of Salt Lake City SIP narrative; 

pages 53-54 of Utah 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 conclusion that "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% of the 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 PM2.5 rule 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 FR 20630). The SIP must include evidence 

that prior BACTILAER determinations continue to represent RACT for each source involved 

and for each pollutant of interest. 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 implementation rule states, 

"For VOC sources subject to MACT standards, States may streamline their RACT analysis by 

including a discussion of the MACT controls and relevant factors such as whether VOCs are 

well controlled under the relevant MACT air taxies standard, which units at the facility have 

MACT controls, and whether any major new developments in technologies or costs have 

occurred subsequent to establishment of the MACT standards." 72 FR 20630. The SIP narrative 

does not contain any supporting information or discussion as described in the preamble. We do 

not know which sources, units, or pollutants may be involved and, thus, have no basis to evaluate 

MACT standards as surrogates for RACM/RACT. 

1 To the best of our knowledge there have only been three stationary sources that have had a recent 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 covered by those reviews. Based on the list of stationary sources in the SIP 

narrative, that would leave approximately 31 of 34 stationary sources that have not been subject to LAER. 

5 
c) The statement in Chapter 9, that stationary sources meet or exceed RACT, is not supported by 

any substantive information in Chapter 6. Furthermore, the suggestion that stationary source 

emissions may receive a less rigorous RACT analysis because they "represent at most" 20% of 

the inventory is not sufficient, particularly since the SIP currently cannot demonstrate attainment 

by 2014 or 2019 for the Salt Lake City or Utah County areas. 

d) To the extent the State is intending to rely on prior RACT determinations for other pollutants, 

the State must include a certification and supporting documentation in the 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 pollutant emitted from a specific stationary source or source 

category under another NAAQS program, the State may submit as part of its SIP revision a 

certification, with appropriate supporting information, that the previous determination represents 

a current RACT level of control for those emissions for purposes ofthe PM2.5 program." (72 FR 

20629) The preamble also states that, "For RACT 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 information in the PM2.

5 SIP narrative. Thus, 

based on the draft analyses in the SIP narratives, we are unable to conclude at this time that the 

State analyses are" ... sufficiently robust in considering potential measures to ensure the 

selection of all appropriate RACT and RACM," or that the State has provided "a reasoned 

justification for its analytical approach." 72 FR 20612. 

7) §51.1011 Mid-course Review (MCR) 

The draft PM2.s SIP narrative does not acknowledge that a Mid-course review must be submitted 

to EPA six years after the designation date or December 14, 2015. The requirements for the 

MCR are described in the preamble of the PM2.s Implementation Rule, which states that "where 

EPA finds that a MCR would be required, the approval ofthe attainment demonstration would be 

contingent on a commitment by the State to conduct the MCR." 72 FR 20640-20642. According 

to section 51.1011, the MCR is required for areas with extensions of the attainment date to 

December 14, 2019 and must include: 1) a review of emission reductions and progress made in 

implementing control measures; 2) an analysis of changes in ambient air quality; 3) revised air 

quality modeling analysis to demonstrate attainment; and 4) any new or revised control measures 

adopted by the State, as necessary to ensure attainment. 

8) § 51.1 0 12 Contingency Measures 

CAA section 172( c )(9) requires emission reductions to be undertaken by a state if the 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 by the state. Additionally, the 

preamble to the PM2.s Implementation Rule notes that the contingency measures "should provide 

for emission reductions equivalent to about one year of reductions 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: 

6 
a) The draft PM2.s SIP relies on "commitments" to adopt or implement contingency measures: 

"As part of this contingency plan UDAQ will commit to 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 "continue to 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 on transportation conformity) 

d) The draft PM2.s SIP contains no calculation of the emission reductions that would be 

equivalent to about one year of reductions needed for reasonable further progress, nor does it 

contain an estimate of the reductions the identified contingency measures would achieve. 

e) One contingency measure identified in the 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 proposed rule, R307-302-3(2) and R307-302-3(4), exempts" ... those having no visible 

emissions." Also, how would the rule be enforced and what penalties are there for violations of 

the no bum day 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 of the 

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 "each plan must 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 CFR part 51, subpart K requires that SIPs include 

monitoring, recordkeeping, and reporting requirements, as does 40 CFR part 51, appendix V. 

The preamble to the PM2.5 Implementation Rule also discusses enforcement and compliance. 

For example, the preamble states the following: "[w]e reiterate that the compliance obligations, 

including emissions limits and other applicable requirements, must be representative of and 

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. 

7 
The preamble also emphasizes that RACT /RACM measures must be 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. In particular, we note the following 

three criteria: 

a) "[T]he baseline emissions from the source or group of sources and the future year projected 

emissions must be quantifiable so that the projected emissions reductions from the sources can 

be attributed to the specific measures being implemented." 

b) [T]he control measures must be enforceable. 

c) "[T]he control measures must be accountable," meaning, for example, "that source-specific 

emission limits must be permanent and must reflect the assumptions used in the 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 of the PM2.

5 SIP narrative, which describes potential additional SIP 

controls, needs to have more detail than is presented. Generally, the absence of dates and details 

of the measures, or whether any of these measures will actually be adopted, is not consistent with 

an enforceable SIP commitment. Additionally, the SIP must estimate the 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 in the 9th 

Circuit Court of Appeals. 

An example of the current lack of detail that we are concerned about is shown in this statement 

from the PM2.5 SIP Salt Lake City (p. 62): "Results of these feasibility studies will be made 

available by the completion dates also shown in the table. Studies that point toward possible 

emission reductions opportunities will be incorporated into the plan with specific development 

schedules and emission reductions commitments." Among other things, to satisfy CAA 

requirements, the State must clearly commit in the SIP to adopt specified control measures and 

achieve specific amounts of emission reductions 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 in the nonattainment area with 

allowable emissions limits (and potential to emit) for primary PM2.5 and precursors that are well 

above their current (and future projected) actual emissions. Due to the overwhelmingly local 

nature of the PM2.5 problem, the State needs to evaluate whether more stringent emissions limits, 

consistent with projected actual emissions, are needed at these sources. For further detail 

regarding this issue please see EPA's Preliminary Comments on Utah PM2.5 State 

Implementation Plan, July 3, 2012. 

8 
ATTACHMENT 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 if the rules are not revised 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 Air Act. However, this preliminary determination should 

not be considered our final decision. Our formal analysis will occur through public notice and 

comment rulemaking after we receive a PM2.5 SIP submittal from the State. 

Solid Fuel Burning Devices in Box Elder, Cache, Davis, Salt Lake, Tooele, Utah, and 

Weber Counties 

Utah Draft Rule R307-302 

Summary of concerns on draft rule 

1. Lack of Reasonably Available Control Technology (RACT) analysis for the source category; 

e.g., no information on range of control technologies or measures considered or other state rules 

evaluated. For example, are there other potential 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 changed to either specify that the boundary is for all PM2.5 

nonattainment areas or reference the CFR which provides the legal description for the 

nonattainment area boundaries. ( 40 CFR 81.345). 

3. The proposed rule 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 "The mandatory no-bum periods 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 area will have a no-bum period. The sentence should be changed 

to: "The mandatory no-bum periods will apply, at a minimum, to the entire nonattainment (or 

maintenance) area within 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 " ... or those having no visible 

emissions" allows an exemption from the mandatory no-bum rule which undermines the 

intention of the rule to ban the use of solid fuel devices because of bad air quality. Additionally, 

there is no provision for enforcing this rule other than 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, which relies on monitored exceedances. At a minimum, there 

should be an objective trigger- a monitored exceedance. Thus, we recommend that the rule 

1 
provide that a no-burn day is triggered whenever there is a monitored or forecasted exceedance 

of the trigger level. 

7. R307-302-6(1) should delete "wood burning stove" and substitute "solid fuel burning 

device." Also, DAQ should consider including specifications for fuel that can be burned in these 

devices. For example, the San Joaquin Valley's Wood Burning Fireplaces and Wood Burning 

Heaters rule (Rule 4901) includes requirements for the sale of wood and the test method used for 

the moisture content of the wood. Additionally, the rule lists prohibited fuels: garbage, treated 

wood, plastic products, rubber products, waste petroleum products, 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 consider prohibiting residential wood burning 

fireplaces for new residential developments in the PM2.5 nonattainment area. At a minimum, 

DAQ must evaluate these rule improvements as potential RACM. 

8. The rule should specify what is included in the "public announcement" and to whom it will be 

distributed. For example, the San Joaquin Valley's Wood Burning Fireplaces and Wood 

Burning Heaters rule (Rule 4901) spells out every avenue that the District could take to notify 

citizens. These include newspapers, radio or television stations, recorded telephone messages, 

and messages posted on the District's website. 

9. R307-302-5 limits opacity to 20% for fireplaces and solid fuel burning devices, but there 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 enforcement by the State and 

local governments. See CAA 110(a)(2)(C) and (E). 

10. Section R307-302-6(2) states: "Ownership of a 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 

of the rule? Additionally, R307-302-6(2) states, " ... so long as the unit remains intact within the 

real property of sale." What is intended by including the word "intact?" 

2 
Generator Testing 

Utah Draft Rule R307-330 

Summary of concerns on draft rule 

1. Lack ofRACT analysis for the source category; e.g., no information on range of control 

technologies or measures 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 proposed rule 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 of back-up generators for the nonattainment areas? How will DAQ know if 

this rule is being implemented if the sources do not notify DAQ of how 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 if all 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 of the back-up generators in the State 

and thus this rule would achieve minimal reductions, if any. 

8. Is it stated in Federal and/or State law that a test date cannot be rescheduled? 

9. The proposed rule 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." 

3 
Appliance Pilot Light 

U tab Draft Rule R307 -356 

Summary of concerns on draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

technologies or measures considered or other state rules evaluated. For example, are there other 

potential measures the state could adopt to 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 checking up on 

compliance and the consequences of non-compliance? 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 Board Meeting Minutes of August 1, 2012, mention that Questar provided comments on 

excluding home water heaters. What was the "convincing position" comment that Questar 

provided that persuaded DAQ to exclude home water heaters? San Joaquin Valley's Residential 

Water Heaters rule (Rule 4902) "applies to manufacturers, distributors, retailers, and installers of 

PUC quality natural gas-fired residential water heaters with heat input rates 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. Should they be 

included too? Or are they encompassed within stoves? A definition of"stove" would help. 

5. The definition of"recreational vehicle," which provides the boundaries of the exemption in 

R307-356-3(2), indicates that it includes a vehicle designed for human habitation for 

"recreational, emergency, or other occupancy." "Other occupancy" is vague. Is it necessary? Is 

it possible to be more specific? 

4 
Control of Emissions from Aerospace Manufacture and Rework Facilities. 

Utah Draft Rule R307-355 

Summary of concerns on draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

technologies considered, control efficiencies, or other 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 if it 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) per manufacturer's recommendations, but no specified monitoring, 

reporting, test methods, or compliance 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 of sources that 

would be affected and to clearly define terms used to describe the industry or applicable control 

methods and provides example definitions of pertinent 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: It appears 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 by the 

Aerospace NESHAP. 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 of captured emissions. 

8. Work practices do not specify a maximum VOC content for cleaning solvent. SJVAPCD and 

SCAQMD specify maximum VOC content of cleaners. 

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 of 40%. 

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) of 80% is not supported due to the concerns identified and the lack 

of documentation. 

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 

1 In the draft PM2.s SIP for each NAA, emission reductions in Table 6.5 compared to baseline area source emissions 

in Table 4.1. 

5 
Automotive Refinishing Coatings 

Utah Draft Rule R307-354 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

technologies considered, control efficiencies, or other state rules evaluated. 

2. Applies only to refinishing of automobiles, motorcycles, light and medium duty trucks and 

vans in facilities with PTE~ 2.7 tpy VOC. Rule has much narrower applicability provisions than 

other contemporary rules. SCAQMD, Ozone Transport Commission (OTC), Maryland (MD), 

and SJVU APCD rules have no emission cut -off and apply to refinishing of all types of motor 

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 on rails or roadways including, but not limited to, trains, railcars, 

truck trailers, mobile cranes, bulldozers, street cleaners, and implements of husbandry or 

agriculture). 

3. Alternative emission control device with 90% efficiency as certified by manufacturer; 

apparently applied to control device rather than overall control. Need clarification if it applies to 

both "control device" and "control system." OTC, MD, and SJVUAPCD require 85% overall 

control (capture and control). SCAQMD requires case-specific calculation of equivalent control. 

4. 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, OTC, MD, and SNUAPCD 

rules: specific records related to coatings; require records of key parameters 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 of cleaners (25 giL with 

exceptions). 

6. Lack of restrictions on manufacture and sale of noncompliant coatings, as well as labeling 

requirements. SCAQMD, OTC, MD, and SJVUAPCD rules all include bans on manufacture, 

sale, and possession of noncompliant coatings, except for sources with add-on control, and VOC 

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 of documentation. EPA's CoST Model database lists CE of $2,534/ton for what appear to 

be similar measures but information for comparison is lacking because the State's value is 

undocumented. 

8. RE of 80%2 is not supported due to the concerns identified and the lack of documentation. 

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 

6 
Comparative materials referenced: 

• Maryland- Code of Maryland 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- Motor Vehicle 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 CFR part 59, subpart B, 1998 (applies to coating manufacturers, not applicators) 

http://ecfr.gpoaccess.gov/cgi/t/text/textidx?c=ecfr&sid=6ef2dffl Of04cb94d9f91 72 7 c52 9c3 48&rgn=div6&view=text&node=40: 

6.0.1.1. 7 .2&idno=40 

• CoST database http://www.epa.gov/ttn/ecas/cost.htm 

7 
Fabric and Vinyl Coatings 

U tab Draft Rule R307 -345 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

teclmologies considered, control efficiencies, or other state rules evaluated. 

2. VOC content standards in the draft rule for fabric and vinyl coatings are less stringent than 

comparable rules. Please provide documentation or explain why these less stringent limits were 

selected. SCAQMD 1128 and SJV APCD 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 if it applies to 

both "control device" and "control system." Additionally, the rule does not provide 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, of the VOC emissions generated by the sources of emissions. 

4. Insufficient MRRT. The rule only requires records from the manufacturer that demonstrate 

compliance. 

5. VOC content standard is the same as the 1995 CTG requirements in EPA-453/R-95-010 for 

fabric and vinyl coatings but is less stringent than SCAQMD and SJV APCD rules that have 

limits at 2.2 lbs/g (265 g/1) for both categories. 

6. Lack of Transfer Efficiency (TE) requirement. 

Where TE is typically defined as the ratio of the weight of coating solids adhering to an object 

to the total weight of coating 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/ton VOC. EPA's CoST 

Model database lists CE of $1 ,343/ton and 97% control efficiency for fabric coating. 

9. RE of 80%3 is not supported due to the concerns identified and the lack of documentation. 

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 /ttncatc I I dir 1 /byndract. pdf 

• SJVIAPCD rule http://www.valleyair.org/rules/curmtrules/r4607.pdf 

3 Rule effectiveness value from the Utah SIP Technical Support Document published 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 

8 
Flat Wood Panel Coatings 

Utah Draft Rule R307-349 

Summary of concerns on draft rule 4 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

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 rather than overall control. Need clarification if it 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 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. Much more detailed in 

SCAQMD and SNUAPCD rules: specific records related to coatings; require records of key 

parameters for add-on control; and test methods are identified. 

4. Lack of application equipment and TE requirements. 

5. Requirements related to specification or labeling of coatings was not provided. SJUAPCD 

rule requires labeling of coatings and prohibits specifying use of noncompliant coatings. 

6. Work practices do not specify a maximum VOC content for cleaning solvent. SJVUAPCD 

and SCAQMD rules specify maximum VOC content of cleaners (25 giL with exceptions). 

7. CE value of$2,110/ton5 is not verifiable due to lack of documentation .. EPA's 2006 CTG 

describes CE estimates, in 2005 dollars, for the manufacture of exterior siding as $2,600 per ton 

ofVOC and, for interior paneling/tileboard, as $1,900 per ton 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 

documentation to support this percentage. 

8. 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 and the lack of documentation. 

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/20 12/September/ITEM 15 R307-

340to355.pdf 

5 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 349.pdf 

9 
Graphic Arts 

Utah Draft Rule R307-351 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

technologies considered, control efficiencies, or other state rules evaluated. 

2. Insufficient MRRT. The rule only requires monthly records of material usage and 

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. 

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 in the 1978 CTG and our review of SCAQMD and 

SJVU APCD rules showed evidence of a more stringent standard. 

5. Minimal number of limits on VOC content of cleaning solvent included. 

6. Lack of requirements related to sales or labeling of coatings or solvents. 

7. The draft rule does not specify a maximum VOC content for cleaning solvent. SJVUAPCD 

and SCAQMD specify maximum VOC content of cleaners (25 giL with exceptions) for all types 

of operations at a level lower than the 2006 CTG. 

8. The 2006 EPA CTG recommends 90% control for control devices installed prior to the 

effective date of the rule and 95% for devices installed after but the draft rule only specifies 90% 

control of dryer emissions for all offset lithographic and letterpress printing. Please explain why 

the difference from the CTG. 

9. Lack of sales/specification restrictions. SCAQMD prohibits specifying use of noncompliant 

coatings and sale of noncompliant 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 of documentation. Control 

efficiency of 65%3 references AirControlNet pg. 111-1340, but provides 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 of 90% 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 and the 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 

II 
Industrial Baking Ovens 

Utah Draft Rule R307 -334 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

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 similar rules. SJVUAPCD (Section 6.2) requires 

emissions from all oven stacks to be vented to an emission collection system and the collected 

emissions are vented to an approved emission control device, which has a control efficiency of at 

least 95% as determined by the test method. SCAQMD requires existing bakery ovens to control 

by at least: (A) 70 percent by weight (as carbon) for an oven with a base year average daily VOC 

emissions of 50 pounds or more, but less thl';ln 100 pounds; (B) 95 percent by weight (as carbon) 

for an oven with a base year average daily VOC emissions of 100 pounds or more. SCAQMD 

also requires new bakery ovens to reduce emissions by at least 95% by weight (as carbon) if the 

uncontrolled average daily VOC emissions are 50 pounds or more. 

4. CE value of90% and CE estimated at $9-10,000/ton VOC removed in the rule is according to 

documentation from Earthgrains Baking Companies. The control efficiency and CE needs to 

have additional analysis done to provide verification between Utah/Earthgrains, CoST Model 

database, and California District rules. EPA's CoST Model database lists CE of$1,470/ton and 

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) Regulation Number 3, 

http://www.maricopa.gov/aq/divisions/planning analysis/rules/docs/343-9502.pdf 

12 
Magnet Wire Coatings 

Utah Draft Rule R307-348 

Summary of concerns for draft rule 

1. Lack ofRACT analysis for the source category; e.g., no information on range of control 

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 rather than 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&M per manufacturer's recommendations, but no specified monitoring, 

reporting, test methods, or compliance certification. 

4. No limits on VOC content of cleaning solvent are included. 

5. No specification for a maximum VOC content for cleaning solvent. SCAQMD specifies 

maximum VOC content of cleaners (25 g/L with exceptions). 

6. Lack of regulation 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 of documentation. 

8. RE of 80%7 for Box Elder, Cache, Tooele, Utah, and Weber Counties are not supported due 

to the concerns identified and the lack of documentation. 

Comparative materials identified 

• SCAQMD Rule 1126 (1995) http://www.aqmd.gov/rules/reg/reg11/r1126.pdf 

• New Jersey TITLE 7, CHAPTER 27, SUBCHAPTER 16 

http://www.state.nj.us/dep/aqrn/Sub16.pdf 

• Phoenix (Maricopa County) Regulation Number 7, 

http://www.colorado.gov/cs/Satellite?blobcol=urldata&blobheadername 1 =ContentDisposition&blobheadername2=ContentType&blobheadervalue 1 =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= 12518099953 74&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 

13 
Metal Container, Closure, and Coil Coatings 

U tab Draft Rule R307 -352 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

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. 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 Denver rules: specific records related to coatings; require records of key 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 not include coil coating operations. 

5. Alternative emission control device with 90% efficiency as certified by manufacturer; 

apparently applied to control device rather than overall control Please clarify if it refers to both 

"control device" and "control system"). 

6. Lack of application and TE requirements. SCAQMD (2008) and SJVUAPCD (2007) rules 

list various approved application methods. 

7. Clarity is lacking related to inclusion of coil-coating and applicability size cut-off under the 

Applicability section ofthe draft rule. 

Rules applicable in Denver and Phoenix (ozone SIPs) have applicability cut-offs at 15 lb/day 

of actual, uncontrolled emissions. Denver applies a 2 tpy cutoff, and Phoenix applies 3 lb/hr. 

Denver and Phoenix cut-offs apply across all subject operations at the facility. 

It is unclear how broadly the draft rules cut-off applies absent definition of "coating 

operation." SCAQMD has an exemption if use< 1 gal/day at a single facility, SNUAPCD has 

an exemption for sources that use< 55 gal/yr, and BAAQMD has no cut-off. 

8. Lack of requirements in the draft rule related to sales or labeling of coatings or solvents. 

SCAQMD prohibits specifying use of noncompliant coatings and sale without labeling. 

SJUAPCD requires labeling of coatings and solvents. 

9. No limits on VOC content of cleaning 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 of regulation on capture efficiency. SNUAPCD requires 90% overall 

control (capture and control). Phoenix and SCAQMD require 85% overall control. BAAQMD 

requires equivalent control and "abatement device" efficiency of 90%. 

11. CE of$3,221/ton "derived from EPA database" is not verifiable or supported due to lack of 

documentation. 

12. RE of 80%8 is not supported due to the concerns identified and the lack of documentation. 

8 Rule effectiveness value from the Utah SIP Technical Support Document published 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 

14 
Comparative 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 

• Maricopa County (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&blobheadervalue 1 =inline%3 B+filename%3 D%22Regulation+ 7+-

+Control+of+Ozone+ Viz+Ozone+ Precursors+%2 8Emissions+of+ V olati tle+Organic+Co 

mpounds+and+Nitrogen+Oxides%29.pdfllo22&blobheadervalue2=application%2Fpdf&b 

lobkey=id&blobtable=MungoBlobs&blobwhere= 125180999 53 7 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 

15 
Metal Furniture Surface Coatings 

Utah Draft Rule R307 -346 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

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&M per manufacturer's recommendations, but no specified 

monitoring, reporting, test methods, or compliance certification 

3. Alternative emission control device with 90% efficiency as certified by manufacturer; 

apparently applied to control device rather than overall control. Please clarify if it refers to both 

"control device" and "control system." 

4. Lack of application and TE requirements. 

5. Lack oflimits on VOC content of cleaning solvent. 

6. Work practices do not specify a maximum VOC content for cleaning solvent. SN APCD and 

SCAQMD specify maximum VOC content of cleaners (25 g/L with exceptions). 

7. Lack of requirements and restrictions related to sales or labeling of coatings or solvents. 

8. Does not clearly specify overall control efficiency (capture and control device) for add-on 

control alternative. The CTG and SJV APCD require 90% overall control (capture and control). 

SCAQMD requires 85% overall 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 of 90 percent (from CTG). 

9. CE of $2,020/ton "derived from EPA database" is not verifiable or supported due to lack of 

documentation. EPA's CoST Model database lists CE of$2,027/ton for what appear to be 

similar measures (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 $200/ton with a 

control efficiency of 35%. 

10. RE of80%9 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 

• 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. gov I aq/ divisions/planning analysis/rules/ docs/3 3 6-9904 .pdf 

• Colorado DPHE (Denver) Regulation 7, updated 2011 

http: I lwww. colorado. gov I cs/Satellite?blo bcol=urldata&blobheadername 1 =ContentDisposition&blobheadername2=ContentType&blobheadervalue 1 =inline%3B+filename%3D%22Regulation+ ?+-

+Control +of+Ozone+ Viz+Ozone+ Precursors+%28Emissions+of+ V olatitle+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 

16 
mpounds+and+Nitrogen+Oxides%29.pdf0/o22&blobheadervalue2=application%2Fpdf&b 

lobkey=id&blobtable=MungoBlobs&blobwhere= 12518099953 74&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 

17 
Miscellaneous Metal Parts and Products Coatings 

Utah Draft Rule R307-350 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

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 by manufacturer; 

apparently applied to control device rather than overall control. Please clarify if it refers to both 

"control device" and "control system. The CTG recommends that add-on devices be coupled 

with capture systems to collect the VOC being released at the affected facilities in order to 

achieve an overall control efficiency of 90%. 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 collect at least 90%, by weight, of the VOC emissions generated by the 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/ton for Other 

Transportation at 35% control efficiency "derived from EPA database" is not verifiable or 

supported due to lack of documentation. The 2008 CTG lists CE of $1,7 58/ton and control 

efficiency of about 35% (from miscellaneous metal and plastic part coating). 

7. RE of 80%10 in Box Elder, Cache, Tooele, Utah, and Weber Counties and in Davis and Salt 

Lake Counties of 90%, 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&blobheadervalue 1 =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= 12518099953 7 4&ssbinary=true 

• EPA's CTG for miscellaneous metal and plastic parts coatings, 2008, 

http://www .epa. gov /ttn/ caaa/t 1 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 

18 
Large Appliance Coatings 

Utah Draft Rule R307-347 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

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 or control device O&M; entirely lacks provisions for monitoring 

and test methods. Much more detailed in SCAQMD and SJV APCD rules: specific records 

related to coatings; require records of key 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 if it 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 of90 percent (from CTG). 

4. Lack of application and TE requirements. SCAQMD (2006) and SJV APCD (2009) rules list 

various approved application methods. The CTG recommends specific application methods. 

5. Lack of requirements and restrictions related to sales or labeling of coatings or solvents. 

SJVAPCD and SCAQMD specify maximum VOC content of cleaners (25 g/L with exceptions). 

6. Work practices do not specify a maximum VOC content for cleaning solvent. SJVAPCD and 

SCAQMD specify maximum VOC content of cleaners (25 g/L with exceptions). 

7. Lack of limits on VOC content of cleaning solvent. 

8. CE of $2,020/ton at 30% control efficiency "derived from EPA database" is not verifiable or 

supported due to lack of documentation. EPA's CoST Model database lists CE of$2,027/ton at 

55% control efficiency for what appear to be similar measures (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 of 30%. 

9. RE of 80%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 1107,2006 http://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 

20 
Paper, Film, and Foil Coatings 

Utah Draft Rule R307-344 

Summary of concerns for draft rule 

1. Lack of !{ACT analysis for the source category; e.g., no information on range of control 

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 by manufacturer; 

apparently applied to control device rather than overall control. Please clarify if it 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 of 90%. 

4. Lack of application and TE requirements. 

5. Lack oflimits on VOC content of cleaning 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 of 80%12 is not supported due to the concerns identified and the lack of documentation 

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 

21 
Plastic Part Coatings 

Utah Draft Rule R307 -353 

Summary of concerns for draft rule 

1. Lack ofRACT analysis for the source category; e.g., no information on range of control 

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 by manufacturer; 

apparently applied to control device rather than overall control. Please clarify if it refers to both 

"control device" and "control system." The CTG recommends that add-on devices be coupled 

with capture systems to collect the VOC being released at the affected facilities in order to 

achieve an overall control efficiency of 90%. 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, of the VOC emissions generated by the sources of 

emlSSlOnS. 

4. Prohibits conventional air-atomizing spray equipment, but does not identify other application 

and lacks TE requirement. CTG recommends the specified use of one or more of the following 

coating application methods in conjunction with the use of low-V OC 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, or other coating application methods 

capable of achieving a transfer efficiency equivalent to or better than 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 CE value of$2,020/ton VOC "derived from 

EPA database" is not verifiable or supported due to lack of documentation. 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 of about 35% (from miscellaneous metal and 

plastic part coating). 

8. RE of 80%13 is not supported due to the concerns identified and the lack of documentation. 

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 

22 
Emissions Standards for Wood Furniture Manufacturing Operations 

Utah Draft Rule R307-343 

Summary of concerns for draft rule 

1. Lack of RACT analysis for the source category; e.g., no information on range of control 

technologies considered, control efficiencies, or other state rules evaluated. 

2. Alternative emission control system with overall 90% efficiency (capture and control) as 

certified by manufacturer. 

3. The Applicability of the draft rule is slightly less stringent than other rules. Phoenix rule 

(ozone SIP) is applicable> 2 tpy, but has less stringent limits and other provisions if< 10 tpy. 

SCAQMD has an exemption if use< 1 gal/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 

(per the CTG and existing rule). SCAQMD and SJVUAPCD rules have much lower limits as 

well as limits for more types of coatings. 

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 work practice 

implementation plan, operator training, leak inspection and maintenance plan, cleaning and 

washoff solvent accounting system, and spray booth cleaning solvent VOC limit. SJVUAPCD 

and SCAQMD specify maximum VOC content of cleaners (25 g/L with exceptions). Phoenix 

specifies maximum VOC content of spray booth cleaning solvent (8.0% by weight as in CTG). 

6. Insufficient MRRT. Only requires certified product data sheets for coatings plus 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 of key parameters for add-on control; test methods identified. CTG requires semiannual 

compliance reports. 

7. VOC content standards are much less stringent than California rules. 

8. No requirements related to sales or labeling of coatings or solvents. SJUAPCD and Phoenix 

require labeling of coatings. 

9. Lack oflimits on VOC content of cleaning solvent. 

10. CE of $2,260/ton 14 is not verifiable or supported due to lack of documentation. EPA's CoST 

Model database lists CE of$967/ton for 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 of 80%3 is not supported due to the concerns identified and the lack of documentation. 

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 

23 
Comparative 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/34 2-9611.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.s Nonattainment Areas 

Utah Draft Rule R307-312 

Summary of concerns for draft rule 

1. Lack of Reasonably Available Control Technology (RACT) analysis for the source category; 

e.g., no information on range of control technologies considered, control efficiencies, or other 

state rules evaluated. 

2. There are no MRRT requirements in the draft rule. 

3. The draft rule only has seven definitions while SCAQMD rule includes 54 definitions. The 

term "aggregate processing" is not defined in the draft rule even though it is the primary source 

being regulated. Enforcement of the rule may be hampered by lack of definition of the terms 

contained in the rule. Consideration should be given to defining more terms, such as those 

defined in the SCAQMD rule. 

4. Some requirements in the Utah rule 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 not provide any work practice standards for achieving the specified visible 

emission limits. 

The SCAQMD rule specifies the use of dust suppressants or other dust control methods to 

meet the visible emission standards, but does not specify specific work practice standards. A 

separate SCAQMD rule (Rule 403) for fugitive dust provides detailed work practice standards 

that apply to, among other sources, aggregate-related plants and cement manufacturing facilities. 

This rule includes work practice standards for screening and crushing, which are not provided in 

the draft rule. 

6. Alternative controls were not provided in the draft rule. 

The SCAQMD rule requires baghouses (fabric filters) for crushing and screening equipment, 

and allows for the use of dust suppressants or other dust control methods to meet visible 

emission standards as an alternative. 

7. CE was not identified in the draft rule. 

8. RE of 80%16 is not supported due to the concerns identified and the lack of documentation. 

Comparative materials identified 

• South Coast Air 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- PM10 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 PM25 Attainment 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/r420 1.pdf 

• CoST database http://www.epa.gov/ttn/ecas/cost.htm 

26 
Permits: PM2.5 Offset Requirements in PM2.5 Nonattainment Areas and in Salt Lake 

County, Davis County and Portions of Utah County Designated Nonattainment for PM2.5 

Utah Draft Rule R307-422 

Summary of concerns for draft rule: 

1. Under the Purpose section of the draft rule, it is not clear why the rule refers to filterable 

PM2.5, rather than total direct emissions ofPM2.5, including both filterable and condensable 

PM2.5. According to the 40 CFR 51.165(a)(1 )(xxxvii) definition of "regulated NSR pollutant," 

PM2.

5 emissions include condensable emissions, which must be accounted for in applicability 

determinations and in establishing emissions limitations for PM2.5 in nonattainment major NSR 

permits. This requirement has been in effect since January 1, 2011, per the definition revised in 

the 2008 PM2.5 NSR Implementation Rule (73 FR 28321, May 16, 2008). 

2. Under the "Applicability" section the draft rule should define how the impact is determined 

(e.g., model, protocol, modeled maximum of3.0 micrograms per cubic meter anywhere in the 

NAA, but 0.1 micrograms per cubic meter modeled at any monitor location). Also, the 

ruleshould make it clear on what 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 

or modification is considered to cause or contribute to violation of the NAAQS) is 1.2 

micrograms per cubic meter for the 24-hour averaging period. (This refers to the concentration 

ofPM2.5 only, not precursor concentrations.) 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. How was the "0.1 micrograms at any monitor" determined? This needs to be defined since 

the concept was not included in rule 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. But with 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 of volatile organic compounds or ammonia from sources in a 

specific area are a significant contributor to 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, when EPA issued final amendments to its rules for the 

NSR program regarding the definition of "regulated NSR pollutant." This action confirms that 

condensable particulate matter must be included as part of the emissions measurements for 

regulation ofPM2.5 and PM10. 

7. While emission reduction credits (ERCs) are defined in the rule in terms of tons/year, given 

that DAQ describes this as a winter-only nonattainment issue, consideration could be given to 

27 
defining or limiting ERC use in a seasonal manner. For example, ERCs created from 

predominantly summertime emission sources may be counterproductive if they are allowed to be 

used during wintertime. 

8. We have concerns regarding the definitions of"offset baseline date" and "pre-baseline ERC." 

We do not understand why the offset baseline date potentially could vary from area to area based 

on the effective date of the SIP. This is something that requires further discussion. We note, 

however, that we are not convinced that the overall approach the rule delineates for use of 

banked emission reduction credits that are "pre-baseline" is viable or consistent 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" emission reduction 

credits for offsets? Such historical emission reduction credits will not reduce area emissions or 

help the area achieve attainment. In fact, it appears to us that allowing use of such 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 Nonattainment Areas, but do 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 revisit those concerns to 

determine how they may impact R307-422. Without further review, it is not clear to us that the 

treatment of baseline for offsets in R307-403-7 or banking in R307-403-8 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/operator up to 180 days after a reduction has occurred to apply for an emission reduction 

credit. Would it make more sense to have an advance application for an emission reduction 

credit, followed by verification of an actual emission reduction and a permit condition restricting 

emissions consistent with the reduction? Whatever system is used, and regardless of whether 

we're considering new or old reductions, there must be some means to verify that the reductions 

to be used for offsets are real. 

12. Paragraph R307-422-4(3)(a) does not specify the offset ratio, where the CAA requires at 

least a 1:1 ratio for PM. Also, given the use of the terms "major modification" and "major 

source," the rule should indicate that they are defined in R307-101-2. 

13. The definitions for "major modification" 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 precursor to PM2.5 since it is not 

defined in § 51.165. 

15. Please provide an explanation of how this requirement for major sources and major 

modifications under R307-422-4(3)(a) satisfies the offset requirements of the Act, and 

inconsideration of the Act's requirement for reasonable further progress in the attainment plan. 

16. R307 -422-4(3)(b )(i) and (ii) needs to be revised to state: "New sources or modifications 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 interpollutant trading for nonattainment major NSR 

without a demonstration by the State. We recognize that R307-422-4(3)(b)(i) and (ii) do not 

supplant the rule's major source requirements, but allowing ERC credit for "any of these 

pollutants" found under R307-422-4(3)(b)(i) and (ii) is nonetheless questionable. Our concern is 

28 
that the rule's approach could result in an increase in ambient concentrations, if, for example, 

sources were to offset direct PM2.5 with precursor reductions. Thus, it is not clear to us that the 

rule is consistent with CAA requirements, including those of CAA 11 0(1). 

18. R307-422-4(3)(c)(i) would be improved by adding the word "increases" as follows: " ... 

required to offset those emissions increases at a .... " 

19. As discussed previously, the 10 tpy under R307-422-4(3)(c)(i)(A) should include emissions 

of both condensable and filterable PM2.5. 

20. What is meant by "effective period ofthe plan" found under R307-422-4(3)(d)(i)? What 

happens after that period? 

21. We are not convinced that the tracking and usage restrictions are sufficiently reliable or 

enforceable. Also, it may be useful to describe and review the magnitude of the threshold 

identified in the PM2.5 state implementation plan (SIP) for each nonattainment area. However, 

as noted previously, we have a general concern regarding the use of pre-baseline credits to offset 

new emissions in the nonattainrnent areas. 

29 
Road Salting and Sanding 

Utah Draft Rule R307-307 

Summary of concerns for draft rule: 

1. Section R307-307-1 was revised to provide boundaries based on geological landmarks. This 

section needs to be changed to either specify that the boundary is for all PM2.5 nonattainment 

areas or reference the CFR which provides the legal description for the nonattainment area 

boundaries. ( 40 CFR 81.345). 

2. R307-307-4 requires a demonstration with respect to PMlO emissions but does not discuss 

PM2.5 emissions. This provision should be 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 

EPA Region 8 Comments PM2.5 SIP Sub Sections IX.H.11, 12, 13 

General Comments 

Section IX lacks a description of the relationship between Section IX's requirements, 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? If so, how were these requirements incorporated? These interconnections must be 

clearly described in the 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 notes that an applicability date of January 1, 2018 seems to apply to most or all 

of the General Requirements. What precludes advancing this date? What makes January 1, 

2018 reasonable or an earlier date unreasonable? 

1. VOC control: For VOC 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 1 gram per kilogram 

of coke bumoff (equivalent to 2 lbs per ton). This is the same stringency as the limit in NSPS 

Subpart J (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. S02 emissions from FCCUs: The State is proposing an emission limit of 50 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 that NSPS doesn't specify an averaging time, therefore 

presumably it is the average of three 1-hour stack test runs). The current NSR permit for at least 

one of the 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 of the limits in NSPS 

Subpart Ja, which is not in Subpart J). The 2005 PM10 SIP submittal had a limit of9.8 kg ofS02 

per 1,000 kg of coke burn off, which is the same as the NSPS Subpart J limit for FCCU s with no 

add-on control device for S02. 

It is unclear which of the 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 limit represents a 

reduction in so2 emissions from the 2008 baseline emissions inventory. 

4. S02 emissions from SRUs: The State is proposing an S02 emission limit of2,500 ppmv. 

This is the same as one of the emission limits in NSPS Subpart Ja. For SRUs smaller than 20 

1 
long tons per day, Subpart Ja specifies a limit of2,500 ppmv, if the 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 of reduced sulfur 

compounds and 100 ppmv of H2S. 

NSPS Subpart J specifies an emission limit of250 ppmv for SRUs having an oxidation control 

system or a reduction control system followed by incineration. For a reduction control system 

not followed by incineration, the Subpart J limit is 300 ppmv of reduced sulfur compounds and 

10 ppmv ofH2S.) However, neither of the Subpart J limits apply to Claus sulfur recovery plants 

(SRUs) with a design capacity for sulfur feed of20 long tons per day or less. 

The following is unclear a) which of the five SLC refineries have SRUs smaller than 20 long 

tons per day, b) which of the refinery SRUs have an oxidation system or reduction control 

system followed by incineration, and c) which of the SRUs might already be subject to Subpart 

Ja. Thus, it is uncertain whether the proposed 2,500 ppmv limit represents 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. EPA had raised enforceability issues 

with the 95% requirement in its December 1, 2009 FR notice 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 now proposing to replace the 95% efficiency requirement with a 2,500 

ppmv emission limit. Since the State's new proposal does not indicate how compliance with the 

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 that the S02 CEMS should be used to track 

emission compliance at the SRUs. No S02 CEMS is mentioned in the State's new proposal. 

Also, the State is proposing a new exemption from SRU emission limits, during periods of 

maintenance of the sulfur pit. This new exemption appears to be the same as in NSPS 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. Our position on this issue was recently upheld by 5th 

Circuit Court of Appeals. See 77 FR 49507 (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 S02 emission 

limit of 20 ppmv, or an alternative a limit of 162 ppmv for H2S in fuel gas, applicable starting in 

2018. These proposed limits are the same as in NSPS Subpart Ja, at 40 CFR 60.1 02a(g)(l )(i). 

The NSPS Subpart J limit is 0.1 gr/dscffor H2S in fuel gas, which is roughly equivalent to 160 

ppmv. Since this limit was in the 2005 PM10 SIP submittal, the State's proposed limit does not 

appear to represent a reduction in so2 emissions from the 2008 baseline emissions inventory. 

2 
The State has, however, apparently removed the exemption from this limit during startup, 

shutdown or malfunction of the amine plant, an exemption which was in the 2005 PM10 SIP 

submittal and which was identified by EPA as an issue in its December 1, 2009 proposed 

disapproval ofthe 2005 submittal. We support removal of the exemption to ensure consistency 

with CAA requirements. 

6. S02 emissions from flares: The State is not proposing any emission limits, nor investigation 

of any possible ways to capture flare emissions. Instead, the State is proposing to require a flare 

management plan (i.e., work practice requirements in lieu of emission limits), for minimizing the 

amount of gases that are routed to the flares. This appears to be the same as the requirements for 

flares in NSPS Subpart Ja, at 40 CFR 60.1 03a. The State's proposal does not sufficiently 

address the issues about flares that EPA raised in its December 1, 2009 proposed disapproval of 

the 2005 PM10 SIP submittal. The issue was lack of appropriate restrictions for flaring emissions 

at refineries. EPA expressed concern that flare emissions during upsets might interfere with 

maintenance of the NAAQS and that the submitted SIP explicitly ignored such emissions for 

purposes of assessing compliance with daily and annual emission caps. EPA did not say that a 

flare management plan of the type now proposed by the State would resolve these issues. 

The State's new proposal for a flare management plan does take some steps to quantify flare 

emissions, by requiring an evaluation of baseline flow to the flares, but does not actually require 

the refineries to quantify flare emissions, which was one of the issues raised by EPA in 2009. 

The new proposal 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 appear to 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. It does not appear that the RACT analyses in the 

TSD were used to identify any new control 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 of adequate records, and periodic reporting. 

Many ofthe source-specific provisions are deficient in this area. We have not attempted to 

identify all MRR deficiencies in our comments. 

2. PM condensables. The State is proposing PM2.5 emission limits that include condensables at 

Holly Refinery, at the Kennecott Smelter Main 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 emission limit at Holly applies to external combustion process equipment. Since 

3 
the same type of equipment exists at the other refineries, for consistency we would expect PM2_5 

emission limits (including condensables) as RACT at the other refineries as well. 

Source-Specific Comments on Sections IX.H.12 and IX.H.13: 

In the comments below, EPA refers back to the 2005 PM10 SIP submittal. This is done only for 

purposes of comparison to the current proposal, and is not meant to imply that EPA is still 

reviewing the 2005 submittal, which was withdrawn by the Governor of Utah on October 7, 

2011. EPA also refers back to the June 27,2011 SIP submittal for the Kennecott Bingham 

Canyon Mine Expansion (which included source-specific provisions for the other sources that 

were in the 2005 SIP submittal), again only for purposes of comparison to the current proposal. 

EPA has not yet acted on the 2011 SIP submittal. 

1. ATK Launch Systems: 

• The proposed provisions consist solely of limits on the pounds of reactive waste and 

rocket motor propellants that may be burned "when the PM2.slevels exceed 35 ug/m3 at 

the nearest real-time monitoring station." These appear to be new provisions that are not 

in any existing State rules or NSR permits applicable to ATK. These proposed 

provisions are inconsistent with the CAA and EPA's regulations on dispersion techniques 

and intermittent control systems ( 40 CFR 51.118 and 51.119) and are not creditable for 

purposes of demonstrating attainment or meeting RACT requirements. They are not a 

substitute for continuous emissions limits/controls. Also, in effect, these provisions treat 

the area around A TK as an independent nonattainment area. 

• No emission controls, or efforts to minimize the above-mentioned open burning, or to 

investigate alternatives to open burning, such as waste minimization or transporting the 

materials somewhere outside the nonattainment area before burning, are proposed. The 

proposed provisions do not appear to be based on a RACT analysis nor is it clear whether 

these provisions represent a reduction from 2008 baseline emissions. It is also not clear 

what pollutant(s) these provisions are intended to address. A meaningful RACT analysis 

is required for A TK. 

2. Big West/Flying J Refinery: 

All proposed provisions appear to be the same as in the 2005 PM10 SIP submittal, with 

respect to daily emission limits and associated enforceability provisions. No new 

emission limits are proposed. Therefore, the proposed provisions 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 of the 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 
• The proposed provisions, which consist ofNOx emission limits at three combustion 

turbines, are not enforceable, as there are no enforceability provisions. The proposed 

NOx limits for Turbine #1 are in tons per day and grams/kW-hr, and for Turbines #2 and 

#3 are in ppm and lb/hr. Also, engine #8 is not addressed in the proposed provisions. 

The current NSR permit limits use of engine #8 to 1,600 hours per year. 

• Since the 2005 PM10 SIP submittal included a NOx emission limit for only one 

combustion turbine, and since the current NSR and title V permits also list only one 

turbine at the facility, the proposed provisions appear to represent an increase from 2008 

baseline emissions, by allowing for two new combustion turbines. The current NSR 

permit says that five existing internal combustion engines are to be replaced when the 

new turbines are installed. Have they been replaced? 

• 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 current NSR permit 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 

in the proposed provisions. 

4. Central Valley Water Reclamation: 

• The only emission limit for this source in the 2005 PM10 SIP submittal, which was a NOx 

emission limit of 0.648 tons per day, for the combined emissions of all engines, has not 

been included in the proposed provisions. It is not clear why not. Instead, the proposed 

provisions basically consist only of a work practice requirement to "remove the biosolids 

from the facility." This requirement is apparently new with this proposal, not carried 

over from any existing rules or NSR permits. No explanation has been provided how this 

requirement might reduce emissions from 2008 baseline, or how this requirement might 

relate to emissions at all. Also, a director's discretion provision is included, which would 

allow for alternatives to this requirement. EPA has explained previously why director's 

discretion provisions are not approvable in SIPs. 

• The current NSR permit 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 each backup generator are limited to 7.13 lb/hr and 1.8 grams 

per hp-hr. The permit 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 NSR permit 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 current NSR 

permit limits the VOC content in paint to the density limits established in R307-340. EPA 

notes that Table 6.3 on page 55 of the Salt Lake County SIP narrative lists VOC 

emissions of0.137 tons per day in 2008, but only 0.032 tons per day in 2014. Please 

explain why the State is projecting a 77% decrease in VOC emissions from 2008 to 2014 

given the lack ofVOC limits in the SIP. 

5 
5. CER Generation: 

• The proposed provisions do not include a NOx emission limit from the current NSR 

permit of 5 ppmdv for each turbine, on a 30-day rolling average. This limit was 

established as LAER in the initial NSR permits for each of the 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/dscf at the Hydrator 

Baghouse, and 24.78lblhr and 0.19 gr/dscfat the 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 current NSR permit, issued in 2006. Therefore, the proposed 

provisions do not appear to represent any reduction from 2008 baseline emissions. 

• The proposed provisions include headings at the Hydrator Baghouse and Kiln 

Electroscrubber for PM2.s, but no emission limits for PM2.5, just blanks. 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: 

• Other than the exceptions noted in the comments below, all proposed provisions appear 

to be the same as in the 2005 PM10 SIP submittal, with respect to daily emission limits 

and associated enforceability provisions. 

• The proposed provisions include a S02 emission limit of 0.5 tons per day, to include gasfired compressor drivers and all external combustion process equipment, but excluding 

the SRU, the FCCU CO Boiler, and the FCCU Catalyst Regenerator. The limit in the 

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 that they are substantial sources of S02 emissions, and considering that 40 

CFR 51.1 002( c)( 1) requires an evaluation of control measures for S02. The proposed 

provisions do not include any separate so2 limit for these two units, just a separate so2 

limit of2.128 tons per day for the SRU, same as the 2005 PM10 SIP submittal. 

• Similarly, for NOx the proposed provisions include an emission limit of2.52 tons per 

day, to include gas-fired compressor drivers and all external combustion process 

equipment. The limit in the 2005 PM10 SIP submittal was 3.248 tons per day, which also 

included the FCCU CO Boiler, Catalyst Regenerator and SRU-TGI. Please explain why 

these three units are no longer included, considering that they are substantial sources of 

NOx emissions, and considering that there is a subsection in the proposed provisions that 

says the NOx emissions from the FCCU CO Boiler and Catalyst Regenerator may be 

6 
determined by CEM. It is 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 "Sulfur Recovery Unit (SRU)," item C says "Whenever the 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 

provision has also been provided for Tesoro refinery, it has not been provided 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 why the S02 CEM 

would need to be bypassed. Please also explain why it should be reasonable to rely on 

CEMS data from the previous three days. This approach does not account for the 

possibility that emissions might be higher during CEM bypass. Please also explain why 

special provisions for CEM bypass should be 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 PM10 SIP submittal 

appear to be removal of S02 and NOx emission limits for certain large emitting units, and 

removal of annual limits, the proposed provisions 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 of the 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: 

• The proposed provisions consist only of a requirement to replace existing wet scrubber 

AH-013 with a baghouse by January 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 new baghouses, and a requirement to propose a PM2.5 emission 

limit for each of the two new baghouses. Please explain why the proposed provisions do 

not include PM emission limits for any of the 13 existing PM control devices. Existing 

NSR permits 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 current NSR permit. 

• Please also explain why GSLM is given until 201 7 to install one of the 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 new baghouses 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 monitor the oxygen content at the RTOs. Since this provision 

only pertains to future carbon fiber lines, it does not appear to represent a reduction from 

2008 baseline emissions. Without specifying minimum oxygen content at the RTOs, the 

requirement to monitor for oxygen content is of no value for minimizing emissions. The 

requirement to monitor is unenforceable without a specified frequency of monitoring and 

adequate recordkeeping and reporting requirements. The provision allows the use of an 

equivalent technology with equivalency to be determined by the Director. This is an 

unacceptable director's discretion provision. 

• The current NSR permit for Hexcel has parametric limits for 15 existing fume 

incinerators, in terms of incinerator temperature, 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 why the 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 provision to require RTOs at all future carbon fiber lines, and to monitor their 

operation, is intended to minimize VOC emissions, and therefore could be viewed as a 

surrogate for VOC emission limits. EPA recognizes that parametric monitoring is 

appropriate to ensure proper operation ofRTOs on an ongoing basis. 

10. Holly Refinery: 

• Other than the exceptions noted in the comments below, all proposed provisions appear 

to be the same as in the 2005 PM10 SIP submittal, with respect to daily emission limits 

and associated enforceability provisions. 

• The proposed provisions include a PM10 emission limit of 0.51 tons per day (filterable 

plus condensable), for combined emissions from all external combustion process 

equipment, including the SRU-TGI (but apparently excluding the FCCU). Also proposed 

is a PM2.s emission limit of 0.237 tons per day, (filterable plus condensable), for the same 

group of emitting units. These proposed limits are apparently new with this proposal, not 

carried over from any existing rules or NSR permits applicable to Holly. EPA does not 

know if these proposed new limits are based on any new controls or represent any 

reduction from 2008 baseline emissions. 

The 2005 PM10 SIP submittal included a filterable PM10 emission limit of0.444 tons per 

day for the same group of emitting units. EPA does not know 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 what portion of the PM emissions are 

condensables. It does appear, however, that the State is assuming PM2.5 emissions are 

8 
about 46% of the mass of total PM10 emissions at external combustion process equipment 

at this refinery. Please provide confirmation of this. 

• The proposed S02 emission limit of 4.714 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 S02 emission limit includes the 

SRU-TGI. This appears to be an omission or error in the proposed provisions. 

• The proposed NOx emission limit of2.20 tons per day does not appear to include the 

FCCU or the SRU-TGI. These are substantial sources ofNOx emissions. The same NOx 

limit in the 2005 PM10 SIP submittal included the SRU-TGI. This also appears to be an 

omission or error in the proposed provisions. 

• No VOC emission limits, or surrogates for VOC limits, are proposed. EPA notes that 

Table 6.3 on pages 55-56 of the Salt Lake County SIP narrative lists VOC emissions of 

0.622 tons per day 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: 

• The proposed provisions for the Mine include a restriction to 30,000 miles per calendar 

day of ore 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 explanation has been provided on how this 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 proposed provisions for the Mine also include fugitive dust control measures for haul 

roads and other unpaved roads, consisting of watering and use of chemical dust 

suppressant. While this potentially addresses another shortcoming that EPA identified in 

the 2005 PM10 SIP submittal (which was lack of any 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 stringent than what Kennecott has been required 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 planned to be dropped. Also, the SIP will need to include a 11 0(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. 

• The proposed provisions for the Mine do not include any limit on amount of material 

movement (ore plus waste) per 12-month period, nor any limit on S02 emissions. We 

9 
note that the 2011 SIP submittal for the Mine Expansion specified a new limit of 260 

million tons of material movement per 12-month period, and a limit of 97 tons per year 

of S02, with the S02 emissions to be calculated on the basis of gallons of diesel fuel used 

at the Mine,. Please explain whether the PM2.5 NAAQS attainment demonstration 

assumes these levels of limits on allowed material movement and S02 emissions, and 

why no limits on material movement or S02 emissions are included in the proposed 

source-specific provisions for the Mine. 

• None of the S02 emission limits from the 2005 PM10 SIP submittal are included, for 

either the Mine or the Concentrator. The 2005 SIP submittal included a limit on sulfur 

content in diesel fuel at the Mine of 0.03 lb sulfur per MMBtu. The 2005 SIP submittal 

also included a limit of 0.314 tons per day of so2 for the molybenite rotary kiln at the 

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 projected to decrease by more than 

half from 2017 to 2019. (Ref: Table 6.3 on pages 55-56 of Salt Lake County SIP 

narrative.) Please explain this decrease considering that no VOC emission limits are 

proposed. 

12. Kennecott Power Plant/Lab/Tailings Impoundment: 

• There are no proposed provisions for the Tailings Impoundment facility. Detailed 

fugitive dust control provisions are in the 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 Power Plant, the only proposed provision is a prohibition 

against operation after January 1, 2018 (or after new Unit #5, a combustion turbine, 

commences operation, whichever is sooner). The current NSR permit (dated December 

2011), which approved construction of the new turbine, prohibits operation of Boilers 1-3 

after the new turbine commences operation and does not mention January 1, 2018. Please 

explain why a date later than the PM2.s attainment date of 2014 has been included and 

why such date is reasonable. 

The 2005 PM10 SIP submittal, as well as the current NSR permit, include PM10 and NOx 

emission limits for Boilers 1-3. One set oflimits is for operation during winter months 

on natural gas. The other set of limits is for operation during non-winter months 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" on the state's website includes corrections for 

existing Boiler 4, to now specify PM2.5 and NOx emission limits, before and after January 

1, 2018. Since these proposed limits are no more stringent than the PMw and NOx limits 

in the 2005 PM10 SIP submittal, the proposed limits do not appear to represent a 

10 
reduction from 2008 baseline emissions. Also, the SIP must justifY the implementation 

date of January 1, 2018 and why measures could not be advanced to an earlier year. 

• Also, please explain why the proposed provisions (including the above-mentioned 

corrections) do not include limits on amount of fuel use at the boilers. The following fuel 

restrictions, for the total of Boilers 1-4, were included in the 2005 PM10 SIP submittal, 

and are in the current NSR permit (issued in 2009) and the current title V permit: 

> Limit of 42,706 MMBtu/day of natural gas usage 

> Limit of 31,510 MMBtu/day of coal usage during natural gas curtailments in 

Winter months 

• The proposed provisions include VOC, NOx and PM2.s emission limits for the anticipated 

new Unit #5 (a combined cycle combustion turbine). These limits are not new with this 

proposal, but are carried over from the current NSR permit dated Dec. 2011. The PM2.s 

limit of 18.8 lblhr includes condensables. (EPA notes that Table 6.3 on page 56 of the 

Salt Lake County SIP narrative lists 0.006 tons per day for 2008 and 2014, but 0.066 tons 

per day for 2017 and 2019. Please explain whether this is a typo.) 

• Overall, the proposed provisions for the Power Plant do not appear to represent a 

reduction from 2008 baseline emissions. Prior to 2018 at least, the four existing boilers 

at the Power Plant will still be allowed to operate, and for Boilers 1-3, with no emission 

limits in the proposed provisions (unlike the 2005 PM10 SIP submittal). For Boiler 4, the 

proposed limits are no more stringent than the limits in the 2005 PM10 SIP submittal. 

• We are also concerned that the limits for Unit #5 appear to include an exemption for 

startup and shutdown and transient load conditions. Such an exemption is inconsistent 

with CAA requirements. 

• The MRR provisions are insufficient. No test methods are specified, and there are no 

recordkeeping or reporting requirements. 

13. Kennecott Smelter and Refinery: 

• Emission limits are proposed for S02 only at the smelter main stack and the acid plant 

tailgas, same as the 2005 PM10 SIP submittal, but the numerical values of the proposed 

limits at the main stack have been updated from the 2005 SIP submittal to reflect limits in 

the current NSR permit. New limits for PM2.5 described below are proposed for the main 

stack, which are not in the current NSR permit. 

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 or NSR permits applicable to the smelter. After taking into account the 

ratio ofPM2.5 to 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 

11 
the 2005 PM10 SIP submittal, which was 89.5 lb/hr. Therefore, the proposed limit 

appears to represent little, if any, reduction from 2008 baseline emissions. 

Please explain why no emission limit is proposed at the smelter main stack for NOx. The 

proposed provisions include a requirement for a NOx CEM at the 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 current NSR permit, dated May 2011. 

• The proposed S02 emission limits for acid plant tailgas, which are 1,050 ppmdv on a 3-

hour rolling average and 650 ppmdv on a 6-hour rolling average, are the same as in the 

2005 PM10 SIP submittal, but that submittal was out-of-date with respect to NSR permit 

limits in effect at that time. The emission limits for acid plant tailgas in the August 2000 

NSR permit, which have been carried over into all subsequent NSR permits, are 250 

ppmdv on a 6-hour block 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 much higher than what the source is already required to meet. Is 

this an inadvertent error? 

• The proposed S02 emission limits for the main stack and acid plant tailgas are carried 

over from NSR permits dating back to August of2000 or earlier, or else are less stringent 

than current limits in the case of acid plant tail gas (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 

just to conduct a stack test for PM2.5 once a year. While EPA presumes this is because 

the PM measurement device at the main stack is not designed to separate out the fraction 

of PM that is smaller than 2.5 microns, this is not explained by the State. 

• Please explain why the proposed provisions for the smelter do not include provisions 

from the 2005 PM10 SIP submittal for recordkeeping, calculation procedures, and CEMS 

QA for the S02 and NOx CEMS. EPA considers such provisions 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 or reporting requirements 

for any pollutants at either the smelter or the refinery. 

• Please explain why the proposed provisions for the smelter do not include the measures 

in the 2005 PM10 SIP submittal for reducing escape of pollutants to the atmosphere and to 

capture emissions and vent them through a stack or stacks, as well as a requirement to 

keep a log of any instances where the sulfuric acid plant is bypassed. 

• The only proposed emission limit at the Kennecott Refinery, which is 9.5 lbs/hr for the 

combined NOx emissions of two boilers, is equivalent to the limit in the 2005 PM10 SIP 

submittal, which was 0.057 tons per day for each boiler. The proposed limit therefore 

does not appear to represent a reduction from 2008 baseline emissions. 

12 
• Overall, the proposed provisions 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 proposed provisions (NOx emission limits of 95 ppmdv on a 4-hour average and 25 

ppmdv on a 24-hour average, for each of the three 14.3 MW combustion turbines) are the 

same as in the current NSR permit, issued in 2004. Therefore, the proposed provisions 

do not appear to represent any reduction from 2008 baseline emissions. 

• NSPS subpart GG has a limit on sulfur content in turbine fuel of 0.05% by weight. This 

limit is included in the current title V permit. Please explain why this limit is not 

included in the proposed provisions. 

• The proposed provisions lack recordkeeping and reporting requirements. 

15. Nucor Steel: 

• The proposed 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 in the current NSR permit (issued in June of201 0) is 20.06 lbs/hr. 

This limit has been in effect in NSR permits 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 current NSR permit, but also include a S02 limit of 78.54 lbs/hr on an 

annual average, which is apparently a new limit with this proposal that does not appear in 

any existing rules or permits applicable to Nucor. Since this proposed limit is equivalent 

to 344 tons per year, it is less stringent than the limit of 322 tons per rolling 12-month 

period in the current NSR permit. The proposed S02 limits therefore do not appear to 

represent a reduction from 2008 baseline emissions. 

The proposed provisions do not include any short-term NOx emission limits for the EAF 

baghouse, nor does the current NSR permit. The only proposed NOx 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 or permits applicable to 

Nucor. Since this proposed limit is equivalent to 262 tons per year, it is less stringent 

than the limit of245 tons per rolling 12-month period in the current NSR permit. The 

proposed limit therefore does not appear to represent any reduction from 2008 baseline 

emtsswns. 

Please explain how the proposed S02 and NOx emission limits could constitute RACT 

when they are higher than existing limits in the current NSR permit. 

13 
• The proposed VOC emission limit of22.2lb/hr is carried over from the current NSR 

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 at the reheat boilers. The proposed provisions 

also lack recordkeeping and reporting requirements. 

16. PacifiCorp Gadsby Power Plant: 

• The only emission limit in the proposed provisions is a NOx limit of 6.57 tons per day, 

for the total of all boilers and combustion turbines. This limit is carried over from the 

2005 PM10 SIP submittal. The limit is not enforceable with respect to the turbines 

because there is no indication how turbine emissions are to be measured, just the boiler 

emissiOns. 

• The proposed provisions require NOx CEMS for the boilers, but not for the turbines. 

The 2005 PM10 SIP submittal required that emissions from both the boilers and the 

turbines be measured by CEMS, as required by 40 CFR Part 75 (Acid Rain Program). 

Please explain why this requirement does not appear in the proposed provisions. 

• Please explain why the proposed provisions do not include the following NOx emission 

limits which are in the current NSR and title V permits: 

> Boiler 1: 179 lb/hr, 336 ppmdv 

> Boiler 2: 204 lb/hr, 336 ppmdv 

> Boiler 3: 142 lb/hr, 168 ppmdv 

> Combustion turbines (all three combined): 22.2 lb/hr 

> Each combustion turbine: 5 ppmdv (30-day rolling average); 

116 ppmdv (not to exceed at any time) 

• The proposed provisions also lack recordkeeping and reporting requirements. 

17. Proctor & Gamble Paper Manufacturing Plant: 

• Please explain why the only emission limit in the proposed provisions is a PM10 limit of 

6.65 lb/hr, for each ofthe two paper machines. The proposed provisions do not include 

NOx emission limits in the current NSR permit at the four boilers (3.3 lb/hr and 45 ppm 

for each boiler) and at the two paper machines (13.50 lb/hr and 0.09lb/MMBtu for each 

machine). These are the main emitting units at the facility. 

• The proposed provisions include a heading for PM2.s, but no emission limit for PM2.s, just 

a placeholder saying "To be determined by January 1, 2015." This is not sufficient. 

Please explain why a date later than the PM2.s attainment date of2014 has been included, 

and why advancing the date would not be reasonable. 

14 
• No VOC emission limits, or surrogates for VOC limits, are proposed. The VOC 

emission potential was listed in the initial NSR permit action as 213 tons per year. A 

RACT review for VOC would seem to be warranted. 

• The proposed provisions do not specify any stack test methods, nor any recordkeeping or 

reporting requirements. 

18. Tesoro SLC Refinery: 

• Other than the exceptions noted in the comments below, all proposed provisions appear 

to be the same as in the 2005 PM10 SIP submittal, with respect to daily emission limits 

and associated enforceability provisions. 

• The proposed provisions include a PM2.s emission limit of 4 lbs/MMSCF at the 

FCCU/CO Boiler. This is apparently a new limit with this proposal, which does not 

appear in any existing rules or permits applicable to Tesoro. The limit is not enforceable 

because the proposed provisions do not specify a stack test method. There is also no 

indication whether the 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 

whether the proposed limit represents 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 of the Salt Lake County SIP narrative lists VOC emissions of 

0.748 tons per day in 2008, 0.744 in 2014, 0.852 in 2017, and 0.796 in 2019. A RACT 

review for VOC would seem warranted. 

• Under the heading "S02 Emission Limits" (which apparently pertains to the entire 

refinery), item E says "Whenever the S02 CEM is unavailable for short periods (i.e., CO 

boiler or ESP 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." Although this CEM provision has also been provided for 

Chevron refinery, it has not been provided 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 of is the one at the SRU. We are not aware of any reason 

why that CEM should be unavailable during abnormal conditions at the CO boiler, ESP, 

or FCC. 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: 

15 
This source in Salt Lake County did not have source-specific provisions in the 200S PM10 

SIP submittal. Nearly all emissions come from natural gas fired boilers in various 

buildings, of which the largest boilers are in Building 302 (three boilers rated at 87.S 

MMBtulhr each) and Building 303 (three boilers rated at 1 OS MMBtulhr each, and a 

combustion turbine with WHRU rated at 8S MMBtulhr). 

• The proposed provisions consist of the following NOx emission limits: 

~ Boilers #3 (sic) - 2S lb/hr and 187 ppmdv 

~ Boilers #4a & 4b -- 3.0 lb/hr and 9 ppmdv for each boiler 

~ Boilers #Sa & Sb -- 3.0 lb/hr and 9 ppmdv for each boiler 

~ Turbine and WHRU duct burner- 8.87lb/hr and 1S ppmdv 

The proposed provisions were apparently carried over from the current NSR permit, 

dated June 2011, but with at least one apparent error. The limits of2Slb/hr and 187 

ppmdv pertain to each of Boilers 3-S in Building 303, not to "Boilers #3." 

• The proposed provisions require an "initial test" for Boilers #4a & 4b by 2018, and an 

"initial test" for Boilers #Sa & Sb by 2017. Since none ofthese boilers are listed in the 

current NSR or title V permit, it appears that the proposed provisions are allowing for 

addition of four new boilers of unspecified size and type. 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 proposed provisions specify that "Unit #3" (which EPA assumes is Boiler #3 in 

Building 303, but this is unclear) shall only be used as a backup/peaking boiler after 

January 1, 2019, but that if it is replaced with a "low-NOx boiler(s)", it may be used 

continuously. Please explain how this provision could be considered a reduction from 

2008 baseline emissions. Please also explain why a date later than the PM2.S attainment 

date of 2014 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 in Buildings SSS & SS6, nor the boilers in 

Buildings S21/S2S/S26. Under the current NSR permit, the boilers in these 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 at the 

University: 

~ Boilers in Building 303 -- 12S MMSCF/yr 

~ Boilers in Building 302- 8S8 MMSCF/yr 

~ Boilers in Buildings SSS & SS6- 212.1 MMSCF/yr 

~ Boilers in Buildings S21/S2S/S26- 200 MMSCF/yr 

Of particular note is that the boilers in Building 302 are allowed to use nearly seven times 

as much fuel annually as the boilers in Building 303. Although the current NSR permit 

does not have emission limits for the boilers in buildings other than 303, please explain 

why the boilers at those other buildings should not be subject to RACT review and 

16 
emission or consumption limits (or at least the boilers in Building 302, which apparently 

account for the most emissions). 

The proposed provisions do not specify any stack test methods, nor any recordkeeping or 

reporting requirements. 

20. Brigham Young University: 

• This review takes into account the recent corrections to the proposed provisions, which 

are part of the "Updated SIP Documentation" on the state's website. The largest emitting 

units are six central heating plant boilers. 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 stringent than 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 per rolling 12-month period. The 

proposed provisions go on to say that if Boiler #1 is operated more than 300 hours, then 

low-NOx burners with FGR shall be installed and tested. Given that Boiler #1 is operated 

only as a backup boiler, please explain whether the proposed new emission limits for 

Boiler #1 would result in any reduction from 2008 baseline emissions. 

• Please explain why the proposed provisions do not include any of the following emission 

limits or other requirements that have been in effect in NSR permits dating back to 2004 

or earlier: 

~ NOx emission limits in lblhr and ppmdv for each of Boilers #2, 3 and 5 

~ PM10 emission limits of 1.83 lblhr and 0.010 gr/dscf for the Central Heating Plant 

Baghouse. 

~ Limits on sulfur content in coal and fuel oil 

• The proposed provisions do not specify any stack test methods, nor any recordkeeping or 

reporting requirements. 

21. Geneva Nitrogen: 

• The proposed provisions consist ofNOx emission limits of 32.4 lblhr and 267.0 ppmdv at 

the Montecatini Acid Plant Vent, and 19.4lblhr and 438.0 ppmdv at the Weatherly Acid 

Plant Vent. Also proposed is a PM10 emission limit of 0.24 tons/day at the Prill Tower. 

These provisions are carried over from the current NSR permit, issued in 2003. 

The 2005 PM10 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 equivalent to the tons/day limits at both 

acid plants that were in the 2005 and 2011 SIP submittals. The proposed provisions 

therefore do not appear to represent a reduction from 2008 baseline emissions. 

17 
The proposed provisions do not specify any stack test methods, nor any recordkeeping or 

reporting requirements. 

22. Pacific States Cast Iron Pipe: 

The proposed provisions include a PM10 emission limit of 0.015 gr/dscf at the cupola 

baghouse. Please explain whether this proposed limit might represent a reduction from 

2008 baseline emissions of PM10, considering that the facility is not currently subject to 

any PM10 emission limits. EPA is not aware of any plans to upgrade the baghouse, or do 

anything else to reduce the current PM10 emissions. 

• The proposed provisions also include a plantwide VOC emission limit of 260 tons per 

rolling 12-month period. 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 combustion processes. 

The current NSR permit includes a VOC emission limit of 355 tons per rolling 12-month 

period, for combined emissions from the cupola, pipe coating, and related operations. 

This limit has been in NSR permits for this facility dating back to 2005 or earlier. Since 

the proposed new limit of 260 tons is substantially lower, the new limit potentially 

represents a substantial reduction from 2008 baseline emissions ofVOC. However, EPA 

notes that daily VOC emissions in Table 6.3 on page 54 of the Utah County SIP narrative 

(which represents "growth and control") are projected to increase from 0.515 tons per day 

in 2008 to 0.759 tons per day in 2019. Please explain whether the proposed reduction in 

the emission limit is factored into these emission projections. Please be aware that if a 

reduction in emissions is factored into the emission projections used for 24-hour NAAQS 

attainment modeling, the reduction would need to be reflected in a short-term (daily) 

limit. 

Please also explain whether the required manner of showing compliance with the 

proposed new limit is intended to include cupola emissions as one of the "combustion 

processes." 

• The current NSR permit also includes a NOx emission limit for the cupola baghouse of 33 

lbs/hr and a S02 emission limit of 0.23 lb/ton of iron melted. Please explain why these 

limits are not included in the proposed provisions as RACT. The cupola baghouse is the 

main emitting point at the facility. 

• The proposed provisions also include a requirement to propose a PM2.s emission limit, 

within 120 days after the stack testing at the cupola baghouse, which is due by January 1, 

2015 (after the 2014 PM2.5 attainment date). Please explain why advancing this date 

would be unreasonable. 

• The proposed provisions do not specify the stack test method for PM10 at the cupola 

baghouse, nor any recordkeeping or reporting requirements for stack tests .. 

18 
23. PacifiCorp Lakeside Power Plant: 

• Block 1 of the plant began operating by September of2007. Block 2 was later permitted. 

The EPA does not know whether Block 2 has begun operating, but the State has included 

Block 2 as well as Block 1 in the proposed provisions. Please explain whether Block 2 is 

now operating and whether Block 2 has been included in the 2008 baseline emissions 

inventory, and/or in the projection inventory for the PM2.s nonattainment area. 

• The proposed provisions consist of a PM2.s emission limit of 10.8 lb/hr (including 

condensables) for each of the two Block 1 combustion turbines, a PM2.s emission limit of 

14lb/hr (including condensables) for each ofthe two Block 2 combustion turbines, a 

VOC emission limit of2.8 ppmdv at each of the Block 2 combustion turbines, and a NOx 

emission limit of two ppmdv at each of the Block 1 and 2 turbines. These proposed 

limits are the same as in the current NSR permit, dated February 2012, for the overall 

facility. The limits reflect PSD BACT and major NAA LAER from the initial NSR 

permits (dated Jan. 2005 for Block 1 and 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 provision related to the test method for 

VOCs- "or other testing methods approved by the Director"- and the lack of 

recordkeeping and reporting requirements. 

24. Payson City Power: 

• The proposed provisions are the same as in the 2005 PM1 0 SIP submittal, with respect to 

short-term emission limits and associated enforceability provisions. The only emission 

limit in the proposed provisions is a NOx limit of 1.54 tons per day, from the operation of 

all engines combined. 

• The current NSR permit, dated September of 1996, contains performance-based NOx 

emission limits, in grams per kW-hr, for each of four 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 not be included as part of 

RACT. 

• The proposed provisions do not specify the stack test method for NOx, nor any 

recordkeeping or reporting requirements for the daily mass emission limit for NOx. 

25. Provo City Power: 

• The proposed provisions are the same as in the 2005 PM10 SIP submittal, with respect to 

short-term emission limits and associated enforceability provisions. The only emission 

limit in the proposed provisions is a NOx limit of2.45 tons per day, from the operation of 

all engines and boilers combined. 

19 
• The current NSR permit, dated December of 2004, contains performance-based NOx 

emission limits, in gramslkW-hr and ppmdv, for each ofthe boilers and engines. The 

NSR limits are 1.46 gramslkW-hr and 155 ppmdv at each of two boilers, and 10.4 

grams/kW-hr and 1,660 ppmdv at each of four engines. Please explain why these 

emission limits, covering the main emitting units at the facility, should not be included as 

part ofRACT. 

• The proposed provisions do not specify the stack test method for NOx, nor any 

recordkeeping or reporting requirements for the daily mass emission limit for NOx. 

26. Springville City Corporation: 

• The proposed provisions are the same as in the 2005 PM10 SIP submittal, with respect to 

short-term emission limits and associated enforceability provisions. The only emission 

limit in the proposed provisions is a NOx limit of 1.68 tons per day, from the operation of 

all engines combined. 

• The current NSR permit, dated December of 2003, contains performance-based NOx 

emission limits, in lb/hr and gramslkW-hr for each of seven 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 of the three General Motors EMD engines. Please explain why 

these emission limits, covering the main emitting units at the facility, should not be 

included as part of RACT. 

• The proposed provisions lack sufficient recordkeeping and reporting requirements. 

20 
ATTACHMENT 4 

EPA Region 8 Comments on Chapter 5: "Utah State Implementation Plan Control 

Measures for Area and Point Sources, Fine Particulate Matter, PM2.5 SIP for the Salt 

Lake, Utah, and Logan, UT -ID Nonattainment Area 

1. Page 41, section 5.8: Given that 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 

our teleconference 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 U AA after it is 

submitted. 

2. Chapter 5: Note that EPA is commenting on the 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 what modeling 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 of the 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. From the 

description of the modeling, it is not clear ifbanked emissions were included in the modeling. 

The description of the emissions scenarios should specifically identify by species, location and 

layer any banked emissions. 

5. The modeled attainment test needs to consider all monitored baseline 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 on the MATS Technical Support Document 

1. We note that the model attainment demonstration does not show attainment of the 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's plans for augmenting the 

control strategy and re-running the model? Will this occur before Utah finalizes the SIP and 

submits it to us? 

2. High wind dust event data impacts the baseline design value for several sites, and EPA may 

not be able to concur on this flagged data in the near future. Therefore, the non-concurred 

monitor concentrations should be included in the attainment demonstration. EPA's guidance 

document "Update to the 24 Hour PM2.5 NAAQS Modeled Attainment Test" dated June 28t\ 

2011 addresses seasonal aspects of the model attainment demonstration that should be used to 

evaluate the projected future design value given exceedances in other seasons. 

1 
3. The "2008 Observed" column of tables 1, 2 and 3 of Section 4.'d should be the baseline design 

values of table 3.2 of the Salt Lake City SIP narrative; several ofthe entries in section 4.d do not 

match the values in table 3.2; EPA believes the table 3.2 values are correct, and the section 4.d 

values are incorrect. 

4. Page 1 last paragraph and page 2 first paragraph: It is unclear exactly what datasets DAQ are 

using. Please include a table where DAQ lists datasets that being 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) If only the one 

episode Dec 13 2009- Jan 20 2010 was used for CMAQ modeling, why were the other two 

periods that had acceptable model performance not used? The modeling protocol listed four 

episodes that would be evaluated and only one was removed because of poor model 

performance; if only one of the 4 episodes in the modeling protocol was used for the RRF 

development, the reasons the two additional episodes were not used for RRF development needs 

to be explained in the TSD. (3) For the FRM data, were there any days outside of the 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 calculation is 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% of modeled PM2.5 days (is this regardless of the 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 if MATS necessarily uses the same days 

in the base and future year. 

7. Also, please list the range of the 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 of the STN data used for BDV speciation from the cold seasons? (2) 

The top 10% of STN 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 Evaluation TSD 

1. Table 5.3 of the Salt Lake City SIP narrative shows an "attainment inventory" 2019 

concentration for the Salt Lake City Hawthorne monitor of 34.8 ug/m3, which appears to attain 

2 
the NAAQS. This "attainment inventory" concentration is not explained in the SIP Narrative, 

and is not addressed at all in the TSD. 

2. Table 5.3 of the Provo SIP Narrative shows an "attainment inventory" 2019 concentration for 

the Salt Lake City Hawthorne monitor of 35.2 ug/m3, which appears to attain the NAAQS. This 

"attainment inventory" concentration is not explained in the SIP Narrative, and is not addressed 

at all in the TSD. 

3. A detailed description of the baseline and control basket emissions scenarios is needed for 

each non-attainment area. For example, a description of emissions by source category, species, 

and county for each of the baseline and control basket scenarios is needed to show how 

emissions have changed over time. For the attainment inventories, a description is needed of the 

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. Snow cover and albedo are important areas of uncertainty both for the current modeling 

and future modeling efforts. For the current modeling, we recommend including a more specific 

description of conditions during winter PM2.5 episodes, e.g.: Surface albedo can range from 0.05 

for ground with no snow cover to 0.9 for conditions with complete snow coverage. An average 

albedo value of 0.55 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 of evidence 

analysis a comparison of relative response factors with and without vertical advection. This will 

help in determining how much of an effect the use of vertical advection has on the model 

attainment demonstration. 

6. Page 7: Ammonia Inventory Adjustments. We recommend adding some information 

describing the effect of the added ammonia on the model NH3 concentration and how this 

compared with the available NH3 measurements. 

7. Page 8 section 1.2, second paragraph (and all other areas where model performance is 

discussed): 

The main purpose of this 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 other performance analyses DAQ 

might perform as part of a more general model performance analyses. Plotting the performance 

for all of the above is not as important as providing the tabulated performance statistics. Perhaps 

DAQ could provide plots for a representative subset of the data as well as the tabulated statistics 

for all. Specifically, in terms of monitors (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. 

For PM2.5 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 cut point that gives DAQ enough 

3 
data for meaningful statistics while still being representative of conditions that lead to elevated 

PM2.5. 

For episodes (item (3) in comment #7), it is currently not clear in this document which episodes 

will be used for the attainment demonstration. There were 4 episodes discussed in the modeling 

protocol, but in the TSD the focus is mainly on the 4th (which has many episodes within it). One 

of the episodes was removed due to poor model performance, but what of the other two 

episodes? Will they be part of the attainment demonstration? For chemical 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 indicator ratios. 

8. Page 13, Figure 1.8 and similar figures: It would be helpful to add the comparable 24 hour 

modeled value to see the comparison better. 

9. Page 19, first paragraph: 'Table 1.3' in text should be 'Table 1.2'. 

10. Page 28: For the secondary PM2.5 Precursor Performance we recommend including in an 

Appendix the ozone, CO, NO and N02 hourly comparison of model and data for all monitors (as 

was shown in Figures 1.33- 1.35 for the Hawthorne site). It would be useful to also include a 

set of plots comparing monitored NOx=NO+N02 to modeled NOx=NO+N02 and to modeled 

total NOy. Because the NOx measurement from the chemiluminescent method detects some 

fraction of other NOy species, such as PAN, HN03 and organic nitrates, the measured NOx 

should be bounded by the modeled NOx 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 phenomenon that is not understood and thereby by replicated therefore not 

well represented in the meteorological modeling." 

12. Page 28 Section 1.2.2, second paragraph: The 'better model performance' for these species 

is not apparent from the time series plots. We recommend providing the performance statistics. 

Also, the colors in the plots make it hard to distinguish the different values. 

13. Page 29 section 1.2.3, last paragraph (and first on next 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: It is unclear ifthese scenarios will be used as part ofthe modeling for 

the attainment demo. If they will, then it doesn't make sense to separate them out from the 

general discussion of model performance. If they will not be used for the attainment demo, then 

DAQ could just provide the performance statistics (as per first main comment above) rather than 

plots. 

4 
16. Page 32: "The sensitivities v1ill be were performed on the 2008 inventory and the 2019 

inventory that has incorporated emission reduction 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 of direct PM2.5 and S02. 

This demonstration includes an evaluation of technically and economically feasible 

control measures to demonstrate expeditious attainment of the PM2.5 NAAQS. 

However, Page 34 includes this text: 

Much of emission control strategy planning by UDAQ focused on the results of the 

sensitivities to the 2008 Inventory. That is, strategies that dealt with the benefit ofVOC 

reductions and avoided the dis-benefit ofNOx controls. 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 

NOx reductions. 

We recognize that the ratio ofVOC and NOx emissions will change over time, 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 of the model PM2.5 sensitivity to VOC 

and NOx, it will be challenging to identify the optimal mix of VOC 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 or VOC 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 data to 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 of Evidence discussion of trends in Cache County: the EPA modeling guidance 

discusses that a weight of evidence analysis is often necessary to augment the modeled 

prediction of attainment, given the uncertain nature of input generation and chemistry for the 

very complex scientific issue of secondary pollutant 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 show that attainment will be reached in the 

future with some margin of safety (e.g., estimated concentrations below 82 ppb for 

ozone, 14.5 ug/m3 for annual PM2.5, and 62 ug/m3 for 24-hour PM2.5) will need more 

limited supporting material. For other attainment cases, in which the projected future 

5 
design value is closer to the NAAQS, more rigorous supporting analyses should be 

completed." 

On page 99 of the guidance: 

"There are three basic types of analyses that are recommended to supplement the primary 

modeling analysis. They are: 

1) Additional modeling 

2) Analyses of trends in ambient air quality and emissions 

3) Observational models and diagnostic analyses" 

For the Cache Valley, analysis of trends in ambient air quality may present some issues. The 

figure below shows the long term data trends for 98th percentile 24-hour PM2.5, the trend in 3 

year PM2.5 design value, and the trend in 5 year Baseline Design Value (BDV) used for 

modeled base year concentration: 

0 

1998 

Logan historical 98th percentile, Design Value 

and Baseline DV PM2.5 

2000 2002 2004 2006 2008 2010 2012 

-98th 

-ov 

-BDV 

Examination of the trend, particularly with respect to the five year period from 2006 through 

2010 used to establish the BDV for modeling, shows that the 2006 through 2010 period includes 

two of the lowest 98th percentile values in the 11 year data set, and that those low values result in 

the 2008 centered BDV being the lowest in the 11 year period. The 98th percentile values in the 

period 2008 through 2011 all lie above the 2008 centered BDV, indicating PM2.5 since 2008 has 

6 
generally been greater than that observed on average in the 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, contrary to what is indicated by the 

model. Further evaluation and discussion of this trend in a weight of evidence discussion could 

be used to counter this potential vulnerability in the modeled attainment. For example, Utah 

could discuss the ability of the SIP controls to meet attainment even with higher 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). 

7 
ATTACHMENT 5 

EPA Region 8 Comments on RACT Discussion in SIP Narratives DAQ-072-12 and DAQ074-12 and RACT Technical Support Document 

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 on the 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 Monica Morales of EPA 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 in Utah County). It appears that the RACT analyses for the 33 sources 

were prepared primarily by the sources, not by the State. Six sources were apparently 

dropped from the list of 34 sources that appears in the 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 in the RACT TSD do not have RACT analyses (Interstate Brick 

and Silver Eagle Refining). Instead, the TSD indicates that synthetic minor status has 

been established for Interstate Brick, and will shortly be established for Silver Eagle 

Refining, to relieve them of the requirement for source-specific RACT. 

~ For nearly all ofthe RACT analyses, either no sources of information on RACT are cited, 

or else the only source of information cited is EPA's RACT/BACT/LAER Clearinghouse 

(RBLC). This is not sufficient to support the RACT analyses (see September 13, 2011 

email from Monica Morales). Also, for many of the analyses, there is no indication 

whether more 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 indication how the costs were calculated. For some sources, the 

chosen RACT options are not reflected in the proposed source-specific provisions in 

DAQ-075-12. 

~ Please see attached reports by EC/R for additional concerns and recommendations on 

how to improve the RACT analyses. 

1. ATK Launch Systems: ATK reviewed RACT options for PM, S02, NOx and VOC from 

their boilers, engines, mobile sources, and fugitive emissions. A TK does not propose any new 

1 
controls. ATK's RACT analysis says they already use ultra low sulfur fuel oil in their boilers, 

engines and mobile sources. 

With regard to open burning/testing of waste propellants, energetics and pyrotechnics, ATK says 

they are currently in the process of conducting an open burning risk assessment under the 

direction ofthe State's Division of Solid and Hazardous Waste (DSHW), and that open burning 

limits will be determined and imposed by a DSHW permit when the risk assessment process is 

completed. 

A TK' s proposal to only address RACT for open burning after a risk assessment process is 

completed is not consistent with what the State has proposed as source-specific provisions for 

ATKin the document DAQE-075-12. For the period from November 1 to February 28 annually, 

the State is proposing to limit open burning to 50% of the daily limit in the DSHW permit, when 

PM2_5 levels exceed 35 ug/m3 at the nearest real-time monitoring station, and to limit testing of 

propellant, energetics, pyrotechnics, flares and other reactive compounds to 2,400 lbs of 

propellant per item during these periods, as well as prohibit testing of rocket motors less than 1 

million lbs of propellant per motor during these periods. (This last provision is confusing. What 

about rocket motors larger than 1 million lbs of propellant per motor?) 

As we noted in our comments on draft Sections IX.H.12 and IX.H.13, these proposed provisions 

are inconsistent with the CAA and EPA's regulations on dispersion techniques and intermittent 

control systems ( 40 CFR 51.118 and 51.119) and are not creditable for purposes 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: 

• How the State's proposed source-specific provisions constitute RACT. The SIP or TSD 

needs to include an analysis of technical and economic feasibility. 

• Whether the State considered other alternatives, such as transporting waste outside of the 

NAA before burning it, and/or minimizing the amount of waste to be burned. 

• The pollutants addressed by the State's proposal. 

• Whether the State's proposal represents a reduction from 2008 baseline emissions, and if 

so, how the reduction was calculated. What emission rate was assumed for the projection 

years out to 2019? 

• Whether the State's proposal could change after the risk assessment mentioned by ATK 

is completed and whether it is appropriate for the RACT determination to await/depend 

on that risk assessment. 

2. Big West/Flying J Refinery: We have asked EC/R to review this 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) Unit by fall of2015. BWO expects to achieve about 42 tons 

per year of reduction in PM emissions by year 2016. How was this calculated? A table included 

in BWO's analysis indicates only a 29 ton per year expected reduction in PM2.5, to be achieved 

between 2017 and 2019. Please explain the discrepancy in timing and amount. The State must 

2 

... 
also explain whether any other RACT options were considered and how it was determined that 

the proposed RACT is the lowest achievable based on technical and economic feasiblility. 

For S02, BWO is proposing to start using DeSOx additives with their catalyst at the MSCC Unit, 

to achieve better than 90 percent so2 control and emissions below 25 ppm so2 in catalyst 

regenerator flue gas, resulting in a reduction of 252 tons per year of S02 emissions. BWO is also 

proposing to install additional fuel-gas treating technology (caustic scrubbing) that can be used 

during planned or unplanned outages of the Amine or Sulfur Recovery Units. BWO indicates 

this technology could reduce S02 emissions by an average of 50 tons per year. The total 

potential reductions are therefore about 302 tons per year. How was this calculated? A table 

included in BWO's analysis indicates only a 150 ton per year expected reduction in S02, to be 

achieved between 2017 and 2019. Please explain this discrepancy. Please also explain why an 

earlier timeline would be unreasonable. The State must also explain whether any other RACT 

options were considered and how it was determined that the proposed RACT is the best 

achievable based on technical and economic feasibility. 

For NOx, BWO is proposing to retrofit three existing plant boilers with Ultra Low-NOx Burners, 

to achieve a NOx emission rate of 0.035 lb/MMBtu or less. This is expected by BWO to achieve 

a NOx reduction of about 30 tons per year before the end of2013. How was this calculated? A 

table included in BWO's analysis indicates an expected reduction of 52 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. 

For VOC, BWO is proposing to adopt more stringent leak definitions in its LDAR monitoring 

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 of leaking pump seal would drop from 10,000 ppm to 2,000 ppm. This is expected by 

BWO to result in as much as a 100 ton per year VOC emission reduction for valves and 30 tons 

per year reduction for pumps. The total potential reductions are therefore about 130 tons per 

year. How was this calculated? A table included in BWO's analysis indicates an expected 

reduction of 152 tons per year, 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 of these commitments for emission reductions are reflected in the source-specific 

provisions proposed for BWO in the document DAQE-075-12. There is no explanation why not. 

The provisions in that document appear to be the same as in the 2005 PM10 SIP submittal, with 

respect to daily emission limits and associated enforceability provisions. None of these 

commitments for new emission reductions are reflected in the General Requirements for 

refineries either. Please explain why these are not in the source-specific provisions. 

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 

3 
are currently limited in the NSR permit to 15 ppm and 7.5lb/hr ofNOx per turbine. 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, but presents no RACT discussion for it. The 

current NSR permit has no emission limits for that engine. Please provide a RACT discussion 

for that engine, or else provide a justification for no RACT discussion. Also, the current NSR 

permit lists five dual-fuel IC engines #2-6, to be replaced at some point by the two new turbines, 

but the RACT analysis only mentions one IC engine. Please explain this discrepancy. Have 

these engines been replaced? 

The RACT analysis does not identify any RACT option other than current controls, nor does it 

present any explanation why current controls should be considered 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. 

Also, since the current NSR and 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 combustion turbines. A table included in the RACT analysis indicates that starting in 2014, 

PM2.s emissions will triple, S02 emissions 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 with the new turbines, the facility will operate on a more 

aggressive production schedule than previously. Please explain whether these 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 enforceability provisions. 

EPA also comments that it's not clear why a fuel restriction to natural gas from the current NSR 

permit has not been included in the proposed provisions. Also, engine #8 is not addressed in the 

proposed provisions. The current NSR permit limits use of engine #8 to 1,600 hours per year. 

4. Brigham Young University: Please see attached report by EC/R for discussion of this 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 bum coal during winter months (November 1 through February 28), 

BYU did a RACT review only for the gas-fired HWGs. BYU claims that use of natural gas 

constitutes RACT for PM10, PM2.s, S02 and VOC. Current emissions of each of those pollutants 

at BYU are below 1 ton for winter months. 

For NOx, BYU evaluated four RACT options at HWG1 and four options at HWG4 and 6. BYU 

calculated the cost-effectiveness at HWG 1 to 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 spud tips and add 18% FGR). Expected NOx reduction for the 

cheapest option was about 6 tons during winter months (about a 45% reduction from current 

winter emissions of 13.87 tons). 

4 
BYU 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 per HWG during winter months (about a 65% reduction from current 

winter emissions of 16.86 tons at each HWG). 

BYU concluded that the cost effectiveness of all NOx control options was too high to justify as 

RACT. EPA has concerns about this conclusion and whether it is justified. 

BYU also evaluated VOC RACT for their landfill, which is subject to NSPS (40 CFR 40 Part 60 

Subpart WWW), but is not required under Subpart WWW to install a non-methane organic 

carbon collection and control system. BYU states that it installed a control system of its own 

accord, with an estimated VOC control efficiency of about 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 better than 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 of water and dust suppressants such as magnesium chloride 

as needed for dust suppression, minimizing the extent of disturbed ground, establishing 

vegetation on disturbed ground as soon as practical, sweeping of paved 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 current practice of purchasing equipment 

which is either Tier 4 Transitional or Tier 4 compliant. Again, 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. 

The State has not proposed any source-specific provisions to make BYU's current practices, 

emission limits and fuel consumption limits enforceable. The current NSR permit 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 of 405 MMSCF per rolling 

12-month period, 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 of operation in a 

12-month period). 

5. Central Valley Water Reclamation: The RACT analysis indicates that the digesters were 

redesigned in 2011, resulting in a VOC emission reduction of 85%. There is no indication how 

much reduction this was in tons per year. The RACT analysis indicates that the composting 

5 
process was also redesigned in 2011, resulting in a VOC emission reduction of about 95%, or 

about 36.4 tons per year of reduction. 

Since VOC emissions from composting were not accounted for in the 2008 emission inventory, 

the annual VOC emissions are estimated to drop by only about 18 tons from 2008 to 2014. No 

change in emissions of any other pollutants is projected after the 2008 baseline year. 

The facility's proposal for RACT basically consists only of a work practice requirement to 

"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 proposed requirement is apparently new, not carried over from 

any existing rules or NSR permits. No explanation has been provided how this proposed 

requirement might further reduce emissions from 2008 baseline, or how this requirement might 

relate to emissions at all. Also, the proposed requirement 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 examined the source's RACT analysis and 

confirm whether 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. 

None of the provisions from the current NSR permit, nor from the 2005 PM10 SIP submittal, are 

proposed as RACT. The current NSR permit 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-month NOx 

limits for the engines and for the backup generators. Please explain why such limits are not 

evaluated in the RACT analysis. 

6. CER Generation: This facility consists of five combustion turbines. The RACT analysis 

indicates that the BACTILAER emission limits for NOx in the original2002 construction permit 

should satisfy RACT. The limits cited are: 5 ppmdv for each turbine, on a 30-day rolling 

average, under steady state operation (not including startup and shutdown); 100 ppmdv not to be 

exceeded at any time; and 37 lblhr for the total of all five turbines, on a 30-day rolling average 

under steady state operation (not including startup and shutdown). No emission reduction from 

2008 baseline is projected. 

The only emission limit proposed by the State is a NOx limit of 0.44 tons per day, for the total of 

all five turbines. This is numerically equivalent to the 37 lblhr in the current NSR permit. 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. As part of this effort, 

the State should analyze whether there have been advancements in control measures for turbines 

since the construction permit was issued. Please explain why 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/R to review Chemical 

Lime for RACT. In the meantime, we have the following preliminary comments: After a 

6 
screening ofRACT possibilities throughout the facility, the RACT analysis focuses on possible 

upgrade of emission controls at the rotary kiln for PM10, PM2.5, NOx, VOC and S02, and possible 

upgrade of fugitive 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 combustion practices. A search of the 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 of existing electroscrubber control device (75% control efficiency) 

NOx- existing NOx limit in permit of 75.00 lb/hr + good combustion practices 

VOC- good combustion practices 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 of water 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/dscf at the Hydrator 

Baghouse, and 24.78 lb/hr and 0.19 gr/dscf at the Kiln Electroscrubber. The proposed emission 

limits for NOx are 75.00 lb/hr and 650 ppm at the Kiln Electroscrubber. These limits are the 

same as in the current NSR permit, 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 

how it 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 of this 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/R to review GSLM for RACT. In the 

meantime, we have the following preliminary comments: The format of this RACT analysis 

consists entirely of tables, and the RACT review for each emitting unit consists of only a couple 

of sentences. For most of the emitting units, the key sentence is that "There are no "vendor 

guaranteed" controls options applicable to this process which could exceed the measured 

emission rate 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 on technical and 

economic feasibility. 

11. Hill Air Force Base- Main Base: The RACT analysis says only that emissions shall not 

exceed applicable requirements in 40 CFR 60, 62 and 63 or any effective applicable state 

requirements in R307-401 (the state's NSR permitting rule). There is no analysis of the technical 

or economic feasibility of any potential emission reductions. This is insufficient for a RACT 

7 
analysis. All potential RACT options should be identified and an explanation presented on how 

it was determined that the proposed RACT achieves the lowest emissions based on technical and 

economic feasibility. 

12. Holly Refinery: We have asked EC/R to review this RACT analysis. 

13. Kennecott Power Plant/Lab/Tailings Impoundment: Please see attached report by EC/R for 

discussion of this RACT analysis. 

14. Kennecott Smelter and Refinery: Please see attached report by EC/R for discussion of this 

RACT analysis. 

15. Pacific States Cast Iron Pipe: We have asked EC/R to review this 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 shot blast, but the only source of RACT information mentioned is the RBLC, and 

no cost information is presented for any options. The State must explain whether it has 

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 on technical 

and economic feasibility. 

16. Tesoro SLC Refinery: Please see attached report by EC/R for discussion ofthis RACT 

analysis. 

17. Proctor and Gamble Paper Manufacturing Plant: We have asked EC/R to review Proctor 

and Gamble for RACT. In the meantime, we have the following preliminary comments: In 

brief, the RACT analysis asserts that the BACT evaluations in the 2007 application for an NSR 

permit for initial plant construction (issued February 20, 2008) should be adequate to serve as a 

RACT analysis (with the possible exception ofPMz.5). The only sources of information cited in 

the RACT analysis are the prior BACT analysis and the RBLC. While there is some discussion 

of control 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 that it has checked the 

RBLC and other appropriate sources of information on control technologies. Ifthe State then 

concludes that the 2008 BACT determination constitutes RACT, the State needs to certify in the 

SIP or TSD that there are no better controls than those adopted by P&G that would be 

technically and economically feasible, and that the BACT analysis can be relied upon as the 

RACT analysis, for those pollutants covered in the BACT analysis. 

We also note that the RACT analysis only proposes an emission limit of 6.65 lblhr for PM10, at 

each of the two paper machines, and a commitment to propose a PMz.s emission limit by January 

1, 2015. Please explain why an earlier timeline would be unreasonable. Also, we note that the 

proposal does not include NOx emission limits from the current NSR permit at the four boilers 

and two paper machines, although the RACT analysis mentions that such limits exist in the NSR 

permit. Please explain why no NOx emission limits are proposed as part ofRACT. 

8 
Also, we note that the NSR permit lists the potential to emit for VOC at 213 tons per year. A 

RACT review for VOC would seem warranted. Please provide such a RACT analysis or explain 

why the RACT analysis does not address VOC. 

18. University ofUtah: We have asked EC/R to 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 of an "aggressive energy conservation program" in 

existing buildings, reducing the heating capacity at Building 303 by replacing three 105 

MMBtulhr boilers with six 40 MMBtulhr boilers, and an undefined "study" of three 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 whether the costs presented are capital costs or annualized costs, 

nor how the costs were calculated, nor what sources of information were used to identify RACT 

options for any pollutant. For each 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 it has 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 on technical and economic feasibility. 

19. The following sources are still under review: Great Salt Lake Minerals; Big West/Flying J 

Refinery; Hexcel; Holly refinery, Kennecott Bingham Canyon Mine and Copperton 

Concentrator; Murray City Power; Nucor Steel; Olympia Sales Company; Pacific States Cast 

Iron Pipe; Pacificorp Gadsby Power Plant; Pacificorp Lakeside Power Plant; Pacificorp EnergyLittle Mountain Power Plant; Payson City Power; Pepperidge Farm; Proctor & Gamble Paper 

Manufacturing Plant; Provo City Power; University of Utah; Utility Trailer; Vulcraft; Wasatch 

Integrated Waste Management; Springville City Corporation. We are awaiting RACT reports 

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. 

9 
Brigham Young University Central Heating Plant 

Evaluation ofRACT Analysis 

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 Draft Technical 

Support Document (TSD) for the Utah PM2.5 State Implementation Plan (SIP). 

SUMMARY OF RACT ANALYSIS 

Facility description 

BYU operates six (6) hot water generators (HWGs)/boilers at their central heating plant. HWGs 1, 4, and 

6 bum natural gas with fuel oil backup and HWGs 2, 3 and 5 bum coal except during the winter months 

(November 1 ending February 28/29), when these units are permitted to bum natural gas or fuel oil only. 

BYU does not provide any information or analysis for HWGs 2, 3, and 5, even though these units appear 

to operate and bum natural gas during the winter (similar to HWGs 1, 4 and 6). Table 1 provides the 

annual emissions in tons from this facility based on the Utah 2008 emission inventor!. 

Table 1. Brigham Young University 2008 Annual Emissions 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 boiler rated 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 boiler rated at 192 MMBTU/hr (16.86 tons NOx). 

Emission sources included in EC/R's evaluation 

This evaluation of the BYU RACT analysis will be restricted to 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's evaluation 

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 that these units are in operation 

during the winter and bum natural gas, which generates emissions ofNOx, a PM2.5 precursor. 

SUPPLEMENTAL DATA SOURCES 

1 Control Strategies for Brigham Young University. Undated; contained in the Draft TSD for PM25 Attainment 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 

10 
Table 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. 

Table 2. NOx Control Technologies Identified for Natural Gas-fired Boilers 

Control Cost 

Control Technology 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 

Low NOx 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 

Selective Non-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 SNCR in their analysis of potential RACT options for reduction of 

NOx boiler emissions. 

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 determined to be cost-effective. 

Adequacy of data 

A full RACT analysis for this source is not provided. The following are examples of areas where the 

RACT analysis in the TSD does not provide adequate data: 

• All costs are unsupported; 

• The control efficiencies and emission reductions (in tons per year) of potential control options are 

not provided; 

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 of CoST 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 of potential control measures is not sufficient because Tesoro did not evaluate all 

appropriate RACT options (e.g., OT/WI, SCR, or SNCR for 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/ton NOx; 

• 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/ton NOx; 

• LNB at $6,387/ton NOx; 

• LNB and FGR at $6,124/ton NOx; 

• ULNB and FGR at $7,232/ton NOx 

It appears that BYU only evaluated the cost effectiveness of controls with respect to wintertime 

emissions. However, as described in EPA's Apri125, 2007 PM2.5 implementation rule (72 FR 20594), 

"the cost effectiveness of a technology is its annualized cost($/ year) divided by the emissions reduced 

(i.e., tons/year) which yields a cost per amount of emission reduction ($/ton)". Therefore, BYU's costeffectiveness calculations should include the year-round emissions, including non-wintertime emissions 

(if any). All cost-effectiveness values estimated by BYU are high as compared with the EPA costeffectiveness values in Table 2, which could be a result of the BYU calculations potentially including 

wintertime emissions only. 

Recommendations 

• Request the State to provide a full RACT analysis including supporting documentation (see 

attached RACT Analysis list). 

• Recommend further evaluation of the potential emission reductions and costs to install additional 

NOx controls on HWG 1, 4 and 6; including a review of the detailed cost analyses when this 

information is provided by BYU. 

Recommend an evaluation of whether HWG 2, 3, and 5 should be included in a RACT analysis. 

12 
Chevron Products Company Salt Lake Refinery 

Evaluation ofRACT Analysis 

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 RACT analysis prepared by Chevron6 on May 16, 2012, which 

was summarized by the state in the Draft TSD. 

EVALUATION OF RACT ANALYSIS 

Facility description 

The Chevron refinery processes crude oil and hydrocarbon feedstocks into transportation fuels, petroleum 

coke, sulfur, and various byproducts. Table 1 provides 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. Chevron Refinery 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 of the installation of numerous control technologies, including: a tail gas unit for the original 

sulfur recovery unit (SRU), a redundant SRU with tail gas unit, upgrades to the FCC electrostatic 

precipitator (ESP), upgraded cooling tower controls, and installation of vapor recovery 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 per year (tpy)) and the PM2.5 emissions 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 1 and 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 of less than 0.01 percent; 

5 Control Strategies for Chevron Products Company. Undated; contained in the Draft TSD for PM2.5 Attainment 

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 with LNB; 

• Refinery fuel gas-fired furnace rated at 115.1 MMBTU!hr equipped with LNB; 

• Fluid Catalytic Cracking Unit (FCCU) Regenerator, using an electrostatic precipitator (ESP), 

NOx and sulfur dioxide (S02) catalyst additives, and feedstock hydrotreatment to control 

emissions; 

• Three (3) flares; 

• Fugitive emissions; 

• Three (3) rich burn reformer compressor engines rated at 16 MMBTU/hr each; 

• Two (2) sulfur plants consisting of a sulfur recovery unit (SRU), a tail gas treatment unit (TGTU), 

and a tail gas incinerator (TGI); 

• Storage tanks; 

• Wastewater treatment plant; 

• Reformer catalyst regenerator. 

Emission sources included in EC/R's evaluation 

This evaluation of the Chevron RACT analysis will be restricted to the following emission units and 

pollutants: 

• Boiler Units 1, 2 (potential to emit (PTE)= 138.1 tpy NOx) and Unit 4 (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 sources that were evaluated in the Chevron RACT analysis have been excluded from 

this analysis for various reasons. 

• Boiler Units 5 and 6, the furnaces, the flares, the sulfur plants, and the cooling towers will not be 

evaluated because these sources have low emissions compared to the sources identified above, are 

already controlled to some extent, and/or have overall less potential for significant reductions in 

emissions. 

• Fugitive VOC emissions from equipment leaks (PTE= 690.8 tpy) will not be evaluated because 

there is insufficient data on the types of equipment components and the current LDAR plan 

operated by the refinery to suggest more stringent control options and work practices. In 

addition, Chevron currently complies with valve and pump leak definitions of 500 ppm and 2,000 

ppm, respectively, which are relatively strict compared to current limitations at other refineries in 

Utah. 

• VOC emissions from the wastewater treatment plant (PTE= 139.3 tpy) and storage tanks (PTE= 

272.7 tpy) will not be evaluated because there is inadequate data on the types of tanks/equipment 

operated by the facility and the existing controls. In addition, VOC emissions from storage tanks 

and wastewater treatment processes are already controlled to some extent by regenerative thermal 

oxidizers and are subject to various NSPS and NESHAP requirements. 

SUPPLEMENTAL DATA SOURCES 

Boiler Units 1, 2 and 4 

Table 2 provides NOx control technologies identified for refinery fuel gas-fired boilers from EPA sources. 

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

Control Cost 

Control Technology Efficiency Effectiveness Reference 

($/ton NOx) 

Oxygen Trim (OT) and 65 680 CoST8 

Water Injection (WI) 

Low NOx burners (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 OF A 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 

• It is assumed that SCR and SNCR controls are applied with a combustiOn control (e.g., OF A). 

Chevron evaluated Ultra Low NOx burners (ULNB) and SCR in their RACT analysis, but did not 

evaluate any other technologies 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 

Control Technology 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 consent decrees 

established with most US refineries through EPA's refinery initiative. The technologies required by these 

consent decrees, as summarized in the Emission Effects of Refinery Cases and Settlements document 9

; 

include: 

• SCR to 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 of CoST 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. 9

Including the Emission Effects of Refmery Cases and Settlements in Projections for the EPA's CAAA Section 812 

Analysis, E.H. Pechan & Associates. Available at: http://www.epa.gov/ttnchie 1/conference/ei 15/session4/wilson.pdf 

15 
• Scrubber-based NOx emission reduction technology to achieve 20 ppmvd; 

• Low NOx CO combustion promoters 

• Catalyst additives 

• Lo TOx system 

It should be noted that in the TSD RACT analysis for Tesoro Refinery10, LNB is rejected as a potential 

control option because regenerator temperatures are generally not high enough for significant thermal 

NOx formation. LNB stages the combustion process to reduce thermal NOx, which occurs in the high 

temperature flame zone near the burners. The Environment Agency (EA), which is a British nondepartmental public body, published a document on oil and gas processes

11 that supports Tesoro's 

conclusion that thermal 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 of FCC regenerators that Chevron did not evaluate is 

selective non-catalytic reduction (SNCR). In the RACT analysis for the Tesoro refinery, SNCR was 

evaluated for their FCC regenerator and considered this technology to be technically feasible. The EA 

document also supports the use of SNCR, and cites emission reductions of 50-60%. 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 highest NOx 

reduction levels of all options identified, equivalent to SCR6

. LoTOx was 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 NOx to soluble oxidized 

compounds 12• LoTOx requires installation of a wet gas scrubber downstream. 

The following technologies for reduction of S02 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 of PM emissions from FCCU identified in the EA document include: 

• ESP; 

• Wet scrubbers; 

• Cyclones. 

The EA document also identifies bag filters (fabric filters), but states that this technology is not favored 

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 larger particles and have limited 

effectiveness on particle sizes of PM10 and smaller. 

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. 

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 Grant Number ICA T 99-2. California Air Resources Board (CARB). 

Webpage updated November 18,2005. Available at: http://www.arb.ca.gov/research/icat/projects/boc.htm 

16 
Rich 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. Chevron evaluated the use ofNSCR for additional NOx reduction. It is assumed that the 

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 Cost Effectiveness 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 of the 

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. 

New RACT identified in the Chevron analysis 

In the RACT analysis, Chevron states that they will install non-selective catalytic reduction (NSCR) on 

each of the compressor engines "within one year of the date of entry of the pending draft agreement with 

the EPA". 

Adequacy of data 

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 of areas where the RACT analysis in the TSD does 

not provide adequate data: 

• Costs of controls and cost effectiveness values are unsupported; 

• The size and emissions of boiler Units 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 of the analysis appears to be out of place or missing in the "Results of 

Analysis" section; 

• The fuel type of the compressor engines and emissions from the engines are not provided; 

• The review of potential control measures is not sufficient because Chevron did not evaluate all 

appropriate RACT options (e.g., OT/WI and SNCR for boiler Units 1, 2 and 4; LoTOx and 

SNCR for FCCU; and IR, LEC and PSC for the compressor engines). 

Cost effectiveness 

Boiler Units 1, 2 and 4 

Chevron identified the following controls and cost-effectiveness values for boiler Units 1, 2 and 4: 

• ULNB for Unit 1 and 2 at $2,831/ton NOx and ULNB for Unit 4 at $2,917/ton NOx; 

• SCR for Unit 1 and 2 at $2,608/ton NOx and SCR for Unit 4 at 2,695/ton NOx. 

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 SCR for all units as technically feasible; 

however, these technologies are rejected on the basis that they are economically unreasonable (i.e., not 

cost effective). 

In the May 16, 2012 RACT analysis provided by Chevron, Chevron asserts that PM2.5 precursors do not 

correlate directly to emissions ofPM25, and NOx and S02 emissions from Chevron Salt Lake Refinery 

sources do not significantly contribute to PM2.

5 concentrations 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 PM2.5 precursors. However, as described in EPA's April25, 2007 

PM2.5 implementation rule (72 FR 20594), "States are required to address NOx as a PM2.5 attainment plan 

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." 

Fluid catalytic cracking unit (FCCU) regenerator 

Chevron identified the following controls and cost effectiveness values for the FCCU: 

• Wet gas scrubber at $16,021/ton PM10 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 of the potential control options identified above on 

the basis that they are economically unreasonable. 

Rich burn compressor engines 

Chevron identified air to fuel ratio controls and NSCR at $876/ton NOx for each rich bum compressor 

engine. The cost effectiveness of$876/ton NOx is only slightly higher than the EPA value provided in 

Table 4 ($521 /ton NOx). Chevron stated that they would agree to 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, SCR for boiler Units 1, 2 and 4 may be RACT due to 

technical feasibility and cost effectiveness less than $2,700/ton. 

18 
• Recommend further evaluation ofthe cost to install a wet gas scrubber for control of PM and S02 

emissions from the FCCU; including a review ofthe detailed cost analysis submitted by Chevron 

(May 16, 2012) and a review ofFCCU rules adopted by state and local agencies. 

Recommend further evaluation of the 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. 

19 
Kennecott Utah Copper LLC Power Plant 

Evaluation of RACT Analysis 

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 Draft Technical Support 

Document (TSD) for the Utah PM2.5 State Implementation Plan (SIP). 

SUMMARY OF RACT ANALYSIS 

Facility description 

The KUC facility includes a tailings impoundment, power plant and laboratory. The power plant supplies 

power to KUC operations and the laboratory is used to perform tests for permitting compliance and 

operations optimization. Table 1 provides the annual emissions in tons from this facility based on the 

Utah 2008 emission inventory15 • 

Table 1. Kennecott Power Plant Annual 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 1 through 3); 

• One (1) tangential natural gas and coal-fired boiler rated 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 of the tailings embankment; controlled by a dust 

control plan. 

Emission sources included in EC/R's evaluation 

This evaluation of the 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 of dry low NOx 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 PM25 Attainment 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 10-1-20 12/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 
• Four noncontact water cooling towers, natural gas fired space heaters, and fugitive dust emissions 

from wind erosion of the tailings embankment were not evaluated because these sources have low 

emissions compared to Unit 4, 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 of Unit 4 will be restricted to NOx, which is the primary pollutant from the 

combustion of natural gas. However, any additional controls identified in this analysis for NOx reduction 

may also apply to coal-fired boilers to allow for use of the technology year-round. 

SUPPLEMENTAL DATA 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)) 

Low NOx 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 

a The 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 of Utah DEQ Approval Order Number DAQE-AN105720026-11. December 1, 2011. 17 Alternative 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 of CoST was developed in 2008. The CMDB is available 

for download at: http://www.epa.gov/ttnecasl/cost.htm. 

21 
FINDINGS 

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 per year reduction in NOx could be achieved by implementation of this 

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 of data 

A full RACT analysis for this source is not provided (e.g., insufficient data for cost calculations: the 

analysis states that costs and time of installation 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 OF A and SNCR at 53% control efficiency and $1,517 /ton; 

• LNB with OF A and SCR at 82% control efficiency and $2,087 /ton. 

Although the control efficiencies and cost-effectiveness values identified by KUC in their RACT analysis 

differ somewhat as compared with EPA values shown in Table 2, all scenarios appear to be cost effective. 

While KUC identifies SNCR and SCR as economically feasible, these post-combustion controls are 

rejected on the basis that it will take three years for design and installation, and this is "beyond the EPA 

guidance time frame of one year and therefore .... are chronologically infeasible". 

Recommendations 

• Request the State to provide a full RACT analysis including supporting documentation (see 

attached RACT Analysis list). 

• Based on the KUC RACT analysis, LNB with OF A and SCR appears to be RACT due to the 

reasonable cost effectiveness. 

Regarding KUC's point of"chronologically infeasible", request the State to determine whether these 

measures are necessary for attainment as expeditiously as practicable. The State may exclude those 

reasonable measures that, considered collectively, would not advance the attainment date by at least one 

year (PM2.5 implementation rule at 72 FR 20617). 

22 
Kennecott Smelter and Refinery 

Evaluation ofRACT Analysis 

This document evaluates the reasonably available control technology (RACT) analysis19 prepared for 

Kennecott Utah Copper (KUC) LLC Smelter and Refinery in Utah and included in the Draft Technical 

Support Document (TSD) for the Utah PM2.

5 State Implementation Plan (SIP). 

SUMMARY OF RACT ANALYSIS 

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 sent to the refinery where the copper is fused to a steel sheet to form a copper plate. The facility 

includes over 74 individual emission sources. Table 1 provides the annual emissions in tons from this 

facility based on the Utah 2008 emission inventory20• 

Table 1. Kennecott Smelter and 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. 

Refinery sources: 

• 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; 

• Noncontact water cooling towers equipped with drift eliminators with drift loss rated at 0.002 

percent; 

• Precious metals recovery scrubber. 

Smelter sources: 

• Powerhouse Holman boiler rated at 187 MMBTU/hr; 

• Main Stack: includes the matte granulator, slag granulator, acid plant, power house, furnaces, 

dryers and grinding circuits, each of these sources of emissions 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.

5 Attainment 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 I 0-1-20 12/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 of wet flux and 

concentrate and from transfer points of the conveyor; 

• Slag and matte granulators vented through a stack with a wet scrubber; 

• Feed storage building, stores wet copper 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 SoLoNOx burners; 

• Product drying, storage, packing, and reagent storage, vented through a baghouse. 

Emission sources included in EC/R's evaluation 

This evaluation of the 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 per year (tpy)): 

• Refinery and MAP combined heat and power units (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 combined total emissions) 

• Smelter fugitives (157 tpy combined total emissions) 

Emission sources excluded from EC/R's evaluation 

All emission sources at the KUC plant that were not identified as being included in EC/R's analysis above 

have been excluded from this evaluation because these sources have low emissions compared to the 

sources identified above, are already controlled to some extent, and/or have overall less potential for 

significant reductions in emissions. 

SUPPLEMENTAL DATA SOURCES 

Refine1y and MAP combined heat and power (CHP) units 

Table 2 provides NOx control technologies identified for natural gas-fired turbine cogeneration units from 

EPA sources. The KUC analysis does not identify the fuel source of the CHP units, which is assumed to 

be natural gas in this evaluation. 

24 
Table 2. NOx Control Technologies Identified for Natural 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 

SCR and water injection 95% 2,730 CoST 

KUC identifies the existing controls on each CHP unit (i.e., LNB on duct burner and SoLoN Ox on 

turbine) as RACT, and does not evaluate any of the other potential RACT options identified in Table 2. 

SoLoN Ox technology is a form of staged 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 boiler rated 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 I 00 

MMBTU/hr or larger. 

Table 3. NOx Control Technologies Identified for Natural Gas-fired Boilers 

Control Cost 

Control Technology 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 NOx Burners (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 of CoST was developed in 2008. The CMDB is available 

for download at: http://www.epa.gov/ttnecas 1/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 of Utah DEQ, Approval Order Number: 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") 

25 
Selective 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 on the boiler (i.e, LNB) as RACT, and does not evaluate any of the 

other potential RACT options identified in Table 3. The New Jersey State of the Art (SOTA) Manual for 

Boilers and Process Heaters24 identifies LNB with FGR and/or SCR as control technolgies that 

correspond to SOTA performance emission limits for natural gas fired boilers rated 75 MMBTU/hr or 

greater. 

Main stack 

In the summary of emission 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 of these emission sources, including unit characteristics (i.e., type, 

size), current controls, individual unit emissions, or potential RACT options. 

According to the summary of emission source table, the Main Stack PTE combined emissions of 1,114 

tpy is 73.7% of the total facility emissions. Based on the NSR permit emission limits for the main stack, 

summarized in Table 4, it appears that the bulk of these emissions are S02• 

Table 4. NSR Permit Limits for KUC Smelter Main 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 of processes that have been engineered/designed to 

reduce fugitives, but does not specify any specific sources of RACT emissions or potential controls for 

these emissions. Table 5 provides examples of process fugitive emission control techniques that could be 

considered to reduce emissions from copper smelting operations. 

24 State of the Art (SOT A) Manual for Boilers and Process Heaters, NJ DEP. Revised February 22, 2004. 

26 
Table 5. Process Fugitive Control Techniques for Copper Smelting Operations 

Process Fugitive Control Techniques 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/repair program 1 

Improve leak detection/repair, including improved detection through use of optical gas 8 

imaging 

Prompt repairs of exhaust hood leaks 7 

Increase exhaust rate of primary control system 7 

Add curtains to increase hood capture efficiency 7 

Capture system that collects the gases and fumes from transfer of molten materials from 6 

smelting and converting vessels 

Capture systems that collects the gases from each vessel used to refine blister copper, remelt 6 

anode copper, or remelt 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. 

New RACT 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 of data 

A full RACT analysis for this source is not provided. The following are examples of areas where the 

RACT analysis does not provide adequate data: 

• A complete RACT 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 of potential control measures is not sufficient because 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 FGR and LNB. KUC estimated a cost of $26, 790/ton NOx to install 

SCR. An 80% control efficiency was estimated for SCR, which is low compared to the typical value of 

90% for SCR on natural gas fired boilers, as show in Table 3. No costs of additional 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. 

27 
KUC asserts that current controls and practices constitute RACT for every emission source. However, as 

described in EPA's April25, 2007 PM2.5 implementation rule (72 FR 20594), the EPA defines RACT as 

"the lowest emissions limitation that a particular source is capable of meeting 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 of additional controls for any emission 

sources (with the exception of refinery boilers) to determine if there exists any reasonably available 

control technology to achieve the lowest emission limitation that the source is capable of meeting. 

Recommendations 

• Request the State to provide a full RACT analysis including supporting documentation (see 

attached RACT Analysis list). 

• Recommend further evaluation of the cost to 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. 

28 
Tesoro Salt Lake City Refinery 

Evaluation ofRACT Analysis 

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 Support Document (TSD) for the Utah PM25 State Implementation Plan (SIP). Throughout this 

document, the emission sources and controls at Tesoro may be compared with those at other refineries in 

Utah PM2.5 nonattainment areas that were previously evaluated by EC/R, including Chevron, Holly, and 

Big West Oil. 

SUMMARY OF RACT ANALYSIS 

Facility description 

The Tesoro refinery processes and refines crude oil into more useful products. Table 1 provides 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 (CG 1 and CG2), each with one 

11.8 MW turbine with SoLoNOx controls and one 157.8 MMBTU/hr heat recovery steam 

generating unit; 

• Sulfur recovery unit (SRU); 

• Storage tanks; 

• 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 of the 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.

5 Attainment 

SIPs, Section 5, Control Strategies, available for public comment I 011/2012 - 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.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 to the sources identified above, are already 

controlled to some extent, and/or have overall less potential for significant reductions in emissions. These 

sources include: the storage tanks, the fugitive equipment and wastewater system, the flares, the cooling 

towers, and the compressor engines. 

SUPPLEMENTAL DATA 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 

Control Technology 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 consent decrees 

established with most US refineries through EPA's refinery initiative. The technologies required by these 

consent decrees, as summarized in the Emission Effects of Refinery Cases and Settlements document 28

; 

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 combustion promoters; 

• 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 not high enough for significant thermal NOx formation. LNB 

stages the combustion process to reduce thermal NOx, which occurs in the high temperature flame zone 

near the burners. The Environment Agency (EA), which is a British non-departmental public body, 

published a document on oil and gas processes

29 that supports Tesoro's conclusion that thermal NOx 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 of CoST was developed in 2008. The CMDB is available 

for download at: http://www.epa.gov/ttnecasl/cost.htm. 28 Including the Emission Effects of Refinery Cases and Settlements in Projections for the EPA's CAAA Section 

812 Analysis. E.H. Pechan & Associates. Available at: 

http://www.epa.gov/ttnchie I /conference/ei 15/session4/wilson.pdf 29 Oil and Gas Processes Supplementary Guidance Note, IPC S3 1.02, Environment Agency. First published 2000. 

30 
regenerators 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 operate their FCCU in partial bum mode. 

It appears that the Tesoro refinery does not operate any NOx control technologies on their FCCU 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 scrubber based NOx emission reduction technology to comply with a consent 

decree emission limit of 40 ppm. It is unknown what technologies, if any, are used to control NOx 

emissions from the FCCU at the Big West Oil (BWO) Refinery. 

The following technologies for reduction of S02 emissions from FCCU are required in multiple EPA 

consent decrees with refineries: 

• Wet gas scrubber to 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, and the refinery does not have a vacuum tower to separate the residual oil from 

vacuum gas oil. Tesoro currently uses catalyst additives to control FCCU S02 emissions. BWO proposes 

the use of S02 catalyst additives in their RACT analysis, and the Chevron refinery currently uses catalyst 

additives. The Holly refinery currently operates a wet scrubber to comply with a consent decree emission 

limit of 24 ppm S02. According to the Tesoro RACT analysis, S02 catalyst additives typically achieve 

20-60% emission reduction, while wet scrubbers can achieve 95% emission reduction. The EA document 

cites a wet scrubber S02 removal efficiency of 90% or better from the FCC flue gas. 

Technologies for reduction of PM 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 part to their pressure drop, as FCCU are particularly sensitive to pressure drop changes. In addition, 

cyclones are primarily used to remove larger particles 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, while the Holly refinery operates a wet scrubber. BWO operates 

a bank of cyclones in combination with a fabric filter on the cyclone underflow, and proposes to 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 owned treatment works (POTW) would not receive the 

purge stream from a wet scrubber due to the 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. 

31 
Process 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 

Control Technology Control Cost Effectiveness 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, ACT for PH 

*All costs and control efficiencies are from CoST. 

Table 4 provides the size and current controls and emission rates of the process heaters identified by 

Tesoro Refinery in their RACT analysis. 

Table 4. Tesoro Refinery Process Heater Information 

Process Heater Unit# Current Current Emission 

(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-1 01, F -680 or F-681 because these units are identified as well 

controlled and satisfy RACT. The New Jersey State of the Art (SOTA) Manual for Petroleum 

Refineries31 provides SOTA performance. emission levels for refinery fuel gas-fired process heaters. 

These emission levels are usually accomplished with combustion controls and are 0.05 lb NOxiMMBTU 

for new units and 0.07lb NOx/MMBTU for burner replacements. Because Units H-101, F-680 and F-681 

operate below these emission limits, Tesoro's contention that these 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 FR 20594), 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 of the Art (SOTA) Manual for Petroleum Refmeries, NJ DEP. July 1997. 

32 
However, because these units are small, have low emissions, and are already controlled by LNB, the 

incremental cost of additional controls would likely be high and may not be economically feasible. 

Tesoro states that ULNB and SCR for unit F -1 is currently being evaluated with the assistance of vendors, 

and cost information should be available by the end of October. In their RACT analysis, Tesoro does not 

state their intent to evaluate LNB with FGR, SNCR, or SCR/SNCR with LNB, as potential RACT options 

for any of their process heaters. 

Cogeneration Units 

Table 5 provides NOx control technologies identified for natural gas-fired turbine cogeneration units from 

EPA sources. 

Table 5. NOx Control Technologies Identified for Natural Gas-fired Turbine Cogeneration Units 

Control Technology Control Cost Effectiveness 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 

SCR and 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 of the other technologies 

identified in Table 5. Based on information from the New Source Review (NSR) permit for this facility32, 

the turbines are currently equipped with SoLoNOx technology, a form of staged combustion or LNB. 

In their RACT analysis, Tesoro stated that the cogeneration units are guaranteed to meet 32 ppm@ 15% 

0 2, which met BACT at time of installation in 2003. The guaranteed emission limit of 32 ppm is below 

the Massachusetts Department of Environmental Quality Engineering Rule 31 0 CMR 7.1933 emission 

limit of 42 ppmv NOx, which is defined as RACT by Massachusetts for combined cycle stationary 

combustion turbines (similar to 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 of the Waxy Crude Processing Project by 

late 2014. Tesoro asserts that a TGTU satisfies RACT, and conducts no additional emissions or cost 

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 

emissions from the tail gas incinerator (TGI) to a wet scrubber. Another potential control that was not 

considered by Tesoro is proposed at the Big West Oil (BWO) refinery, and includes redundant sulfur 

32 State of Utah DEQ, Approval Order Number: DAQE- AN103350056-12. January 18,2012. 33 Massachusetts Department of Environmental Quality Engineering Rule 31 0 CMR 7.19 Reasonably Available 

Control Technology (RACT) for Sources of Oxides ofNitrogen (NOx). Available at: 

http://www .epa.gov/regionl/topics/air/sips/ma!MA 7 19 .pdf 34 State of the Art (SOTA) Manual for Stationary Combustion Turbines, NJ DEP. Last Revised December 21, 2004. 

33 
capture technology for use during planned and unplanned outages of the amine units and SRU. The 

alternative technology would include separate caustic gas scrubbers for sour fuel 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 sulfur technology to account for potential 

increased S02 emissions during outages of the SRU, which may not be accounted for at Tesoro and other 

refineries. 

Tesoro states that their TGTU will reduce emission to levels better than NSPS Subpart Ja, which requires 

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 equivalent to RACT. However, as described in EPA's April25, 2007 PM2.5 

implementation rule (72 FR 20594), the EPA defines RACT as "the lowest emissions limitation that a 

particular source is capable of meeting 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. Therefore, RACT 

is determined on a case-by-case basis and an NSPS emission limit cannot be 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 limit of 300ppmvd total reduced sulfur (TRS) (measured as S02) at 0% 0/, 

FINDINGS 

Sources of RACT 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 that they are proposing to install a tail gas treatment unit (TGTU) to 

control emission of S02 by 259 tpy. The TGTU is part of the Waxy Crude Processing Project and is 

expected to be installed in late 2014. 

Adequacy of data 

A full RACT analysis for this source is not provided. The following are examples of areas 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 of potential control measures is not sufficient because Tesoro did not evaluate all 

appropriate RACT options (e.g., LNB with FGR, SNCR, or SCR/SNCR with LNB for process 

heaters; TGI for SRU; steam injection and water injection for cogeneration units). 

Cost effectiveness 

Fluid catalytic cracking unit (FCCU) and CO 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 $20,1 00/ton so2 (88% control); 

• SCR at $36,000/ton NOx, Wet Scrubber+ LoTOx at $108,000/ton NOx (86% control) and 

$117,000/ton NOx (73% control), Wet scrubber+ SCR at $115,000/ton NOx, and SNCR at 

$22,000/ton NOx. 

34 
The cost effectiveness values identified by Tesoro for SCR are much higher than the values identified in 

Table 2. In the cost effectiveness analysis for PM control with wet scrubbers, Tesoro uses low control 

efficiency values as compared to 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-1 0 I. 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 SCR for each cogeneration unit. This cost is well above the 

cost effectiveness values for SCR identified in Table 5. 

Sulfur Recovery units 

Tesoro did not provide any cost effectiveness calculations for the SRU. 

Recommendations 

• Request the State to provide a full RACT analysis including supporting documentation (see 

attached RACT Analysis list). 

• Recommend further evaluation of the cost to install a wet gas scrubber for control of PM and S02 

emissions from the FCCU; including a review ofthe detailed cost analysis when this information 

is provided by Tesoro. 

• Recommend further evaluation of the cost to install SCR or SNCR for control ofNOx emissions 

from the FCCU; including a review of the detailed cost analysis when this information is 

provided by Tesoro. 

• Recommend further evaluation of the cost to install NOx emission controls for process heater F -1, 

including ULNB and SCR and SNCR, when this information is provided by Tesoro. 

• Recommend further evaluation of additional controls beyond the proposed TGTU for the SRU, 

including wet scrubbers after the TGI or the potential for redundant sulfur capture technology in 

the event of planned and unplanned outages. 

35 
ATTACHMENT 6 

EPA Region 8 Comments on Mobile Sources, Transportation Conformity, Related Contingency 

Measures, & I/M 

A.) Mobile Sources Comments on the Salt Lake Section of the SIP Narrative: 

Salt Lake Section: Control Measures for Area and Point Sources, Fine Particulate Matter, 

PM2.5 SIP for the Salt Lake City, UT Nonattainment Area Section IX. Part A.21 

1.) On-road mobile sources; the SIP Narrative states the following on pages 61 and 62 of the Salt 

Lake section: 

"A decentralized, test-and-repair program was evaluated for Box Elder and Tooele counties within 

the Salt Lake-Ogden-Clearfield nonattainment area. For the evaluation, all model year 1968 and 

newer vehicles would be subject to a biennial test except for exempt vehicles. The program would 

exempt vehicles less than four years old as of January 1 on any given year from an emissions 

inspection. Year 1996 and newer vehicles would be subject to an On-Board Diagnostics (OBD) 

inspection. Year 1995 and older vehicles would be subject to a two-speed idle inspection (TSl). 

Based on this evaluation, this program was not included because it was determined that 

implementation of such 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 comment A.l.: There would have been emission reductions ofNOx and VOCs identified with the 

State's evaluation. While just taken only by themselves, these liM emission reductions may not have 

shown a modeled difference at the Hawthorne monitor. However, such an liM program would likely 

produce viable PM2.5 precursor emission reductions for the Salt Lake-Odgen-Clearfield nonattainment 

area. Utah has not provided us with their evaluation and it would be helpful to see their analysis, with the 

estimated potential emission reductions 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 of the Salt Lake 

section: 

(EPA notes that UDAQ is currently evaluating the following additional control strategies for on-road 

mobile sources) 

"Reduction in the Reid vapor pressure (RVP) of gasoline: UDAQ is currently working with the 

Utah petroleum refining industry and other fuel suppliers to evaluate the effectiveness of seeking 

a mandatory or voluntary reduction in the Reid vapor pressure (RVP) of gasoline, 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 3 percent ofthe 

total reduction required to achieve attainment to come from voluntary and emerging mobile source 

strategies. Examples of such 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 with relevant agencies, 

authorities, and stakeholders." 

EPA Comment A.2.: The above two potential control strategies are a common theme for all three 

nonattainment areas. EPA was advised earlier that the State was evaluating emission reductions from the 

possible lowering of the gasoline RVP (from approximately 13 psi to 12 psi), but had also noted on a 

conference call that the Utah Petroleum Association had indicated that the winter time gasoline sold in the 

three nonattainment areas was already at a lower level than estimated by the State. Therefore, if this 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 of the Salt Lake 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 of nitrogen 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 conformity purposes. 

The UDAQ conducted are-entrained road dust study that concluded that PM2.5 re-entrained road 

dust emissions are negligible in Salt Lake City, Utah PM2.5 nonattainment area and meet the 

criteria of 40 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 of a 

direct PM2.5 budget in the transportation conformity budget section of the SIP. The State of Utah 

has concluded that only NO, and VOC emissions from on-road motor vehicles warrant 

consideration for potential emission reduction controls to peak PM2.5 levels in the nonattainment 

areas." 

EPA Comment A.3.: 40 CFR 93.102(b)(1) requires a motor vehicle emission budget (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 of 40 CFR 93.1 09(f) regarding "Areas with insignificant motor vehicle 

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 in Table 7.1 also on Salt Lake document 

page 71 (see EPA Comment A.4. below). 

4.) Transportation Conformity PM2.5 Budgets, section 7.6; the SIP Narrative presents the 

following on pages 27, 71, 74, and 75 of the Salt Lake section: 

2 
"This plan includes reasonable further progress demonstrations for 2014 and 2017 and attainment 

ofthe PM2.5 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 

emission budgets (MVEB) for NOx and VOC for 2014, 2017, and 2019." 

WFRC Transportation Conformity Budgets 

(tons per average winter day) 

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 of on-road mobile source emissions in the nonattainment area. This 

requirement is for the purposes of establishing motor vehicle emissions budgets for transportation 

conformity purposes (as required in 40 CFR part 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 of the 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 of motor vehicle emissions budgets for 

transportation conformity purposes, see Chapter 7 of this 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 Comment A.4.: There are inconsistencies, which the State needs to explain and/or reconcile, with 

the SIP Narrative 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 in tons per day). The "Inventory" and "RFP" MVEBs 

appear to track almost exactly, while the SIP Narrative identified MVEBs show variations: 

2014 2017 2019 

PM2.5 

Inventory* 4.61 4.11 3.50 

3 
SIP** 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 section page 27. 

* * SIP identified MVEBs as presented in Table 7.1 on Salt Lake section page 71. 

***RFP MVEBs as presented in Table 8.2 on Salt Lake section page 75. 

5.) Contingency Measures and Implementation Schedules for the Nonattainment Area, section 9.2, 

the SIP Narrative presents the following on page 77 of the Salt Lake section: 

"Transportation Control Measures (TCMs)- On-Road Mobile Sources account for most of the 

NOx and VOC emissions that lead to fine particulate formation in winter months. The controls 

affecting on-road mobile sources already accounted for in the attainment and RFP demonstrations 

are liM programs and Tier II of the 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 of these measures is Employer Based Trip Reduction, during wintertime 

periods when conditions warrant. It is herein identified as a contingency measure for the purpose 

of this Plan, with an implementation schedule to be determined." 

EPA Comment A.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 of CAA 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, if needed. The above 

statement; "It is herein identified as a contingency measure for the purpose of this Plan, with an 

implementation schedule to be determined." is insufficient. 

B.) Comments on the Logan/Cache County Section of the SIP Narrative: 

Cache Section: Control Measures for Area and Point Sources, Fine Particulate Matter, PM2.5 SIP 

for the Logan, UT - ID Nonattainment Area. 

1.) The following SIP Narrative discussion is provided on page 2 of the Logan section and is in 

regard to the dispersion modeled attainment demonstration and an 1/M program for Cache 

County: 

"In the enclosed SIP, we identify control strategies we have been able to develop through this 

process and the impact they will have on PM2.5 concentrations in the nonattainment area. Of 

special note in this SIP is that, through the stakeholder process and our analysis, it became 

apparent that the implementation of a vehicle inspection/maintenance (liM) program in the Cache 

Valley would allow the area to meet the standard by 2014 as required in the Clean Air Act. 

4 
However, the Cache County Council recently rejected a proposal to delegate the statutory 

authority to the Bear River Health Department to develop and implement this strategy. 

We have looked at other strategies that the Board has the authority to implement and that could 

possibly result in reductions near those that would result from an liM program, and have 

concluded that they are not reasonable. Therefore, this section of the SIP requires Cache County to 

implement a program by December 14, 2013, and within 90 days of the effective date of the SIP, 

to submit a schedule to the Director for developing the program with enforceable milestones that 

can be incorporated into the SIP and submitted to EPA. 

In speaking with the county leadership, we have also offered an alternative that, if during the 

public comment period, the county can identify 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 Comment B.l.: It is EPA's understanding that the dispersion modeled attainment demonstration 

for the Logan PM2.5 nonattainment area used NOx and VOC emission reduction credit from an liM 

program (two-speed idle and OBD) implemented in 2013 to demonstrate attainment in 2014. This will be 

an issue if the County Council stands behind their decision to implement an 1/M program that would 

achieve fewer emission reductions. 

2.) On-road mobile sources, the SIP Narrative states the following on page 60 of the Logan section: 

"As supported by 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 can be 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 Director for 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 subject to a biennial test except for exempt vehicles. The 

program will exempt vehicles less than four years old as of January 1 on any given year from an 

emissions inspection. Year 1996 and newer vehicles will be subject to an On-Board Diagnostics 

(OBD) inspection. Year 1995 and older vehicles will be subject to a two-speed idle inspection 

(TSl). The anticipated emissions reductions associated with this program for the year 2014 are 

0.24 tons per day for NOx and 0.22 tons per day for VOC." 

EPA Comment B.2.: EPA notes 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 of the potential Cache County liM program needs to be indicated by the State. 

3.) On-road mobile sources, the SIP Narrative states the following on page 63 of the Logan section: 

(EPA notes that UDAQ is currently evaluating the following additional control strategies for on-road 

mobile sources) 

5 
"Reduction in the Reid vapor pressure (RVP) of gasoline: UDAQ is currently working with the 

Utah petroleum refining industry and other fuel suppliers to evaluate the effectiveness of seeking a 

mandatory or voluntary reduction in the Reid vapor pressure (RVP) of gasoline, 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 3 percent ofthe 

total reduction required to achieve attainment to come from voluntary and emerging mobile source 

strategies. Examples of such strategies include, but are not limited to: 

• trip reduction programs 

• alternative fuels 

• diesel retrofits 

• episode-triggered/inversion-specific measures" (Logan document page 63) 

EPA Comment B.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 of the Logan section: 

"The transportation conformity requirements found in 40 CFR 93.102 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 of nitrogen 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 conformity purposes. The EPA conformity rule presumes that 

PM2.S re-entrained road dust does not need to be included in the interim conformity test or have 

an established motor vehicle emissions budget unless 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 of the Cache Valley PM2.5 nonattainment area. 

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 of a direct 

PM2.5 2 budget in the transportation conformity budget section of the SIP." 

EPA Comment B.4.: Region 8 has been approached by UDAQ to request EPA's interpretation and 

evaluation of the potential 2014 Logan PM2.s MVEB of 0.33 tons per day and the aspects/options of our 

conformity rule from sections; 40 CFR 93.1 09(f) Areas with insignificant motor vehicle emissions, 40 

CFR 93 .124( a) which addresses the identification and assignment of safety margin to MVEBs, and 40 

CFR 93 .124( c) which addresses the SIP requirements for the identification and assignment of emission 

trading. In an email from Tim Russ of EPA to Joe Thomas (UDAQ) and Rick McKeague III (UDAQ), 

dated October 10, 2012 and entitled "Direct PM 2.5 Issues for Cache County MVEBs: EPA Responses to 

State Questions", EPA presented answers, information, and options for UDAQ to consider for 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 PM2.5 nonattainment area. The State needs to 

review this email, advise if there are further questions, and revise this section of the SIP Narrative as 

appropriate. 

6 
5.) Transportation Conformity PM2.5 Budgets, section 7.6; the SIP Narrative states the following 

on page 68 of the Logan section: 

"In this maintenance plan, the State is establishing transportation conformity motor vehicle 

emission budgets (MVEB) for NOx and VOC for 2014 and 2019 for the nonattainment portions of 

Cache County, Utah. 

Direct PM2.5 

2014 TBD 

2019 TBD 

NOx VOC 

4.82 3.45 

3.61 2.48 

Table 7.1, Emissions Budgets for Transportation Conformity Purposes" 

EPA Comment B.S.: EPA has questions that the State needs to address regarding the MVEBs identified 

for 2019, the potential PM2.5 MVEB shown in Table 4.1 on page 26 ofthe Logan section ofthe SIP 

Narrative, and inconsistencies between the NOx and VOC MVEBs in Table 7.1 as compared to the 

emissions inventory data in Table 4.1 (both tables are from the Logan section of the SIP Narrative). 

a.) Assuming the Cache County I/M program is implemented, as stated in the Logan section of the 

SIP Narrative, and the Logan/Cache County area is shown to 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 on page 26 ofthe Logan section of the SIP Narrative displays PM2.5 mobile sources in 

2014 as 0.33 tons per day. This should essentially be identified as the 2014 PM2.

5 MVEB. 

c.) The 2014 mobile source NOx and VOC emissions shown in Table 4.1 (Logan section page 26 of 

the SIP Narrative), which should become the 2014 NOx and VOC MVEBs are inconsistent with 

those same MVEBs shown in Table 7.1 (Logan section page 68 of the SIP Narrative). The State 

needs to provide an explanation and/or reconcile these MVEBs concerns. Please see the EPA 

provided table below (all emissions in tons 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.) Contingency Measures and Implementation Schedules for the Nonattainment Area, section 9.2; 

the SIP Narrative states the following on page 71 of the Logan section: 

"Transportation Control Measures (TCMs)- On-Road Mobile Sources account for most of the 

NOx and VOC emissions that lead to fine particulate formation in winter months. The controls 

affecting on-road mobile sources already accounted for in the attainment and RFP demonstrations 

are liM programs and Tier II of the 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 of these measures is Employer Based Trip Reduction, during wintertime 

periods when conditions warrant. It is herein identified as a contingency measure for the purpose 

of this Plan, with an implementation schedule to be determined." 

EPA Comment B.6.: Same as EPA comment "A.5." above from the Salt Lake section. 

7 
C.) Comments on the Utah County Section of the SIP Narrative: 

Utah County: Control Measures for Area and Point Sources, Fine Particulate Matter, PM2.5 SIP 

for the Provo, UT Nonattainment Area. 

1.) On-road mobile sources; the SIP Narrative states the following on page 64 of the Provo 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 vapor pressure (RVP) of gasoline: UDAQ is currently working with the 

Utah petroleum refining industry and other fuel suppliers to evaluate the effectiveness of seeking a 

mandatory or voluntary reduction in the Reid vapor pressure (RVP) of gasoline, 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 3 percent ofthe 

total reduction required to achieve attainment to come from voluntary and emerging mobile source 

strategies. Examples of such 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 of the Provo section: 

"Currently the UDAQ is in negotiations with EPA Region 8 regarding the establishment of a 

direct PM2.5 budget in the transportation conformity budget section of the SIP. The State of Utah 

has concluded that only NOx and VOC emissions from on-road motor vehicles warrant 

consideration for potential emission reduction controls to peak PM2.5 levels in the nonattainment 

areas." 

EPA Comment C.2.: 40 CFR 93.102(b)(l) requires a motor vehicle emission budget (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 of 40 CFR 93.1 09(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 PM2.5 MVEB in Table 7.1 also on page 70 of the Provo section of 

the SIP Narrative (see EPA "Comment C.3." below). 

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3.) Transportation Conformity PM2.S Budgets, section 7.6; the SIP Narrative states the following 

on pages 70, 73, and 74 of the Provo section: 

RFP: 

"This plan includes reasonable further progress demonstrations for 2014 and 2017 and attainment 

ofthe PM2.5 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 

emission budgets (MVEB) forNOx and VOC for 2014,2017, and 2019." 

MAG Transportation Conformity Budgets 

(tons per average winter day) 

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" 

"Motor Vehicle Emissions: 40 CFR 51.1009 also requires that State shall include in its RFP 

submittal an inventory of on-road mobile source emissions in the nonattainment area. This 

requirement is for the purposes of establishing motor vehicle emissions budgets for transportation 

conformity purposes (as required in 40 CFR part 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 of the 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 of motor vehicle emissions budgets for 

transportation conformity purposes, see Chapter7ofthis Plan." 

Mobile Source Emissions 

Provo, UT PM2.S Nonattainment Area 

*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 in tons per average winter day 

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

Table 8.2.. Motor Vehide Emissions for Purooses of RFP 

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EPA Comment C.3.: There are inconsistencies, which the State needs to explain and/or reconcile, with 

the SIP Narrative identified PM2.5, 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 in tons per day). The "Inventory" and "RFP" MVEBs 

appear to track almost exactly, while the SIP Narrative identified MVEBs show variations: 

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 on Provo section page 27. 

* * SIP identified MVEBs as presented in Table 7.1 on Provo section page 70. 

***RFP MVEBs as presented in Table 8.2 on Provo section page 74. 

4.) Contingency Measures and Implementation Schedules for the Nonattainment Area, section 9.2, 

the SIP Narrative presents the following on page 76 of the Provo section: 

"Transportation Control Measures (TCMs)- On-Road Mobile Sources account for most of the 

NOx and VOC emissions that lead to fine particulate formation in winter months. The controls 

affecting on-road mobile sources already accounted for in the attainment and RFP demonstrations 

are liM programs and Tier II of the 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 of these measures is Employer Based Trip Reduction, during wintertime 

periods when conditions warrant. It is herein identified as a contingency measure for the purpose 

of this 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 ofthe UDAQ memorandum to the 

UAQB.) 

"SUBJECT: PROPOSE FOR PUBLIC COMMENT: Repeal and Reenact Utah State 

Implementation Plan Section X, Vehicle Inspection and Maintenance Program, Part A, General 

Requirements and Applicability; Section X, Vehicle Inspection and Maintenance Program, Part B, 

Davis County; Section X, Vehicle Inspection and Maintenance Program, Part D, Utah County; 

Section X, Vehicle Inspection and Maintenance Program, Part E, Weber 

County; Add new Section X, Vehicle Inspection and Maintenance Program, Part F, Cache 

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County; and Amend R307-110. General Requirements: State Implementation Plan. 

Background 

Utah Code Annotated 41-6a-1642 gives authority to each county to design and manage a vehicle 

inspection and maintenance (liM) program to 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 

Air Act (CAA) to implement an I/M program to attain and maintain the ozone and carbon 

monoxide NAAQS. 

An I/M program has been identified as a necessary control strategy for Cache County to attain the 

PM2.5 NAAQS. 

Proposed Changes to the Utah State Implementation Plan 

We are proposing to repeal and reenact Section X, Part A to summarize current liM requirements 

that are common among all liM programs. The Air Quality Board last adopted Section X, Part A 

on March 31, 2004. In addition, we are proposing to repeal and reenact Section X Parts B, D, and 

E to update each of these parts to reflect the current liM programs in Davis, Utah, and Weber 

counties. We are not amending Section X, Part C at this time because Salt Lake County officials 

are in the process of revising 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 liM program. 

We have attached the current State Implementation Plan (SIP) Section X, Part A, B, D, and E 

along with the proposed new Part F. 

Staff Recommendation: Staff recommends that the Board propose for public comment the repeal 

and reenactment of Section X, Parts A, B, D, and E ofthe SIP and add Part F, Cache County liM 

program to Section X. Staff also recommends that the Board propose for public comment the 

amendments to R307-110 to update the date these Parts ofthe SIP are adopted by the Air Quality 

Board." 

EPA Comment D.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 liM programs as per the minor changes from Utah 

HB 407 (1/M) of the 2012 Legislative Session. It is our understanding that this CAA section 11 0(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 Contingency Measures 

EPA Comment E.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 of the three PM2.s 

nonattainment areas. There may be potential discrepancies between the VMT data developed by the 

MPOs which was then used in EPA's MOVES2010a model to develop mobile sources emissions 

estimates for inventory data tables, the dispersion modeling, and for defining the respective nonattainment 

areaMVEBs. 

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EPA had prior questions regarding the VMT used by the State and by the MPOs to generate the mobile 

sources PM2.5, NOx, and VOC emissions. EPA reviewed the SIP modeling VMT data as shown below 

for the Wasatch Front Regional Council (WFRC) area of responsibility (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 data to those presented in the August, 2012 2011-2040 RTP air 

quality conformity analysis as provided in WFRC's Air Quality Memorandum 281 • 

From the "AQ memo 28" file above, we looked at Table 11 b for projected VMT figures for seasonal 

VMT for 2015 and 2020 for Salt Lake County only (Note: We reviewed the seasonal VMT from the 

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 winter time seasons). 

The VMT appear to be inconsistent between the SIP and the WFRC. For the 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 compared to 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 of these VMT figures are for the entire county, they should be very similar for 

2014 compared to 2015 and 2019 compared to 2020. 

For the Salt Lake Five County Nonattainment Area, EPA reviewed 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 between the SIP and draft conformity determination are even more pronounced for 

the larger Salt Lake Five County Nonattainment Area. For 2014 the PM2.s SIP daily VMT are 

53,518,017; yet from the WFRC conformity determination for 2015, the daily VMT are only 47,502,009. 

The same situation occurs with 2019 SIP VMT when compared to 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). 

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EPA Comment E.2.) SIP Contingency Measures; deficiencies with the Transportation Control Measure 

(TCM). In all three nonattainment area sections of the SIP Narrative, the State provides the following 

language with regard to TCM contingency measures: 

"Additional control measures are available for contingency purposes, and they fall into the category 

known as TCMs. The most promising of these measures is Employer Based Trip Reduction, during 

wintertime periods when conditions warrant. It is herein identified as a contingency measure for the 

purpose of this 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 by the 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 with respect to a CAA section 108 TCM? We note though, the current State 

version of R307 -320 is inconsistent with CAA section 118 because it does not apply to private companies. 

Finally, EPA notes that we have never approved R307-320 into the Federal SIP. 

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