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 

DEC 2 2013 

RE: EPA Region 8 Comments on Utah's Draft 

PM25 State Implementation Plans and 

Technical Support Documents. 

Thank you for the opportunity to provide comments on the state of Utah's draft fine particulate matter 

(PM2.5) State Implementation Plans (SIPs) for the Salt Lake City and Provo areas, the technical support 

documents (TSDs), which were approved for public comment by the Utah Air Quality Board on 

September 11 , 2013, and Section IX, Part H that was approved for public comment by the Board on 

October 2, 2013 with comments due December 2, 2013. 

Our comments, which are detailed in the five enclosures to this letter, should be considered preliminary. 

Our preliminary assessment is that the draft PM2.s SIPs need additional development and analysis as 

detailed in the enclosed comments so that the PM2.s SIPs can be fully approved by the EPA. However, 

we will not reach any final conclusions until the state provides a formal submittal of the PM2.s SIPs and 

after we conduct our own notice and comment rulemaking. 

We want to acknowledge the tremendous efforts of the Utah Department of Air Quality (UDAQ) on ail 

of the hard work that has been undertaken on the draft PM2.5 SIPs. We also want to provide any 

assistance needed and look forward to working with you to resolve the issues that we have identified. 
If you have any questions, please contact me at 303-312-6416, or have your staff contact Crystal 

Ostigaard, Particulate Matter Program Manager, at 303-312-6602. 

Enclosures (5) 

Sincerely, 

~~~q Carl Daly, Director 

Air Program 

1) EPA Region 8 Comments for Utah PM2.s SIP Section IX Salt Lake City Part A.21 ; Provo Part A.22. 

2) EPA Region 8 Comments on Utah PM2.s SIP Sub Sections IX.H.11 , 12, and 13, RACT Discussion in 

SIP Narratives and RACT Technical Support Documents. 

3) EPA Region 8 Comments on Modeling Technical Support Documents for Utah SIP Control Measures 

for Area and Point Sources, Fine Particulate Matter, for the Salt Lake and Utah nonattainment areas. 

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

Measures, and liM. 

5) EPA Region 8 Comments on Emission Inventories and RACM Analysis for Area Source Rules. 
ATTACHMENT 1 

EPA Region 8 Comments for Utah PM2.5 SIP Section IX Salt Lake City Part A.21; Provo Part 

A.22. 

The following comments are the Region's general review of the SIP narratives and also comments based 

on Clean Air Act part D- Plan Requirements for Nonattainment Areas, subpart 1 - Nonattainment 

Areas in General, subpart 4 - Additional Provisions for Particulate Matter Nonattainment Areas, and 

State Implementation Plans; General Preamble for the Implementation of Title I of the Clean Air Act 

Amendments of 1990 (57 FR 13498; April 16, 1992). 

General Comments: 

a) The January 4, 2013 court ruling held that the EPA should have implemented the 2006 PM2.5 24-

hour standard based on both Clean Air Act (CAA) subpart 1 and subpart 4. Thus, the state should 

submit a subpart 1 and subpart 4 moderate area SIP. However, our review of the draft SIPs 

indicates that they do not address CAA subpart 4. Therefore, these aspects of the SIP are not 

approvable and will be discussed further (see CAA, part D, subpart 4 comments below). 

b) In the draft PM2.s SIPs, the state references the "EPA Clean Air Particulate Implementation Rule 

(FR 72, 20586)." However, this rule has been remanded, and the March 2, 2012 guidance titled 

"Implementation Guidance for the 2006 24-Hour Fine Particulate (PM2 5) National Ambient Air 

Quality Standards (NAAQS)" has been withdrawn. These two documents no longer adequately 

define what the SIPs should contain. Additionally, 40 CFR 51.1000, Subpart Z- Provisions for 

Implementation of PM2.s National Ambient Air Quality Standards should not be used because 

the information in the CFR comes from the 2007 Clean Air Particulate Implementation Rule that 

was remanded. 

c) Under Chapter 8 of the draft PM2.s SIPs, we have concerns regarding the "Full Implementation 

Reduction" and "Benchmark Emission Reduction" equations. From the 2012 draft SIP narratives 

and the new draft SIP narratives out for public comment, these equations have changed. 

d) Full Implementation Reduction equation for the draft 2012 SIPs was: 

"equals: (attainment inventory)- (baseline inventory)" 

However, the Full Implementation Reduction equation for the draft 2013 SIPs is: 

"equals: (baseline inventory)- (attainment inventory)" 

Benchmark Emission Reduction equation for the draft 2012 SIPs was: 

"equals: (Full Imp. Reduction) - (Milestone Date Fraction) 

However, the Benchmark Emission Reduction equation for the draft 2013 SIPs is: 

"equals: (Full Imp. Reduction) * (Milestone Date Fraction) 

Why were these equations changed? A discussion is needed on which equations are correct 

and how the changes affect reasonable further progress (RFP). 

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

SIP subsections IX.H.12 and 13, have modeled emissions based wholly or partly on projected 

actual emissions, or on 2008 actual emissions, rather than on allowable emissions. Of these 15 

sources, only five had enough information were we able to determine that the proposed 

allowable emissions in the draft SIP subsections are substantially greater than the modeled 

emissions, in terms of equivalent daily emissions. For the other ten of the 15 sources, we did not 

3 
have enough information to determine the difference between the projected actuals and proposed 

allowables. Currently, the draft SIP appears to lack the necessary evidence that projected actual 

will not be exceeded by an amount that would interfere with attainment or maintenance. Further 

detail can be found in Attachment 2. 

f) The RACT Summary Table, found on the state's website, lists emission reductions in tons per 

year (tpy) which are credited to various stationary sources. This is beyond the reductions 

achieved by existing emission controls. For some sources, the proposed RACT requirements do 

not include any requirement to achieve those additional emission reductions. For the additional 

reductions to be creditable, a requirement to achieve such reductions needs to be reflected in the 

SIP. Further detail can be found in Attachment 2. 

g) In the draft SIP subsections IX.H.l2 and 13, some sources do not have requirements to maintain 

existing emission controls as part ofRACT, only requirements to install new controls. The state 

needs to identify the existing local measures in the area that contribute to attainment of the 

NAAQS in the area, so the EPA can approve the measures specifically as RACT. Further detail 

can be found in Attachment 2. 

h) Some instances within the RACT Evaluation Report have identified a certain type of emission 

control option as RACT, but the draft SIP subsections IX.H.12 and 13 propose no corresponding 

RACT requirement. Further detail can be found in Attachment 2. 

i) Pre-baseline emission reduction credits were not included in the model nor was there definitive 

language in the draft SIPs stating that these credits would not be used. Further detail can be 

found in Attachment 3. 

j) There are discrepancies between the Salt Lake nonattainment area's SIP PM2.5 direct and 

nitrogen oxides (NOx) motor vehicle emissions budgets (MVEB) as compared to data from 

Wasatch Front Regional Councils (WRFC) August 22, 2013 conformity determination. Further 

detail can be found in Attachment 4. 

k) Vehicle Miles Traveled data for the Salt Lake nonattainment area is not consistent. The VMT 

data from the TSD show predicted growth, as would be anticipated, 2010 to 2014 and to 2017, 

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

their 2017 levels. Inconsistent data for VMT would have impacts on the MOVES modeling 

performed by the UDAQ to develop mobile sources emissions estimates for inventory data 

tables, the dispersion modeling, and for defining the respective nonattainment area MVEBs. 

Further detail can be found in Attachment 4. 

CAA part D, subpart 1 Comments 

CAA part D, subpart 1, 172(c) 

a) (1) In General. This section states "plan provisions shall provide for the implementation of all 

reasonably available control measures as expeditiously as practicable (including such reductions 

in emissions from existing sources in the area as may be obtained through the adoption, at a 

minimum, of reasonably available control technology). " However, many ofthe point sources 

will not implement controls until 2019. There is no analysis showing that it would be infeasible 

to implement the control measures earlier. See Attachment 2 for the EPA's more detailed review 

of reasonably available control technology (RACT). We also note that, to support a 

4 
demonstration that attainment by the moderate area attainment date is impracticable under CAA 

section 189(a)(l )(B), the state must show that it has adopted "all available control measures that 

are technologically and economically feasible. " See 57 FR 13544. Additionally, CAA section 

189( a)( 1 )(C) has an additional requirement for RACMIRACT implementation, see below. 

b) (9) Contingency Measures. The draft PM2.s SIPs contingency provisions do not satisfy applicable 

requirements. First, as noted in the General Preamble, the rule containing the contingency 

measure must clearly state that the measure will go into effect upon a determination by the EPA 

that the area has failed to make RFP or attain the NAAQS by the statutory deadline. See 57 FR 

13543. R307-302-3 merely states, "Ifthe PM2.s contingency plan ofthe State Implementation 

Plan has been implemented, the trigger level for no-bum periods as specified in R307-302-3(4) 

shall be 15 micrograms per cubic meter for the area where the PM2.5 contingency plan has been 

implemented." Neither the rule nor the SIP states that the contingency measures will be triggered 

by the EPA's determination that the area has failed to make RFP or attain the NAAQS by the 

deadline. Second, the General Preamble (57 FR 13543-13544) notes that the contingency 

measures "should be approximately equal to the emissions reductions necessary to demonstrate 

RFP for one year." The state has not estimated the emission reductions that would be achieved 

by lowering the trigger level for no-bum periods to 15 micrograms per cubic meter or whether 

those reductions would equal the reductions necessary to demonstrate RFP for one year. 

CAA part D, subpart 4 Comments 

CAA part D, subpart 4, 188(b) 

In the draft PM2.s SIPs, the state requests a five-year extension to December 14, 2019. This 

request could only be utilized under subpart 1. However, due to the January 4, 2013 court 

decision, implementation of the 2006 PM2.s 24-hour standard must follow CAA subpart 1 and 

subpart 4 and not exclusively subpart 1. Under subpart 4, the moderate area SIP attainment date 

is December 31 , 2015. Ifthe area does not attain by this date, the area will be reclassified to 

serious and have a serious area attainment date of December 31 , 2019. Thus, the state does not 

need to request a five-year extension but should begin to work toward developing a serious area 

SIP. However, the state is still required to submit a moderate area SIP that satisfies applicable 

CAA requirements, including the requirements to adopt and implement reasonably available 

control measures/reasonably available control technology (RACM/RACT). Regarding this, we 

reiterate what we stated above: to support a demonstration that attainment by the moderate area 

attainment date is impracticable under CAA section 189(a)(l )(B), the state must show that it has 

adopted "all available control measures that are technologically and economically feasible." See 

57 FR 13544. 

CAA part D, subpart 4, 189(a) 

a) In the draft PM2.s SIPs, the state provides a demonstration of attainment by December 14, 2019. 

However, under 189(a)(l)(B), a moderate area SIP needs to demonstrate attainment by the 

moderate area attainment date or demonstrate that attainment is impracticable by that date. The 

moderate area attainment date is December 31 , 2015. Thus, the SIP should demonstrate the 

impracticability of attaining by December 31 , 2015, and the state should begin to develop a 

serious area SIP that has an attainment date of December 31 , 2019. However, as noted above, the 

state is still required to submit a moderate area SIP by the applicable deadline (as discussed 

below, this is proposed to be December 31 , 2014) that satisfies applicable CAA requirements, 

including the requirements to adopt and implement RACM/RACT. 

5 
b) In the draft PM2.s SIPs, the state discusses RACM/RACT with implementation dates that range 

from 2014 to 2019. As stated above, 189( a)(l )(C), RACM/RACT for a moderate SIP shall be 

implemented no later than four years after designation, and under CAA section 172( c )(1 ), as 

expeditiously as practicable. However, in the draft SIPs some control measures won't be 

implemented until the end of 20 19, the serious area attainment date. This would not appear to 

meet the requirements of CAA section 189(a)(l )(C). Also, we reiterate what we stated above: to 

support a demonstration that attainment by the moderate area attainment date is impracticable 

under CAA section 189(a)(1 )(B), the state must show that it has adopted "all available control 

measures that are technologically and economically feasible." See 57 FR 13544. Did the state 

consider whether RACM/RACT could be implemented sooner? The SIP and/or the state's 

technical support document (TSD) must address this issue. For the serious area SIP development, 

all sources will need to be reviewed for best available control measure/best available control 

technology (BACM/BACT), which will have a later implementation date. 

CAA part D, subpart 4, 189(c) 

The draft PM2.s SIP narratives do not acknowledge that milestones must be submitted every three 

years until the areas are redesignated to attainment. The requirements are described in CAA 

section 189( c). 

CAA part D, subpart 4, 189(e) 

In the draft PM2.s SIPs, the state indicates that volatile organic compounds (VOC) and ammonia 

are precursors that are presumed to be excluded unless it is demonstrated that they are a 

significant contributor to PM2.s concentrations. This presumption of exclusion was only 

applicable under subpart 1. Under subpart 4, all control requirements applicable to major 

stationary sources of PM2.s also apply to major stationary sources of PM2.5 precursors, "except 

where the Administrator determines that such sources [of the precursors] do not contribute 

significantly" to PM2.s levels "which exceed the standard in the area." Additionally, the General 

Preamble (57 FR 13498; 13541) states the following: "EPA intends to make a formal 

determination as to whether major stationary sources ofPM10 precursors contribute significantly 

to PM10 levels in a particular area when it takes rulemaking action on the individual moderate 

area SIPs." We intend to apply the same approach for PM2.s· The state included VOC as a 

precursor that needed to be reviewed for stationary sources in the SIPs but excluded ammonia 

from further review. For ammonia, the state discusses doing a sensitivity run with the model to 

show that ammonia has no effect on predicted PM2.5 concentrations. The EPA will make a 

formal determination for PM2.5 precursors, including ammonia, during the action approving or 

disapproving Utah's SIPs. Ifthere is a stationary source of ammonia emissions that contributes a 

significant portion of the county or nonattainment area ammonia inventory, a model sensitivity 

study should be performed to evaluate the effect of that source on ammonium nitrate 

concentrations. For the EPA to adequately make this determination, documentation is needed 

showing that ammonia controls for stationary sources would have no effect on predicted PM2 5 

concentrations. This might be done by showing 1) that the fraction of ammonia emissions in the 

inventory from stationary sources is small relative to total anthropogenic emissions and 2) that 

stationary source ammonia emissions are a negligible fraction of total domain ammonia. Any 

showing would need to discuss the relative sizes of known anthropogenic emissions and likely 

natural emissions in the area, as indicated by monitored levels and other evidence. 

State Implementation Plans; General Preamble for the Implementation of Title 1 of the Clean Air 

Act Amendments of 1990, (57 FR 13498, April16, 1992), Comments. 

6 
a) Page 13539; (f) RFP/quantitative milestones. 

The General Preamble discusses that there is a gap in the law - the text of section 189( c) does 

not articulate the starting point for counting the 3-year period for quantitative milestones. The 

General Preamble states that the EPA believes it is reasonable to begin counting the 3-year 

milestone deadline from the due date for applicable implementation plan revisions containing 

the control measures for the area. The EPA recently signed a proposed rule that, if finalized, 

would set a new due date for CAA subpart 1/subpart 4 SIPs of December 31, 2014. Utah 

should include in its SIPs a discussion of milestones based on the proposed due date. If 

December 31, 2014, is finalized as the SIP due date, Utah will need to provide a milestone 

report every three years after December 31, 2014 until the area is redesignated. 

7 
ATTACHMENT 2 

EPA Region 8 Comments on Utah PM6.5 SIP Sub Sections IX.H.ll, 12, and 13, RACT Discussion 

in SIP Narratives and RACT Technical Support Documents 

I) Comments on Proposed SIP Subsection IX.H.ll - General Requirements 

These comments are based on EPA review of the following documents: 

Subsection H.ll (General Requirements) of a memorandum dated September 20, 2013, DAQ083-13 , from Bill Reiss ofUtah DAQ to Utah Air Quality Board, posted on Utah DAQ website 

at: http://www.airquality.utah.gov/Public-Interest/Public-Commen-Hearings/Pubrule.htm. 

RACT Evaluation Reports and RACT Summary Table for major stationary point sources, posted 

on Utah DAQ website (section 5.c ofTechnical Support Document) at: 

http://www .airq uality. utah. gov I Air Poll utants/ParticulateMatter/PM2 5/SaltLakeProvo/index .htm 

a) IX.H.ll.d: This subsection says "All emission limitations listed in Subsections IX.H.1 2 and 

IX.H.13 apply during steady-state operation, unless otherwise specified in the source-specific 

conditions listed in IX.H.12 and 13." This is inconsistent with CAA requirements that SIP 

emission limits apply at all times, including periods of startup, shutdown, and malfunction 

(SSM). See CAA section 302(k); 76 FR 21641 (April18, 2011 ). EPA's interpretation on this 

point has been upheld in several cases, including one involving our SIP call concerning 

Utah's unavoidable breakdown rule. See US Magnesium, LLC v. EPA, 690 F.3d 1157, 1170 

(lOth Cir. 2012). 

b) IX.H.ll.e.i.C and D: These subsections each include the following statement: "The back 

half condensables shall also be tested using the method specified by the Director." 

Everywhere else in these subsections; the language reads, "EPA-approved testing methods 

acceptable to the Director." The same language should be used here. 

c) IX.H.ll.e.i.G: This subsection does not list a specific method for VOC testing. Are there no 

methods that can be specified up front for VOCs? Please explain. 

d) IX.H.ll.g: There are no requirements in this subsection for CEMS. The draft SIP 

subsections for the individual refineries in IX.H.12 rely on CEMS for determining some of 

the emissions and emission factors for sulfur dioxide (S02), NOx and H2S. CEMS are 

required for other sources as well. Requirements to operate and maintain CEMS should be 

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

e) IX.H.ll.g.i.A.I: We have several comments on this subsection: 

1) This subsection specifies S02 emission limits of 25 ppmdv and 50 ppmdv at FCCUs. 

Please explain how it was determined that 25 ppmdv and 50 ppmdv represent RACT. We 

are not aware of any RACT Evaluation Report in the TSD that explains this. 

8 
2) This subsection specifies a 365-day rolling average basis and a 7-day rolling average 

basis for the emission limits. Please explain how averaging times longer than 24 hours 

can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 

3) What value was modeled in the attainment demonstration for S02 emissions on a 24-hour 

basis from FCCUs? Was it greater than 50 ppmdv, to account for greater variability than 

a 7-day average? 

4) This subsection requires compliance "By no later than January 1, 2018." Please explain 

why an earlier date would not be achievable. 

f) IX.H.ll.g.i.A.III: This subsection says "S02 emissions during periods of Startup, 

Shutdown, or Malfunction shall not be used in determining compliance with the emission 

limit of 50 ppmvd @ 0% excess 02 on a 7-day rolling average basis, provided that during 

such periods the owner or operator implements good air pollution control practices to 

minimize S02 emissions." As we have noted above, this is inconsistent with CAA 

requirements that SIP emission limits apply at all times, including periods of startup, 

shutdown, and malfunction (SSM). 

g) IX.H.ll.g.i.B.I: This subsection requires compliance "By no later than January 1, 2018." 

Please explain why an earlier date would not be achievable. 

h) IX.H.ll.g.i.B.II: This subsection requires a stack test once every five years at FCCUs for 

PM emissions. Please explain why once every five years is considered sufficient frequency. 

i) IX.H.ll.g.i.B.III: This subsection says "PM emissions during periods of Startup, Shutdown, 

or Malfunction shall not be used in determining compliance with the emission limit. .. " As 

we have noted above, this is inconsistent with CAA requirements that SIP emission limits 

apply at all times, including periods of startup, shutdown, and malfunction (SSM). 

j) IX.H.ll.g.ii.A: We have several comments on this subsection: 

1) This subsection requires compliance "By no later than January 1, 2018." Please explain 

why an earlier date would not be achievable. 

2) This subsection says " ... except during periods of startup, shutdown, or malfunction." As 

we have noted above, this is inconsistent with CAA requirements that SIP emission limits 

apply at all times, including periods of startup, shutdown, and malfunction (SSM). 

3) This subsection says "Compliance shall be based on a rolling average of365 days." 

Please explain how averaging times longer than 24 hours can represent RACT in a plan 

that is intended to attain a 24-hour NAAQS. 

4) This subsection specifies a limit of 60 ppm for hydrogen sulfide (H2S) in refinery plant 

gas. This sort of limit is normally set in lieu of S02 emission limits at individual emitting 

units that burn plant fuel gas. Please explain how this limit was factored into the 

attainment modeling, i.e., were plantwide allowable so2 emissions calculated using this 

limit? 

9 
k) IX.H.ll.g.iii.A: This subsection requires compliance "as soon as practicable but no later 

than January 1, 2018." Please explain why an earlier date would not be achievable. We do 

not view the phrase "as soon as practicable" to be practically enforceable; thus, it is not a 

meaningful addition to the date deadline and does not help meet CAA section 172( c)( 1)' s 

requirement that RACM/RACT be implemented "as expeditiously as practicable," or CAA 

section 189(a)(l)(C)'s requirement that "reasonably available control measures for the 

control of [PM2.sJ shall be implemented no later than ... 4 years after designation ... " 

l) IX.H.ll.g.iii.A.I: This subsection contains exemption language "in lieu of 40 CFR 

63 .654(b)." Please explain where this exemption language comes from, what its significance 

is in terms ofVOC emissions, and why it should be considered reasonable for inclusion in 

the PM2.s SIP. We could not find it in 40 CFR 63, subpart CC (National Emission Standards 

for Hazardous Air Pollutants from Petroleum Refineries). Please also explain why there is an 

exemption from requirements on heat exchangers when the process fluid contains less than 

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

m) IX.H.ll.g.iv.A: This subsection requires compliance "as soon as practicable but no later 

than January 1, 2018." Please explain why an earlier date would not be achievable. We do 

not view the phrase "as soon as practicable" to be practically enforceable; thus, it is not a 

meaningful addition to the date deadline and does not help meet CAA section 172(c)(l)'s 

requirement that RACM/RACT be implemented "as expeditiously as practicable," or CAA 

section 189(a)(l)(C)'s requirement that "reasonably available control measures for the 

control of [PM2 s] shall be implemented no later than .. . 4 years after designation ... " 

n) IX.H.ll.g.v: We question why the flare restrictions in this section and its subsections are 

limited to "hydrocarbon flares." What is the intended scope of this term, and is it intended to 

address flaring of sulfur-containing gasses? Given that S02 is a PM2.

5 precursor, it would 

make sense to require compliance with NSPS Subpart Ja's S02-related provisions. 

o) IX.H.ll.g.v.A: This subsection requires compliance "Beginning January 1, 2018." Please 

explain why an earlier date would not be achievable. Also, please explain what is meant by 

"affecting a designated PM2.5 non-attainment area ... " Is this defined somewhere? If so, this 

provision should include a cross-reference to ensure clarity. If not, the provision should be 

defined. 

In addition, while we support the requirement for the refineries to comply with Subpart Ja, 

we note that Subpart Ja contains an exemption from the H2S limit in 40 CFR 60.1 03a(h) for 

releases to the flare as a result of relief valve leakage or other emergency malfunctions. As 

we have noted above, this is inconsistent with CAA requirements that the SIP emission limits 

apply at all times, including periods of startup, shutdown and malfunction (SSM). The SIP 

should note that this exemption does not apply under the SIP. 

p) IX.H.ll.g.v.B: This subsection requires compliance "By no later than January 1, 2019." 

Please explain why an earlier date would not be achievable. Also, this subsection says 

"except during periods of startup, shut down, or malfunction." As we have noted above, this 

is inconsistent with CAA requirements that SIP emission limits apply at all times, including 

periods of startup, shutdown, and malfunction (SSM). 

10 
q) IX.H.ll.g.vi.A: This subsection requires compliance "Beginning January 1, 2017." Please 

explain why an earlier date would not be achievable. 

r) IX.H.ll.g.vi.B: This subsection says "These degassing provisions shall not apply while 

connecting or disconnecting degassing equipment." Please explain the basis for this 

exemption, i.e., why should it be necessary to exhaust VOCs to the atmosphere while 

connecting or disconnecting degassing equipment? 

II) Comments on Proposed SIP Subsections IX.H.12 and IX.H.13 - Source-Specific Emission 

Limitations in Utah PM 2.5 Nonattainment Area 

These comments are based on EPA review of the following documents: 

Subsections H.12 and H.13 of a memorandum dated September 20, 2013, DAQ-083-13, from 

Bill Reiss of Utah DAQ to Utah Air Quality Board, posted on Utah DAQ website at: 

http://www .airquality. utah. gov /Public-Interest/Pub! ic-Commen-Hearings/Pubrule.htm. 

RACT Evaluation Reports and RACT Summary Table for major stationary point sources, posted 

on Utah DAQ website (section S.c of Technical Support Document) at: 

http://www .airquali ty. utah. gov I Air Poll utants/ParticulateMatter/PM25/SaltLakeProvo/index.htm 

Point Source Reduction Summary table provided by Utah to EPA, via email dated October 31, 

2013, from Marty Gray ofUtah DAQ to Mike Owens ofEPA. This table lists the basis for 

"Emissions Modeled" for each of the 28 stationary sources that are subject to source-specific 

RACT, versus the basis for "SIP Emission Limits." 

a) General Comments 

1) Modeled emissions versus allowable emissions: According to the table provided to us on 

October 31,2013, for 15 ofthe 28 sources listed in draft SIP subsections IX.H.12 and 13, the 

modeled emissions are based wholly or partly on projected actual emissions, or on 2008 

actual emissions, rather than on allowable emissions. For five of these 15 sources, we were 

able to determine that the proposed allowable emissions in the draft SIP subsections are 

substantially greater than the modeled emissions, in terms of equivalent daily emissions. For 

the remaining ten of the 15 sources, we do not have enough information to determine 

whether or not the proposed allowables are substantially greater than projected actuals. 

Individual instances are cited in the source-specific comments below. 

The General Preamble 1 contemplates that source allowable emission limits may need to be 

reduced to the levels sources are actually emitting to support the modeled attainment 

demonstration. See 57 FR 13543. In a "SIP expectations" paper we provided to the state, via 

email from Carl Daly to Bryce Bird on July 5, 2012, we said, "The SIP submittal needs to 

provide evidence that projected actual emissions will not be exceeded by an amount that 

would interfere with attainment or maintenance of the PM2.

5 NAAQS." We are seeking an 

1 State Implementation Plans; General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990. 

57 FR 13497, April 16, 1992. 

11 
explanation why the state chose to use the projected actual emissions as the basis for the 

modeled emissions at these sources, rather than use the proposed allowable emissions. We 

are also requesting emissions information where we have been unable to determine whether 

or not the proposed allowables are substantially greater than projected actuals. Currently, the 

draft SIP appears to lack the necessary evidence that projected actuals will not be exceeded 

by an amount that would interfere with attainment or maintenance. 

2) Emission reductions being credited at some sources are not reflected in requirements to 

achieve those reductions. The RACT Summary Table on the state's website lists the emission 

reductions in tons per year which are being credited to various stationary sources, beyond the 

reductions achieved by existing emission controls. For some of those sources, the proposed 

RACT requirements in draft SIP subsections IX.H.l2 and 13 do not include any requirement 

to achieve those additional emission reductions. Individual instances are cited in the sourcespecific comments below. For the additional reductions to be creditable in the attainment 

demonstration, a requirement to achieve such reductions needs to be reflected in the SIP. 

3) Requirements for existing controls are not included as part of RACT at some sources. For 

some sources, requirements to maintain existing emission controls are not included as part of 

RACT in draft SIP subsections IX.H.12 and 13, but just requirements to install new controls. 

Individual instances are cited in the source-specific comments below. For an approvable 

attainment demonstration, the state needs to identify the existing local measures in the area 

that ·contribute to attainment of the NAAQS in that area, so that EPA can approve those 

measures specifically as RACT. 

4) Lack ofRACT requirements where a particular RACT control option has been identified. 

There are some instances where the RACT Evaluation Reports have identified a certain type 

of emission control option as RACT, but where the draft SIP subsections IX.H.12 and 13 

propose no corresponding RACT requirement. Individual instances are cited in the sourcespecific comments below. We are seeking explanations for these instances. 

5) Condensable particulate matter: There are a few instances where the RACT Evaluation 

Reports and proposed RACT emission limits in draft SIP subsections IX.H.12 and 13 do not 

take into account condensable PM. Individual instances are cited in the source-specific 

comments below. We are seeking an explanation why this was not done. If there is a valid 

basis for not considering condensable PM in particular cases (for example, if the source does 

not emit condensable PM or emits a de minimus amount), the TSD or the SIP should explain 

that basis. 

6) Emission limit averaging times. 'Some of the proposed source-specific RACT emission limits 

have averaging times longer than 24 hours. Individual instances are cited in the sourcespecific comments below. We are seeking an explanation how averaging times longer than 

24 hours can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 

7) Time allowed to comply. In nearly all instances where new controls and/or emission 

reductions are required, sources are being given until 2017 or 2019 to comply. Little or no 

explanation could be found for why that amount of time is necessary. Individual instances are 

cited in the source-specific comments below. We are seeking an explanation why an earlier 

date would not be achievable. As noted in our general comments in Attachment 1, under 

12 
CAA section 189( a)(l )(C), RACT for a moderate SIP must be implemented no later than 

four years after designation, and under CAA section 172(c)(l), as expeditiously as 

practicable. The draft SIP's extended deadlines to meet RACT appear to be inconsistent with 

the CAA's requirements. As also noted in our general comments in Attachment 1, to support 

a demonstration that attainment by the moderate area attainment date is impracticable under 

CAA section 189(a)(l)(B), the state must show that it has adopted "all available control 

measures that are technologically and economically feasible" by the moderate area 

attainment date. See 57 FR 13544. 

8) Stack test frequency. There are a number of instances where stack testing is required only 

once every 3 to 5 years. Examples are: Central Valley Water Reclamation, Chemical Lime, 

Great Salt Lake Minerals, Kennecott Power Plant, Kennecott Refinery, Nucor Steel, Proctor 

& Gamble, University of Utah, BYU, Geneva Nitrogen, and Provo City Power. We are 

concerned with stack test frequencies longer than one year. Please explain why these test 

frequencies are sufficient to ensure continuous compliance with the limits. 

9) Excess emission reporting. There are no proposed requirements for any sources to report 

excess emissions. Please explain how this will be addressed. 

1 0) Refineries (general): 

i) For all four petroleum refineries, draft SIP subsection IX.H.12 proposes sourcewide 

emission limits for PM2.s, S02 and NOx in tons per day (tpd) and tons per rolling 12-

month period. No other types of limits are proposed. The RACT Evaluation Reports for 

the refineries do not give any indication what emission limits in tons per day might 

represent RACT. Please explain how the proposed emission limits in tons per day were 

calculated and determined to represent RACT. Please also explain how rolling 12-month 

averages can represent RACT in a plan that is intended to attain a 24-hour NAAQS. 

ii) According to the RACT Summary Table, the Cooling Tower, Flares, Fugitives and Tanks 

VOC control methods at the refineries are not required for implementation until 2019. 

The VOC emissions involved are estimated as significant, at least 1,300 tpy, according to 

the Table. Please explain why an earlier date would not be achievable. 

iii) Sulfur Recovery Units (SRUs) are identified as RACT in the RACT Evaluation Reports 

for the refineries, but no level of control efficiency is identified as RACT. Draft SIP 

subsections IX.H.11 and IX.H.12 do not specify any level of control efficiency that the 

SRUs must achieve. We consider it essential to specify a level of control efficiency as 

RACT and would expect 95% or better control. Please supplement the TSD with a 

discussion of what level of control should be expected for the SRU at each refinery and 

include that level of control in draft SIP subsection IX.H.11 or IX.H.12. 

We also note that only one of the four refineries (Chevron) is required to measure S02 

emissions from the SRU, via CEMS. The draft SIP should require all four refineries to do 

this. See related comment above on IX.H.l1.g. 

b) ATK Launch Systems 

13 
1) Draft SIP subsection IX.H.12.a indicates that the proposed RACT provisions for A TK 

consist solely of limits on the pounds of reactive waste, reactive compounds, and rocket 

motor propellants that may be open burned or tested "when the PM2.s levels exceed 35 ug/m3 

at the nearest real-time monitoring station," during winter months (November through 

February). In our November 1, 2012 comments on an earlier draft of the PM2.s SIP, we stated 

that these proposed provisions are inconsistent with the CAA and EPA's regulations on 

dispersion techniques and intermittent control systems ( 40 CFR 51.118 and 51.119) and are 

not creditable for purposes 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. Regarding the 

proposal to apply the requirements on a seasonal basis, EPA is evaluating whether this is an 

acceptable approach to address PM2.s under the CAA. 

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

to investigate alternatives to open burning or testing, such as waste minimization, other 

means of disposal, or transporting the materials somewhere outside the nonattainment area 

before burning or testing, are proposed. The proposed provisions do not appear to be based 

on a RACT analysis, nor is it clear whether these provisions represent a reduction from 2008 

baseline emissions. It is also not clear what pollutant(s) these provisions are intended to 

address. It is also not clear why certain provisions only apply to rocket motors less than 

1,000,000 lbs. of propellant per motor and larger motors are not addressed. 

2) None of the provisions identified as RACT controls in the RACT Evaluation Report are 

reflected as proposed RACT in draft SIP subsection IX.H.12.a. Page 4 of the Report 

identifies RACT for NOx as replacement of the burners at the two largest boilers (each rated 

at 71.1 MMBtulhr) with LNB + FGR. Page 5 identifies RACT for VOC as the current 

practice of using oflow VOC and/or low vapor pressure solvents, the storing ofVOC 

emitting material in closed containers, and practices to prevent spills. Page 8 identifies 

RACT for PM2.s, S02, NOx and VOC as increased waste minimization efforts to reduce open 

burning, and notes that A TK has a waste minimization program in place. Please explain why 

none of these selected RACT controls in the RACT Evaluation Report are reflected as 

proposed RACT in draft SIP subsection IX.H.12.a. 

3) The RACT Summary Table projects a 9.24 tpy reduction in NOx emissions resulting from 

installation of LNB + FGR at the two 71 MMBtu/hr boilers. If A TK is being credited with a 

NOx reduction due to installation of new controls as RACT, then this needs to be reflected as 

proposed RACT in draft SIP subsection IX.H.12.a. The draft SIP subsection does not 

currently propose any controls for these boilers. 

4) The RACT Summary Table indicates that LNB and FGR will be installed at the 71 

MMBtu/hr boilers for NOx control by 2017. Please explain why an earlier date would not be 

achievable. 

5) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31 , 2013 does not include ATK, therefore we have no information on what 

emissions basis was used for modeling (e.g. , projected actuals, proposed allowables, 90% of 

14 
PTE, or possibly something else) and how that compares to the emissions that are proposed 

to be allowed. 

c) Big West Oil Refinery (a.k.a. Flying J) 

1) The RACT Summary Table indicates that ultra low NOx burners (ULNB) will be installed by 

2017, and that a flue gas filter for PM control, deSOx catalyst for S02 control, and a 

redundant scrubber for S02 control will all be installed by 2019. Please explain why an 

earlier date would not be achievable. 

2) There are a number of instances where new controls are identified as RACT in the RACT 

Evaluation Report, and are credited with emission reductions in the RACT Summary Table, 

but are not required in draft SIP subsection IX.H.12.b: 

i) Page 5 of the RACT Evaluation Report identifies RACT for S02 at the FCCU as use of 

deSOx catalyst. The Report says an S02 reduction of 125 tpy is expected. This expected 

reduction is also cited in the RACT Summary Table, to be achieved by 2019. 

ii) Page 8 of the RACT Evaluation Report identifies RACT for NOx at Process Heaters and 

Boilers as retrofitting the three boilers and replacing the unifier charge heater with ULNB 

capable of achieving a NOx emission rate of 0.035 lb/MMBtu. The Report says a NOx 

reduction of 30 tpy is expected. This expected reduction is also cited in the RACT 

Summary Table, to be achieved by 2017. 

iii) Page 9 of the RACT Evaluation Report identifies RACT for S02 at the SRU as 

installation of a redundant S02 caustic scrubbing system, to be operated in the event of 

SRU malfunction or planned outage. The Report says an S02 reduction of 50 tpy is 

expected. This expected reduction is also cited in the RACT Summary Table, to be 

achieved by 2019. 

Draft SIP subsection IX.H.l2.b specifies the calculations to be used for demonstrating 

compliance with sourcewide S02 and NOx emission limits, but it is not apparent whether 

any of these calculations take into account any requirement to install and use new 

emission controls. Please explain. If Big West Oil is being credited with emission 

reduction due to installation of new controls as RACT, then this needs to be reflected as 

proposed RACT in the SIP. 

3) Page 12 of the RACT Evaluation Report proposes no changes to existing wastewater 

operations as VOC RACT for wastewater separators and drains. One option is presented as 

technically feasible (ensuring all drains are covered and routing the API separator vent gas to 

a control device for thermal combustion or oxidation), with potential 70% VOC control, but 

was not selected as RACT. One other area refinery (Chevron), however, operates a 

regenerative thermal oxidizer system in conjunction with covers and vent routing. Page 12 of 

the RACT Evaluation Report for Big West Oil estimates VOC emission reductions as high as 

38 tpy if a similar system were employed at Big West, but does not propose such a system, 

instead stating only that "further discussions on controlling wastewater VOC emissions need 

to be held." Since it is proven to be technically and economically feasible at another area 

refinery, why is it not proposed here? Please explain. 

15 
4) Under "Source-wide PM2.s," draft SIP subsection IX.H.12.b.i. reads, "Following installation 

of the Flue Gas Blow Back Filter (FGF)," but does not specify a deadline for installation of 

the FGF. This is not approvable because the limits key offofinstallation ofthe FGF. 

5) Same paragraph, the SIP language proposes to defer the establishment of a condensable ratio 

for the Catalyst Regeneration System until "no later than January 1, 2019." At that time a 

new source-wide limit will be established in an AO. This is not approvable. There is no 

explanation why it would not be possible to establish the condensable ratio now, through 

testing, use of emission factors, or estimates. The SIP is supposed to evaluate RACT for 

condensable and filterable PM. The SIP cannot defer the establishment of limits. And the SIP 

must contain the RACT limits, not an AO. 

6) In the next paragraph, the language reads, "Filterable PM2.s emissions shall be determined by 

applying various emission factors ... " This language is imprecise/vague. Please delete the 

word "various." . 

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

Order ... " This is not approvable language. EPA needs to be able to approve any revisions to 

the methods for determining compliance, unless the SIP establishes enforceable, replicable 

procedures for modifying the methods. For example, where a revision to an emission factor is 

established through a simple stack test, we have been willing to approve SIP language that 

describes the process. The process should include notice to us of the stack test date, results, 

and new emission factor. 

8) In the next paragraph, the language reads, "Daily gas consumption by all boilers and furnaces 

shall be measured by meters that can delineate the flow of gas to the indicated emission 

points." The phrase "indicated emission points" is undefined. The SIP language needs to 

specify the emission points that are covered. 

9) Source-wide NOx provisions: Same issues regarding use of phrase "various emission 

factors," AO overriding the SIP for establishment of emission factors, AO as the future 

location for emission factors should "future information reveal that there is a difference in the 

emission factors for natural gas and plant gas," and use of the phrase "indicated emission 

points." 

1 0) Source-wide S02 provisions: Same issue regarding use of the phrase "various emission 

factors." Also, the phrase "by whatever meters are necessary" is imprecise/vague. Also, there 

is no requirement for S02 CEMS or any other technique for accounting for SRU emissions. It 

is our understanding that the SRU at each refinery has an S02 CEMS, which we would 

expect to be used to account for a portion of source-wide S02 emissions. See, for example, 

SIP subsection IX.H.12.g.iii for Chevron, which requires use of S02 CEM in determining 

S02 emissions from the SRU. Please explain why this is not accounted for at Big West. 

11 ) The RACT Evaluation Report does not identify any level of control efficiency as RACT for 

S02 emissions from the SRU at Big West Oil, nor does this appear in draft SIP subsections 

IX.H.11. or IX.H.12.b. We consider it essential to specify a level of control efficiency as 

RACT and would expect 95% or better control. Please supplement the TSD with a discussion 

16 
of what level of control should be expected for the SRU at Big West Oil and include that 

level of control in draft SIP subsection IX.H.ll or IX.H.l2.b. 

12) Draft SIP subsection IX.H.12.b relies on NOx and H2S CEMS to determine some of the 

emissions and emission factors, but this subsection of the draft SIP doesn't clearly require the 

operation of CEMS. This does not appear to be addressed by the General Requirements for 

Petroleum Refineries at draft SIP subsection IX.H.l1.g. Please see our related comment on 

IX.H.11 .g. 

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

be addressed. 

d) Bountiful City Light & Power 

1) Comments on Gas Turbine # 1 : 

i) The table provided to us on October 31 , 2013 indicates that NAAQS attainment modeling 

was based on projected actual emissions for existing turbine GT #1 and for the existing 

internal combustion engine #8. Page 2 of the RACT Evaluation Report indicates that 

2008 actual emissions for GT # 1 were less than 1 ton/year for each pollutant of interest 

(PM2.s, NOx, S02 and VOC). We expect that the projected actual emissions would be 

only slightly higher. However, draft SIP subsection IX.H.l2.c indicates that the proposed 

RACT allowable for GT #1 is 0.6 grams NOx per kilowatt-hour. Since GT #1 is rated at 

5.3 MW, the proposed RACT allowable is equivalent to allowable NOx emissions of7 

lblhr, or 30.7 tons/year. The RACT Evaluation Report indicates that the PTE for this 

turbine is 13.3 tons/year for NOx. Please explain how the proposed RACT allowable 

could equate to a tons/year figure that is substantially more than the PTE. Also, please 

explain how the projected actual emissions could be a valid basis for modeling when the 

proposed allowable emissions are at least 30 times higher (30.7 tons/year allowed versus 

less than 1 ton/year actual). 

2) Comments on Gas Turbines #2 and #3: 

i) The table provided to us on October 31 , 2013 indicates that modeling was based on 90% 

of PTE for the two new turbines. Page 2 of the RACT Evaluation Report indicates that 

the PTE for NOx for each new turbine is 39.65 tons/year. The proposed RACT allowable 

in draft SIP subsection IX.H.l2.c. is 15 ppm for NOx at each turbine. Please explain what 

the equivalent allowable would be in terms of tons/year and how that compares to the 

PTE figure of39.65 tons/year. Our objective here is to see ifthere is a substantial 

difference between the proposed allowable emissions and the emissions used for 

modeling. 

3) Comments on Dual Fuel IC Engine #8: 

i) Draft SIP subsection IX.H.12.c does not include any proposed emission limits or 

operational restrictions as RACT for IC Engine #8. Page 11 of the RACT Evaluation 

17 
Report identifies Good Combustion Practices as RACT for NOx at this engine. The 

current title V permit specifies a NOx emission limit for this engine in grams per 

horsepower-hour, and requires testing for compliance after every 800 operating hours, or 

at least once every 24 months. Please explain why this emission limit was not included in 

subsection IX.H.12.c. as proposed NOx RACT for this engine. 

e) Constellation Energy Resources (CER Generation II, LLC), West Valley Power Plant 

I) The table provided to us on October 31 , 2013 indicates that modeling was based on projected 

actual emissions. However, page 1 of the RACT Evaluation Report indicates that "Rather 

than using the actual emissions from 2008, potential to emit values (permitted emissions) are 

used for establishment of a baseline for RACT evaluation." This leaves it somewhat unclear 

whether PTE might have been used for modeling, rather than projected actual emissions. 

Please explain. Our objective here is to see if there is a substantial difference between the 

proposed RACT allowable and the emissions used for modeling. 

2) Page 4 of the RACT Evaluation Report identifies RACT for VOC as retention of the existing 

oxidation catalyst systems, and indicates that those systems can probably be expected to keep 

VOC emissions down to about 10 ppm. However, draft SIP subsection IX.H.12.d does not 

include any proposed emission limit or required controls for VOC. Please explain why this is 

not included. 

3) Draft SIP subsection IX.H.12.d. proposes RACT allowables for the turbines on a 30-day 

rolling average. Please explain how 30-day rolling averages can represent RACT in a plan 

that is intended to attain a 24-hour NAAQS. 

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

require the operation of CEMS. This does not appear to be addressed by the General 

Requirements at draft SIP subsection IX.H.11 . Requirements to operate and maintain CEMS 

should be included in IX.H.11 or in IX.H.12.d. 

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

be addressed. 

f) Central Valley Water Reclamation 

I) For NOx control, page 4 of the RACT Evaluation Report recommends that RACT be no addon controls. However, page 3 of the Report indicates that Good Combustion Practices (GCP) 

is a technically feasible RACT option and offers no reason why GCP should be ruled out as 

RACT. Please explain whether the proposed performance-based RACT limits for NOx in 

draft SIP subsection IX.H.12.e. (which are 1.75 grams per horsepower-hour at the 1150 kW 

engine generators and 1.8 grams per horsepower-hour at the 1340 kW engine generators) are 

intended to represent GCP. If GCP is intended to be reflected in terms of some other type of 

requirement, then please explain why this was not included in IX.H.12.e. 

2) For VOC control, page 4 ofthe RACT Evaluation Report indicates that installation of 

oxidation catalyst for VOC control at the five IC engines is not economically feasible, but 

18 
offers no cost information to support this conclusion. This is not sufficient to satisfy RACT 

requirements. Please explain what information was used to arrive at this conclusion. 

3) The table provided to us on October 31, 2013 indicates that the emissions used for NAAQS 

attainment modeling were "2008 Actual." Pages 2 and 5 of the RACT Evaluation Report 

indicate that the 2008 total NOx emissions (for the IC engines and the digesters combined) 

were 28.41 tons. This figure is equivalent to average daily emissions of 0.078 tons. Draft SIP 

subsection IX.H.l2.e., however, proposes to allow NOx emissions from the IC engines of 

0.648 tpd and 205.6 tpy. No emission limits or operational limits are proposed for the 

digesters. Please explain how the 2008 actual emissions could be a valid basis for modeling, 

when the proposed allowable emissions are at least eight times higher (0.648 tpd allowed 

versus 0.078 tpd actual). Please also explain how 0.648 tpd was calculated to be an 

appropriate RACT limit. No such explanation appears in the RACT Evaluation Report. 

4) The proposed SIP language should be clarified as follows to ensure the enforceability of 

emission limits: 

i) Subparagraph i should clearly state that Central Valley Water Reclamation shall 

maintain and operate electrical meters to record the electricity production at each of the 

engines. The text should also identify the current engines at the plant. 

ii) In Subparagraphs ii and iii, please state the number of the 1150 kw and 1340 kw engine 

generators. 

iii) Subparagraph iv should clarify that compliance with the emission limits in 

Subparagraphs ii and iii shall be determined by stack test, and that compliance with the 

emission limit in Subparagraph i shall be determined through use of emission factors. 

Also, Subparagraph iv should state the required frequency of stack tests. If the required 

frequency will be less than once per year, please explain why such a frequency is 

adequate to ensure continuous compliance with the limits. 

g) Chemical Lime Company (LHoist North America) 

1) Draft SIP subsection IX.H.l2.f. requires installation of SNCR technology for NOx control 

and a baghouse for PM control on the Lime Production Kiln "upon source start-up." Page 1 

of the RACT Evaluation Report states that the kiln has been in "temporary care and 

maintenance mode" since November of2008. It is unclear whether this means the kiln is now 

completely shut down. Please explain whether "source start-up" means a cold start-up after a 

complete shutdown. 

2) The RACT Summary Table indicates that a baghouse will be installed at the lime processing 

rotary kiln for PMz.s control by 2019, and SNCR will be installed at the kiln for NOx control 

by 2019. Please explain why an earlier date would not be achievable. 

3) Draft SIP subsection IX.H.l2.f. does not include any proposed NOx emission limit after 

installation of SNCR technology at the kiln, nor does it indicate whether the SNCR will even 

be tested after it is installed. If Chemical Lime is being credited with a NOx emission 

19 
reduction due to eventual installation of SNCR, then this needs to be reflected in terms of a 

NOx emission limit and appropriate compliance testing requirements by a specific deadline. 

4) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed at Chemical Lime, on a plantwide daily basis. The 

table provided to us on October 31, 2013 lists emission figures in tons/year that were used for 

modeling for Chemical Lime. The basis for those figures is not indicated. We do not know if 

those figures might represent the proposed RACT allowable, i.e., installation of SNCR and a 

baghouse at the kiln after it resumes operation. Our objective here is to see if there is a 

substantial difference between the proposed allowable emissions and the emissions used for 

modeling. 

5) Condensable PM is not accounted for in the RACT Evaluation Report or in the proposed PM 

emission limit in draft SIP subsection IX.H.12.f. of 0.12 lbs/ton of stone feed. The SIP 

subsection does not indicate whether stack testing needs to include condensable PM. Please 

explain why condensable PM is not accounted for. See our related General Comment #5 on 

condensable PM above. Please also explain why the proposed emission limit is expressed as 

PM rather than PM2.5. The table provided to us on October 31, 2013 indicates that the 

emissions inputted to modeling were 117.42 tpy of PM2.s· How does this relate to the 

proposed emission limit of 0.12 lbs. of PM per ton of stone feed? 

6) Stack testing is proposed to be required at a minimum of every five years. We are concerned 

with stack test frequencies longer than one year. Please explain why these test frequencies 

are sufficient to ensure continuous compliance with the limits. 

h) Chevron Products Company- Salt Lake Refinery 

1) Page 8 of the RACT Evaluation Report identifies NOx RACT for Process Heaters and Boilers 

as replacement of boilers 1, 2 and 4 with ULNB capable of achieving a NOx emission rate of 

0.03 lb/MMBtu. The Report says a NOx emission reduction of 110 tpy is expected. This 

expected reduction is also cited in the RACT Summary Table, to be achieved by 2017. 

However, draft SIP subsection IX.H.12.g. does not include a requirement to replace boilers 1, 

2 and 4. The SIP subsection specifies the calculations to be used for demonstrating 

compliance with sourcewide NOx emission limits, but it is not apparent whether any of these 

calculations take into account any requirement to replace the boilers with ULNB. Please 

explain. If Chevron is being credited with emission reduction due to installation of new 

controls as RACT, then this needs to be reflected as proposed RACT in the SIP. Please also 

explain why an earlier date than 2017 would not be achievable. 

2) Page 7 of Chevron's own RACT analysis, dated March 11,2013, contains an analysis for 

three rich bum reformer compressor engines with a potential to emit of 159.2 tpy NOx each. 

Using air-to-fuel ratio (AFR) controls and Non-Selective Catalytic Reduction (NSCR) at a 

cost of $4,966/ton was considered by Chevron to be economically infeasible, but we find that 

conclusion to be questionable. Though Chevron states that AFR + NSCR will be 

implemented in the future "within one year of the date of entry of the pending draft 

agreement with EPA," it would appear to be a logical requirement for the PM2.s SIP. Why 

was it not discussed in the state's RACT Evaluation Report and why is it not proposed to be 

required for this SIP? 

20 
3) Under "Source-wide PM2.5," draft SIP subsection IX.H.l2.g.i. reads, "Filterable PM2.s 

emissions shall be determined by applying various emission factors ... " This language is 

imprecise/vague. Please delete the word "various." 

4) In the same paragraph, the language reads, "Unless otherwise specified by an Approval 

Order .. . " This is not approvable language. EPA needs to be able to approve any revisions to 

the methods for determining compliance, unless the SIP establishes enforceable, replicable 

procedures for modifying the methods. For example, where a revision to an emission factor is 

established through a simple stack test, we have been willing to approve SIP language that 

describes the process. The process should include notice to us ofthe stack test date, results, 

and new emission factor. 

5) In a later paragraph, the language reads, "Daily gas consumption by all boilers and furnaces 

shall be measured by meters that can delineate the flow of gas to the indicated emission 

points." The phrase "indicated emission points" is undefined. The-SIP language needs to 

specify the emission points that are covered. 

6) In a later paragraph, the language reads, "By no later than January 1, 2017, Chevron shall 

conduct stack testing to establish the ratio of condensable PM2.5 from the FCC Catalyst 

Regenerator and SRUs. At that time the condensable fraction will be added and a new 

source-wide limitation shall be established in the AO." This is not approvable. There is no 

explanation why it would not be possible to establish the condensable ratio now, through 

testing, use of emission factors, or estimates. The SIP is supposed to evaluate RACT for 

condensable and filterable PM. The SIP cannot defer the establishment of limits. And the SIP 

must contain the RACT limits, not an AO. 

7) Source-wide NOx provisions: Language reads, " ... the most recent listing of these emission 

factors is maintained in Chevron's AO." This is not approvable. The SIP must contain the 

relevant emission factors for RACT, not an AO. 

8) Source-wide S02 provisions: The RACT Evaluation Report does not identify any level of 

control efficiency as RACT for S02 emissions from the SRU at Chevron, nor does this 

appear in draft SIP subsections IX.H.ll. or IX.H.l2.g. We consider it essential to specify a 

level of control efficiency as RACT and would expect 95% or better control. Please 

supplement the TSD with a discussion of what level of control should be expected for the 

SRU at Chevron and include that level of control in draft SIP subsection IX.H.ll or 

IX.H.l2.g. 

9) Draft SIP subsection IX.H.12.g relies on NOx, S02 and H2S CEMS to determine some of the 

emissions and emission factors, but this subsection of the draft SIP doesn't clearly require the 

operation of CEMS. This does not appear to be addressed by the General Requirements for 

Petroleum Refineries at draft SIP subsection IX.H.ll .g. Please see our related comment on 

IX.H.ll.g. 

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

be addressed. 

21 
i) Great Salt Lake Minerals Corporation CGSLM): Production Plant 

1) The RACT Summary Table indicates that a PM emission limit of0.010 gr/dscfwill be 

imposed at all baghouses and scrubbers on salt/SOP production lines by 2017. Draft SIP 

subsection IX.H.12.h. requires stack tests by January 1, 2017. Page 13 of the RACT 

Evaluation Report indicates, however, that with the sole exception of wet scrubber AH-013 , 

all existing baghouses and scrubbers at GSLM can already meet 0.010 gr/dscf, as 

demonstrated by recent stack test results. The proposed limit "will be more representative of 

actual operations operating at RACT levels." Further, the existing emission limit for nine of 

the eleven PM control devices is already at or near 0.01 gr/dscf in the current NSR permit. 

Please explain why an earlier date than 2017 would not be achievable. It appears that only 

AH-013 needs time to comply. 

2) Draft SIP subsection IX.H.12.h. does not require stack testing for condensable PM. Please 

explain why condensable PM is not addressed. This is not explained in the RACT Evaluation 

Report. 

3) The RACT Summary Table indicates that ultra low NOx burners (ULNB) will be required at 

Boilers # 1 and #2 by 2017. Draft SIP subsection IX.H.12.h. requires stack tests by January 1, 

2017, to demonstrate compliance with a proposed NOx emission limit of9.0 ppmdv. Please 

explain why an earlier date would not be achievable. 

4) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31, 2013 indicates that the emissions used for modeling were "2008 Actual." 

The RACT Evaluation Report does not indicate what the emissions were in 2008. There is 

also no information on what the allowable emissions will be, on a plantwide daily basis, after 

RACT is applied. Our objective here is to see if there is a substantial difference between the 

proposed allowable emissions and the emissions used for modeling. 

5) The RACT Summary Table projects emission reductions by 2017 of22.12 tpy ofNOx (due 

to installation ofULNB) and 7.97 tpy ofPM (due to imposition of more stringent allowables 

in gr/dscf at existing PM controls). It is unclear why the state would use 2008 actuals as the 

basis for modeling, when emission reductions through application of new controls as RACT 

are projected after 2008. It appears that no credit for these reductions is reflected in the 

modeling. Please explain. 

6) Stack testing is proposed to be required at a minimum of every five years. We are concerned 

with stack test frequencies longer than one year. Please explain why these test frequencies 

are sufficient to ensure continuous compliance with the limits. 

7) Please explain why emission limits are proposed in terms of PM1 o rather than PM2.S· 

j) Hexcel Corporation 

1) Draft SIP subsection IX.H.12.i. proposes a plantwide limit on daily natural gas consumption 

and a plantwide limit on daily carbon fiber production. Page 5 of the RACT Evaluation 

Report indicates, however, that "existing controls" consist not only of a plantwide carbon 

22 
fiber production limit and a natural gas consumption limit (the latter for NOx and S02 

control), but also a plantwide VOC emission limit, along with various operational controls on 

incinerators/ovens. Please explain why no plantwide VOC emission limit or operational 

controls on the incinerators/ovens are proposed as RACT requirements. 

2) The RACT Evaluation Report also identifies continued use of incinerators as RACT for VOC 

control at Fiber Lines 2-8 and 10-12, the Pilot Plant, and the Matrix Operations. The current 

NSR permit (Approval Order) dated December 28, 2011, specifies minimum operating 

temperatures and residence times for the incinerators. Please explain why a requirement for 

continued use of these incinerators for VOC control, with appropriate operational parameters, 

is not included as proposed RACT in draft SIP subsection IX.H.12.i. 

3) The RACT Evaluation Report also indicates that Fiber Lines 13 and 14 currently are 

permitted with a baghouse for PM control, the use of ultra-low NOx burners for NOx control, 

and use of a Regenerative Thermal Oxidizer (RTO) for VOC emission control. The Report 

identifies these controls as RACT for PM2.5, NOx and VOC at Fiber Lines 13 and 14. The 

current NSR permit (Approval Order) dated December 28, 2011 , specifies operational 

requirements for the baghouse and RTO at these fiber lines. Please explain why no emission 

limits or requirements for PM2.s, NOx or VOC controls are proposed in subsection IX.H.12.i. 

as RACT requirements at Fiber Lines 13 and 14. 

k) Hill Air Force Base 

1) Page 1 of the RACT Evaluation Report says Hill AFB is subject to existing requirements in 

40 CFR 60, subparts De, IIII and JJJJ, as well as requirements in 40 CFR 63, subparts N, GG, 

ZZZZ, and DDDDD. These bodies of regulation contain numerous requirements for the 

pollutants of interest for the PM2.5 SIP. Compliance with NSPS (40 CFR 60) and MACT (40 

CFR 63) requirements is identified in several places in the RACT Evaluation Report as 

RACT for NOx and VOCs. Hill AFB is also subject to numerous other requirements for the 

pollutants of interest for the PM2.5 SIP (primarily for VOCs). These requirements may be 

found in the title V permit and pertain to topics such as surface coating operations, 

degreasing, and solvents. 

However, the only requirement proposed as RACT in draft SIP subsection IX.H.12.j. is a 

limit of 0.5 tpd of VOC emissions from painting and depainting operations. No such limit is 

proposed in the RACT Evaluation Report. As we explained in the General Comments above, 

for an approvable attainment demonstration, the state needs to identify the existing local 

measures in the area that contribute to attainment of the NAAQS in that area, so that EPA 

can approve those measures specifically as RACT. 

2) The only proposed emission limit in draft SIP subsection IX.H.12.j is 0.5 tpd for VOC 

emissions from painting and depainting operations. Subparagraph ii says, "Compliance with 

this daily average shall be determined monthly." This language is not approvable because it 

is inadequate to ensure enforceability of the limit. The SIP needs to specify the method(s) 

used to determine compliance, identify what specific painting and depainting operations at 

Hill AFB are to be covered by this limit, and require recordkeeping. Also, the import of 

Subparagraph ii is not clear. Is this intended to make the daily limit into a monthly average? 

23 
If so, we question whether an averaging time longer than 24 hours can represent RACT in a 

plan that is intended to attain a 24-hour NAAQS. 

3) We could find no explanation how 0.5 tpd ofVOC emissions from painting and depainting 

operations represents RACT. The RACT Evaluation Report does not propose any such limit. 

Please explain how this proposed limit was calculated to be RACT. 

4) Page 3 of the RACT Evaluation Report says no additional control is considered RACT for 

NOx for the 12 boilers at Hill AFB, on the basis of high cost, in dollars per ton ofNOx 

removed. The main reason given is that normally steam is provided from outside (Wasatch 

Energy Systems) and the boilers are only kept for the event that steam no longer can be 

provided from the outside. This may be appropriate for emergency operation, but if the 

outside source of steam is lost permanently, then the boilers at Hill AFB will have to operate 

routinely from then on. This could allow the dollars-per-ton costs to become feasible. Please 

address this concern. 

5) The RACT analysis for de greasing operations (section 2.1.d of the RACT Evaluation Report) 

appears inadequate. Questions include: Are there older units that could be replaced with 

newer units with up-to-date passive and active emissions control methods, such as 

condensers or carbon adsorption systems? Is there a smaller number of larger units that can 

be addressed separately, and/or multiple units in concentrated areas that could be addressed 

in groups? Has the use of low VOC solvents been examined? The July 16, 2013 TechLaw 

RACT evaluation states: "Nellis Air Force Base is in the RBLC as permitted with vapor 

condensers and recovery for controlling VOC emissions. It appears that there could be 

potential for emissions reductions from the same or similar technologies for some but not all 

of the degreasing operations at HAFB." Please explain whether these options have been 

considered, or will be considered. 

6) We have the same comment on the RACT analysis for general solvent use (section 2.1.g of 

the RACT Evaluation Report) as for degreasing operations above. Other facilities should be 

examined for potential RACT control measures. 

I) Holly Refining & Marketing Company 

1) The RACT Summary Table indicates that a Wet Gas Scrubber (WGS) will be installed for 

PM, S02 and NOx control at proposed FCCU #2 by 2017, that Selective Catalytic Reduction 

(SCR) will be installed for NOx control at heaters and boilers by 2017, that the compressors 

will be replaced with electric units for control of all pollutants by 2017, and that a WGS will 

be installed for S02 control at the Sulfur Recovery Unit (SRU) by 2017. Please explain why 

an earlier date would not be achievable. 

2) There are a number of instances where new controls are identified as RACT in the RACT 

Evaluation Report, and are credited with emission reductions in the RACT Summary Table, 

but are not required in draft SIP subsection IX.H.12.k: 

i) Pages 5 and 6 of the RACT Evaluation Report identify RACT for PM2.s and S02 at 

proposed FCCU #2 as installation of WGS. The Report says reductions of 30 tpy for 

24 
PM2.

5 and 260 tpy for S02 are expected. These expected reductions are also cited in the 

RACT Summary Table, to be achieved by 2017. 

ii) Page 7 of the RACT Evaluation Report identifies RACT for NOx at proposed FCCU #2 

as installation ofWGS-LoTOx. The Report says a NOx reduction of26.2 tpy is expected. 

This expected reduction is also cited in the RACT Summary Table, to be achieved by 

2019. 

iii) Page 9 of the RACT Evaluation Report identifies RACT for NOx at Process Heaters and 

Boilers as installation of SCR on three process heaters (1 OH1, 30H1 and 30H2) and 

Boiler #8. The Report says a NOx reduction of 35 tpy is expected. This expected 

reduction is also cited in the RACT Summary Table, to be achieved by 2017. 

iv) Page 9 of the RACT Evaluation Report identifies RACT for all pollutants at the 

Compressors as replacement ofthe existing compressors with all electric equipment. The 

Report says the expected emission reductions are 1.6 tpy for PM2.s, 0.04 tpy for S02, 96.2 

tpy for NOx, and 4 tpy for VOC. These expected reductions are also cited in the RACT 

Summary Table, to be achieved by 2017. 

v) Page 11 of the RACT Evaluation Report identifies RACT for S02 at the Sulfur Recovery 

Unit (SRU) as "continue to operate the WGS unit as a final S02 removal system for the 

existing SRU." The Report says a S02 reduction of 125 tpy from the 2008 baseline 

(modeled) inventory is expected. This expected reduction is also cited in the RACT 

Summary Table, to be achieved by 2017. 

Draft SIP subsection IX.H.12.k. specifies the calculations to be used for demonstrating 

compliance with sourcewide S02 and NOx emission limits, but it is not apparent whether 

any of these calculations take into account any requirement to install and use new 

emission controls. Please explain. IfHolly is being credited with emission reductions due 

to installation of new controls as RACT, then this needs to be reflected as proposed 

RACT in the SIP. 

3) Page 14 of the RACT Evaluation Report proposes no changes to existing wastewater 

operations as VOC RACT for wastewater separators and drains. One option is presented as 

technically feasible (ensuring all drains are covered and routing the API separator vent gas to 

a control device for thermal combustion or oxidation), with potential 70% VOC control, but 

was not selected as RACT. One other area refinery (Chevron), however, operates a 

regenerative thermal oxidizer system in conjunction with covers and vent routing. Page 14 of 

the RACT Evaluation Report for Holly estimates VOC emission reductions as high as 31.6 

tpy if a similar system were employed at Holly, but does not propose such a system, instead 

stating only that "further discussions on controlling wastewater VOC emissions need to be 

held." Since it is proven to be technically and economically feasible at another area refinery, 

why is it not proposed here? Please explain. 

4) Under "Source-wide PM2s," draft SIP subsection IX.H.12.k. reads, "PM25 emissions shall be 

determined by applying various emission factors ... " This language is imprecise/vague. 

Please delete the word "various." Also, unlike Big West and Chevron, this language does not 

say "filterable." Was that an inadvertent omission? 

25 
5) In the same paragraph, the language reads, "Unless otherwise specified by an Approval 

Order ... " This is not approvable language. EPA needs to be able to approve any revisions to 

the methods for determining compliance, unless the SIP establishes enforceable, replicable 

procedures for modifying the methods. For example, where a revision to an emission factor is 

established through a simple stack test, we have been willing to approve SIP language that 

describes the process. The process should include notice to us of the stack test date, results, 

and new emission factor. 

6) Language in a later paragraph reads, "Daily natural gas and plant gas consumption shall be 

determined through the use of flow meters." There is no indication where these meters are 

located, for which emission points they are tracking the fuel consumption, and how they 

would delineate the flow of gas to the emission points. The SIP language needs to specify the 

emission points that are covered. 

7) Source-wide S02 provisions: Language reads, " ... excluding routine SRU turnaround 

maintenance emissions." It is unclear why Holly needs this exemption when it is not 

proposed for the other refineries. As we explained in our comment on SIP subsection 

IX.H.1l.d, periods of exemption from emission limits are inconsistent with CAA 

requirements that SIP emission limits apply at all times, including periods of startup, 

shutdown, and malfunction. This comment applies also to periods of scheduled equipment 

maintenance. 

8) There is no requirement for S02 CEMS or any other technique for accounting for SRU 

emissions of S02. It is our understanding that the SRU at each refinery has an S02 CEMS, 

which we would expect to be used to account for a portion of source-wide S02 emissions. 

See, for example, SIP subsection IX.H.12.g.iii for Chevron, which requires use of S02 

CEMS in determining S02 emissions from the SRU. Please explain why this is not accounted 

for at Holly. 

9) The RACT Evaluation Report does not identify any level of control efficiency as RACT for 

S02 emissions from the SRU at Holly, nor does this appear in draft SIP subsections IX.H.11 . 

or IX.H.12.k. We consider it essential to specify a level of control efficiency as RACT and 

would expect 95% or better control. Please supplement the TSD with a discussion of what 

level of control should be expected for the SRU at Holly and include that level of control in 

draft SIP subsection IX.H.ll or IX.H.12.k. 

1 0) The source-wide S02 provisions include a provision that, "The sulfur content of the fuel oil 

shall be tested if directed by the Director." Why was this provision considered necessary for 

Holly? Chevron's source-wide S02 provisions also account for fuel oil, but do not include 

this particular provision. What is the import of this provision? If tests show a different sulfur 

content than the ASTM method, will the test results establish a new emission factor going 

forward? This is not explained. 

11) Unlike Big West and Chevron refineries, there is no requirement for NOx CEMS or any other 

technique for accounting for catalyst regenerator emissions ofNOx at Holly. See, for 

example, requirement for NOx CEMS at the Catalyst Regeneration System at Big West and 

26 
requirement for NOx CEMS at the FCC Regenerator at Chevron. Please explain why this is 

not accounted for at Holly. 

12) Draft SIP subsection IX.H.12.k relies on H2S CEMS to determine some of the emissions and 

emission factors, but this subsection of the draft SIP doesn't clearly require the operation of 

CEMS. This does not appear to be addressed by the General Requirements for Petroleum 

Refineries at draft SIP subsection IX.H.ll.g. Please see our related comment on IX.H.l1.g. 

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

be addressed. 

m) Kennecott- Bingham Canyon Mine/Copperton Concentrator 

I) Page 5 of the RACT Evaluation Report identifies NOx RACT for haul truck tailpipe 

emissions as "replace all trucks that are older than 14 years with trucks that have the highest 

tier rating available and that in the future as trucks are replaced, the replacements use the 

highest tier engine available." The Report explains that the higher tier engines have lower 

NOx emissions in grams per horsepower-hour. However, draft SIP subsection IX.H.l2.l. does 

not propose any such requirement. Instead, the only proposed requirement pertaining 

specifically to haul trucks is a limit of 30,000 miles of haul truck use per calendar day. This 

choice of a truck mileage limit as a representation of RACT is not reflected in the RACT 

Evaluation Report. Please explain why the proposed RACT requirement pertaining to the 

haul trucks does not resemble the discussion in the RACT Evaluation Report. 

2) The RACT Summary Table indicates that higher tier engines will be used in haul trucks for 

NOx control by 2019 and credits Kennecott with a 64.7 tpy NOx reduction. For additional 

reductions such as this to be creditable in the attainment demonstration, a requirement to 

achieve such reductions needs to be reflected in the SIP. Please explain why this was not 

done. Please also explain why an earlier date would not be achievable. Page 5 of the RACT 

Evaluation Report says that if the four tier 1 trucks that are older than 2005 were replaced 

now, that would reduce the emissions by 64.7 tpy. Page 9 of the Report says that "Requiring 

KUC to replace the model year 2004 haul trucks with trucks that have the highest tier rating 

available will reduce NOx emissions by a minimum of64.7 tpy. This will begin in 2018 with 

complete reduction by 2018. In 2019 the six 2005 model year trucks will begin replacement 

by 2019 but the replacement will not be complete until the end of 2019." Please explain why 

the 64.7 tpy emission reduction in the RACT Summary Table is not proposed to occur until 

2019. From the RACT Evaluation Report, it appears that reductions beyond the 64.7 tpy 

reduction cited in the RACT Summary Table might occur by 2019. 

3) Draft SIP subsection IX.H.12.l. proposes to limit sourcewide emissions to 6,205 tons per 

rolling 12-month period, for NOx, PM2.s and S02 combined, until January 1, 2019. After that 

date, sourcewide emissions are proposed to be limited to 5,585 tons per rolling 12-month 

period. No rolling 12-month emission limits are proposed in the RACT Evaluation Report. 

Please explain how rolling 12-month limits can represent RACT in a plan that is intended to 

attain a 24-hour NAAQS. Please also explain how these proposed limits were calculated and 

whether they have any relationship to the proposed mileage limit of 30,000 miles per day of 

haul truck use. 

27 
4) The provisions in the draft SIP are not adequate to ensure the enforceability of the specified 

measures. For example, the draft does not specify means to determine compliance with the 

30,000 mile calendar day limit. Regarding the source-wide combined NOx, PM2.5 and S02 

limits, the draft SIP states that compliance will be determined "per methodology outlined in 

the Emission Inventory." It is unclear what this means, and it is not sufficient to ensure the 

limits could be enforced, even assuming a 12-month averaging period would be sufficient. 

5) We are also concerned with the specification of a combined limit for the three pollutants and 

require an explanation how this is sufficient given the differing impacts of the three 

pollutants on ambient PM2.s levels. 

6) The provisions to address fugitive dust are vague and practically unenforceable. What does 

the phrase "as conditions warrant" mean? The draft language does not explain. Greater 

specificity is needed. What is "the pit influence boundary?" The draft language does not 

define this phrase. What does it mean to require, as one possible measure, "ensure the surface 

of the active haul roads located within the pit influence boundary consists of ... chemical 

dust suppressant?" Isn't chemical dust suppressant something applied to the surface of the 

haul roads? What does the phrase "shall be the primary means" mean? Is it possible to 

specify that the ore conveyors shall be used to transport all crushed ore from the mine to the 

concentrator? Or at least some minimum percentage on a daily basis? Please explain why 

twice per year application of chemical dust suppressant to active haul roads outside of the pit 

influence boundary is adequate. Assuming there is an air quality benefit to the use of graders, 

the draft SIP needs to specify the required frequency of grading. 

n) Kennecott- Power Plant, Tailings Impoundment, Bonneville Borrow Plant and Laboratory 

1) Page 4 of the RACT Evaluation Report says a RACT analysis was not performed on existing 

main boilers 1, 2 and 3 at the Power Plant, because they are being replaced by a Unit 5 

combustion turbine and will not be in operation after 2016. However, draft SIP subsection 

IX.H.12.m. says that boilers 1, 2 and 3 shall not be operated after January 1, 2018, or upon 

commencing operation of Unit 5, whichever is sooner. This implies that boilers 1, 2 and 3 are 

allowed to operate until possibly 2018. Draft SIP subsection IX.H.12.m. does not specify any 

emission limits for boilers 1, 2 and 3. Please explain why emission limits for boilers 1, 2 and 

3 are not proposed to be retained until2018 as RACT. As we explained in the General 

Comments above, for an approvable attainment demonstration, the state needs to identify the 

existing local measures in the area that contribute to attainment of the NAAQS in that area, 

so that EPA can approve those measures specifically as RACT. 

2) Draft SIP subsection IX.H.12.m. says the NOx and VOC emission limits for Unit #5 at the 

Power Plant (combined cycle combustion turbine) apply "under steady state operation." No 

limits are listed for any other periods of operation. As we have noted in our comments above 

on SIP subsection IX.H.11.d, this is inconsistent with CAA requirements that SIP emission 

limits apply at all times, including periods of startup, shutdown, and malfunction (SSM). We 

have similar concerns regarding the language that appears twice that reads, "The limited use 

of natural gas during startup, for maintenance firings and break-in firing does not constitute 

steady-state operation and does not require stack testing." 

28 
3) Draft SIP subsection IX.H.12.m. does not indicate any stack test methods or other means 

(e.g., CEMS) for demonstrating compliance with any of the proposed emission limits at the 

Power Plant, nor are any averaging times indicated for the emission limits. Draft SIP 

subsection IX.H.11.e. should be cross-referenced for stack test methods, as was done for 

other sources (e.g., Central Valley Water Reclamation; Chemical Lime), and averaging times 

indicated for the emission limits. For CEMSs, appropriate requirements should be specified. 

In particular, we do not understand why NOx CEMS is not required. Please explain. 

4) Stack testing for Unit #5 (combustion turbine) is proposed to be required once every three 

years. We are concerned with stack test frequencies longer than one year. Please explain why 

this test frequency is sufficient to ensure continuous compliance with the limits. 

5) Page 7 of the RACT Evaluation Report identifies NOx RACT for boiler 4 as installation of 

LNB with OF A and SCR. The RACT Summary Table indicates that these controls will be 

installed by 2019, with an expected NOx reduction of 170 tpy. Please explain why an earlier 

date would not be achievable. Please also explain why draft SIP subsection IX.H.12.m. does 

not include a requirement to install these controls. The subsection does indicate that the NOx 

emission limit for boiler 4 changes from 336 ppmdv to 60 ppmdv on January 1, 2018, but it 

is not clear that this can be treated as an enforceable requirement to install new controls. 

6) Draft SIP subsection IX.H.12.m.i.D proposes to restrict fuel to natural gas during winter 

months (November through February) for boiler #4, with coal allowed the rest of the year. 

EPA is evaluating whether proposals to apply requirements on a seasonal basis are an 

acceptable approach to address PM2.s under the CAA. Also, during the winter months, the 

draft SIP proposes to allow Unit #4 to burn coal during natural gas curtailments, plus 

sufficient time to empty the coal bins following the curtailment. Was any coal usage modeled 

in the attainment demonstration? If not, then we would be concerned with allowing the 

burning of coal until the coal bins are empty. 

7) The RACT Evaluation Report identifies this source as consisting of not only the Power Plant, 

but also the Tailings Impoundment, Bonneville Borrow Plant (BBP) and Laboratory. For the 

Tailings Impoundment, page 9 of the Report identifies RACT as water spray/wet 

suppression, polymer application, and revegetation. These are all existing practices. Draft 

SIP subsection IX.H.12.m., however, contains no requirements for dust control at the 

Tailings Impoundment. As we explained in the General Comments above, for an approvable 

attainment demonstration, the state needs to identify the existing local measures in the area 

that contribute to attainment of the NAAQS in that area, so that EPA can approve those 

measures specifically as RACT. 

For the BBP, page 9 of the RACT Evaluation Report says RACT has not yet been identified 

because the BBP has not yet started operation. However, draft SIP subsection IX.H.12.m. 

proposes as RACT a limit of 12,500 miles per day of haul truck use. Please explain how this 

was determined to be RACT. Also, the draft SIP needs to specify a means to determine 

compliance with the mileage limit. 

8) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31 , 2013 indicates that projected actuals were used for modeling. We do not 

29 
know if the projected actuals take into account the expected shutdown of boilers 1, 2 and 3, 

and replacement with a combustion turbine. There is also no information on what the 

allowable emissions will be, on a plantwide daily basis, after RACT is applied. Our objective 

here is to see if there is a substantial difference between the proposed allowable emissions 

and the emissions used for modeling. 

o) Kennecott- Smelter, Refinery and Molybdenum Autoclave Processing Plant 

1) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31, 2013 indicates that projected actuals were used for modeling. The RACT 

Evaluation Report does not indicate what the actual emissions are on a plantwide daily basis. 

There is also no information on what the allowable emissions will be, on a plantwide daily 

basis, after RACT is applied. Our objective here is to see if there is a substantial difference 

between the proposed allowable emissions and the emissions used for modeling. 

2) Draft SIP subsection IX.H.12.n. proposes emission limits in pounds per hour for the Main 

Smelter Stack and for the Refinery boilers and Combined Heat Plant. The RACT Evaluation 

Report does not give any indication what emission limits in lblhr might represent RACT. 

Please explain how the proposed emission limits in lb/hr were calculated and determined to 

represent RACT. 

3) Draft SIP subsection IX.H.12.n. does not specify any stack test methods. Draft SIP 

subsection IX.H.11.e. should be cross-referenced for stack test methods, as was done for 

other sources (e.g., Central Valley Water Reclamation; Chemical Lime), and an averaging 

time specified for the NOx emission limits at the Refinery. 

4) Draft SIP subsection IX.H.12.n.i.A.I.3. proposes a NOx emission limit for the Main Stack on 

an annual average. Please explain how an annual average can represent RACT in a plan that 

is intended to attain a 24-hour NAAQS. 

5) Draft SIP subsection IX.H.12.n.i.A.III.l. proposes NOx RACT allowable emission limits for 

the Holman Boiler on a 30-day average. Please explain how 30-day averages can represent 

RACT in a plan that is intended to attain a 24-hour NAAQS. 

6) Draft SIP subsection IX.H.12.n.i.B.III, on monitoring ofNOx emissions at the Holman 

Boiler, requires "CEMS or alternate method determined according to applicable NSPS 

standards." Why is the language about an alternate method necessary? Hasn't the monitoring 

method already been established? Why would it change? 

7) For the Tankhouse Boilers, draft SIP subsection IX.H.l2.n.ii.B. states, "compliance with the 

emission limitation by the second boiler shall be determined by the stack test of the first 

boiler." We question whether that's acceptable, regardless of whether the two boilers are 

identical in make, model, and pollution control equipment. What about the proper operation 

and maintenance of the boilers and control equipment? 

30 
Also, stack testing for the Tankhouse Boilers at the Refinery is proposed to be required once 

every three years. We are concerned with stack test frequencies longer than one year. Please 

explain why this test frequency is sufficient to ensure continuous compliance with the limits. 

8) Draft SIP subsection IX.H.12.n.ii.C. allows for use of#2 fuel oil during testing and 

maintenance periods at the Tankhouse Boilers. No limit is placed on the duration of these 

periods. If the emissions associated with such fuel use have not been modeled in the 

attainment demonstration, then we would be concerned with such use. 

9) Draft SIP subsection IX.H.12.n.iii. needs to define the terms "MAP" and "TEO." 

p) Nucor Steel 

1) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31, 2013 indicates that projected actual emissions were used as the basis for 

modeled emissions. The RACT Evaluation Report provides some information on 2008 actual 

annual emissions for portions of the plant, but we are unable to determine what the emissions 

were for the overall plant on a daily basis. Also, we are unable to determine from draft SIP 

subsection IX.H.12.o. how much emissions are proposed to be allowed for the overall plant 

on a daily basis. Our objective here is to see if there is a substantial difference between the 

proposed allowable emissions and the emissions used for modeling. 

2) Page 8 of the RACT Evaluation Report says that "Based on the consent decree, Reheat 

furnace #1 and Reheat furnace #2 constitute RACT." Please be aware that there is no 

provision in the Clean Air Act for consent decrees to constitute RACT. Since the consent 

decree apparently required a "thorough evaluation of possible NOx controls for reheat 

furnaces," then that evaluation should be presented in the RACT Evaluation Report, or at 

least a summary of that evaluation, rather than just a statement about EPA's conclusion ofthe 

study. EPA made no conclusion from the study that constituted RACT. The RACT 

Evaluation Report does not explain what possible NOx controls were considered, nor why 

0.07 lb/MMBtu should constitute NOx RACT for new reheat furnaces, nor why 0.09 

lb/MMBtu should constitute NOx RACT for retrofit furnaces. 

3) Draft SIP subsection IX.H.12.o. proposes a NOx emission limit for the Electric Arc Furnace 

(EAF) Baghouse of "59.75 lbs/hr (12-month rolling average)." Please explain how a 12-

month rolling average can represent RACT in a plan that is intended to attain a 24-hour 

NAAQS. 

4) Draft SIP subsection IX.H.12.o. does not specify an averaging time or a stack test method for 

the proposed NOx emission limits at Reheat Furnaces #1 and #2, nor for the proposed VOC 

emission limit at the EAF Baghouse. Draft SIP subsection IX.H.11 .e. should be crossreferenced for stack test methods, as was done for other sources (e.g., Central Valley Water 

Reclamation; Chemical Lime), and an averaging time specified for the emission limits. 

5) Stack testing at the EAF Baghouse for VOC is proposed to be required once every five years 

and stack testing at the Reheat Furnaces for NOx is proposed to be required once every three 

31 
years. We are concerned with stack test frequencies longer than one year. Please explain why 

these test frequencies are sufficient to ensure continuous compliance with the limits. 

q) Olympia Sales 

1) With regard to PM2.s control, page 5 of the RACT Evaluation Report indicates that Olympia 

Sales plans to install, within the next year, a baghouse for PM control from the woodworking 

shop, to replace the existing cyclones. Page 8 identifies RACT for PM2.

5 as installation of the 

baghouse. The RACT Summary Table indicates that the expected emission reduction due to 

baghouse installation will be 7.5 tpy for PM10 and 4.4 tpy for PM2.5. The only proposed 

RACT requirement in draft SIP subsection IX.H.12.p., however, is installation and operation 

ofthe baghouse by January 1, 2015. No emission allowable is proposed for PM2.s. If 

Olympia Sales is being credited with an emission reduction due to installation of a new 

baghouse, then this needs to be reflected as proposed RACT in the SIP with a proposed 

emission limit for PM2.s. 

2) With regard to VOC control, page 7 of the RACT Evaluation Report indicates that recent 

revisions to the wood furniture MACT will require Olympia Sales to cut the amount of VOC 

in their topcoats and sealers almost in half by January of 2015. Page 8 identifies RACT for 

VOC as continued research and implementation on the use of low VOC coating and waterbased coatings. The current NSR permit (Approval Order) dated April 13 , 1995, requires use 

of High Volume Low Pressure (HVLP) spray guns for all painting processes. However, draft 

SIP subsection IX.H.12.p. does not propose any RACT requirements for VOC. Please 

explain why this is not included. 

3) Page 1 of the RACT Evaluation Report indicates that the plant's assumed operation will be 

similar to that of the past five years. Page 2 indicates that 2008 actual emissions were 4.28 

tons for PM2.5 and 20.88 tons for VOC. The table provided to us on October 31 , 201'3 

indicates that the emissions used for NAAQS attainment modeling were 0.0279 tpy for PM2.5 

and 15.66 tpy for VOC. Please explain whether the expected installation of a baghouse 

accounts for the PM2.5 reduction from 2008 actual emissions and whether compliance with 

MACT accounts for the VOC reduction from 2008 actual emissions. If Olympia Sales is 

being credited with a VOC reduction due to MACT compliance, then this needs to be 

reflected in proposed RACT requirements in draft SIP subsection IX.H.12.p. Similarly, as we 

stated above, if Olympia Sales is being credited with a PM2.s emission reduction, then this 

needs to be reflected in terms of a proposed PM2.5 emission limit for the new baghouse. 

4) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31, 2013 lists emission figures in tons/year that were used for modeling. The 

basis for these figures (e.g., projected actuals, proposed allowables, 90% of PTE, or possibly 

something else) is not indicated. Our objective here is to see ifthere is a substantial 

difference between the proposed allowable emissions and the emissions used for modeling. 

r) Pacificorp Gadsby 

1) Page 9 of the RACT Evaluation Report says, "The summary of all the above RACT 

evaluations is that PacifiCorp will extend the SCR catalyst beds on each of the three 

32 
combustion turbines at the Gadsby facility. This will increase the amount of catalyst and 

slightly reduce NOx emissions. Total NOx is expected to drop by 10.7 tons of actual 

emissions by the 2017 projection year. " The RACT Summary Table indicates that Gadsby is 

being credited with a 10.7 tpy NOx emission reduction due to expansion of the SCR catalyst 

beds. However, draft SIP subsection IX.H.12.q. does not reflect this. The proposed RACT 

emission limits for NOx for the turbines (5 ppmdv and 22.2lblhr at each turbine) are the 

emission limits that are already in effect. There is no requirement to expand the SCR catalyst 

beds. If Gadsby is being credited with a NOx emission reduction resulting from expansion of 

the catalyst beds, then this needs to be reflected as proposed RACT in the SIP. 

2) The RACT Summary Table indicates that SCR catalyst beds will be expanded for NOx 

control at the natural gas fired turbines by 2017. Please explain why an earlier date would not 

be achievable. 

3) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31 , 2013 indicates that projected actual emissions were used as the basis for 

modeled emissions. Pages 2 and 6 of the RACT Evaluation Report indicate that actual NOx 

emissions in 2008 were 154.2 tons at the boilers and 29.6 tons at the combustion turbines, for 

a plantwide total of 183.8 tons. We expect that projected actuals would be slightly higher. 

However, we are unable to determine what the proposed RACT allowables equate to in tons 

per year, for the overall plant. Draft SIP subsection IX.H.12.q. proposes NOx emission limits 

of 336 ppmdv at each of the three boilers and 22.2 lblhr for the three turbines combined. The 

equivalent annual allowable for the turbines is 97.2 tons, which is 3.3 times as much as the 

2008 actual emissions. Please explain what the equivalent annual allowable is for the boilers. 

Our objective here is to see if there is a substantial difference between the proposed RACT 

allowable and the emissions used for modeling. For the turbines at least, there does appear to 

be a substantial difference, which causes us concern. See our General Comment # 1. 

4) Draft SIP subsection IX.H.12.q. proposes RACT allowables for the turbines on a 30-day 

rolling average. Please explain how 30-day rolling averages can represent RACT in a plan 

that is intended to attain a 24-hour NAAQS. 

5) Draft SIP subsection IX.H.12.q uses the word "permittee" several times. We suggest using 

"owner/operator" or "Pacificorp" instead. 

s) Tesoro Refining & Marketing Company - Salt Lake City Refinery 

1) Page 14 of the RACT Evaluation Report proposes no changes to existing wastewater 

operations as VOC RACT for wastewater separators and drains. One option is presented as 

technically feasible (ensuring all drains are covered and routing the API separator vent gas to 

a control device for thermal combustion or oxidation), with potential 70% VOC control, but 

was not selected as RACT. One other area refinery (Chevron), however, operates a 

regenerative thermal oxidizer system in conjunction with covers and vent routing. Page 14 of 

the RACT Evaluation Report for Tesoro estimates VOC emission reductions as high as 11 

tpy if a similar system were employed at Tesoro, but does not propose such a system, instead 

stating only that "further discussions on controlling wastewater VOC emissions need to be 

33 
held." Since it is proven to be technically and economically feasible at another area refinery, 

why is it not proposed here? Please explain. 

2) There are a number of instances where new controls are identified as RACT in the RACT 

Evaluation Report, and are credited with emission reductions in the RACT Summary Table, 

but are not required in draft SIP subsection IX.H.12.r: 

i) Page 5 of the RACT Evaluation Report identifies RACT for S02 at the FCCU as 

installation of WGS. The Report says a reduction of 585 tpy for S02 is expected. This 

expected reduction is also cited in the RACT Summary Table, to be achieved by 2019. 

ii) Page 6 of the RACT Evaluation Report identifies RACT for NOx at the FCCU as 

installation of WGS-LoTOx. The Report says a NOx reduction of 106 tpy is expected. 

This expected reduction is also cited in the RACT Summary Table, to be achieved by 

2019. 

iii) Page 8 of the RACT Evaluation Report identifies RACT for NOx at Process Heaters and 

Boilers as installation of ULNB on the heaters on the Ultraformer Furnace F -1. The 

Report says a NOx reduction of 17 tpy is expected. This expected reduction is also cited 

in the RACT Summary Table, to be achieved by 2017. 

Draft SIP subsection IX.H.l2.r. specifies the calculations to be used for demonstrating 

compliance with sourcewide S02 and NOx emission limits, but it is not apparent whether 

any of these calculations take into account any requirement to install and use new 

emission controls. Please explain. IfTesoro is being credited with emission reductions 

due to installation of new controls as RACT, then this needs to be reflected as proposed 

RACT in the SIP. 

3) Under "Source-wide PM2.

5," draft SIP subsection IX.H.12.r.i. reads, "Filterable PM2.s 

emissions shall be determined by applying various emission factors ... " This language is 

imprecise/vague. Please delete the word "various." 

4) In the same paragraph, the language reads, "Unless otherwise specified by an Approval 

Order ... " This is not approvable language. EPA needs to be able to approve any revisions to 

the methods for determining compliance, unless the SIP establishes enforceable, replicable 

procedures for modifying the methods. For example, where a revision to an emission factor is 

established through a simple stack test, we have been willing to approve SIP language that 

describes the process. The process should include notice to us of the stack test date, results, 

and new emission factor. 

5) In the next paragraph, the language reads, "Daily gas consumption by all boilers and furnaces 

shall be measured by meters that can delineate the flow of gas to the indicated emission 

points." The phrase "indicated emission points" is undefined. The SIP language needs to 

specify the emission points that are covered. 

6) In the next paragraph, the SIP language proposes to defer the establishment of a condensable 

ratio for FCCU wet gas scrubber stack and SRU/TGTU/TGI until "no later than January 1, 

2019." At that time a new source-wide limit for PM2.s will be established in an AO. This is 

34 
not approvable. There is no explanation why it would not be possible to establish the 

condensable ratio now, through testing, use of emission factors, or estimates. The SIP is 

supposed to evaluate RACT for condensable and filterable PM. The SIP cannot defer the 

establishment of limits. And the SIP must contain the RACT limits, not an AO. 

7) Source-wide S02 provisions: There is no requirement for S02 CEMS or any other technique 

for accounting for SRU emissions. It is our understanding that the SRU at each refinery has 

an S02 CEMS, which we would expect to be used to account for a portion of source-wide 

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

requires use of SOz CEMS in determining S02 emissions from the SRU. Please explain why 

this is not accounted for at Tesoro. 

8) The RACT Evaluation Report does not identify any level of control efficiency as RACT for 

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

IX.H.11. or IX.H.12.r. We consider it essential to specify a level of control efficiency as 

RACT and would expect 95% or better control. Please supplement the TSD with a discussion 

of what level of control should be expected for the SRU at Tesoro and include that level of 

control in draft SIP subsection IX.H.11 or IX.H.12.r. 

9) Draft SIP subsection IX.H.12.r relies on NOx CEMS at the FCCU wet gas scrubber, and on 

H2S CEMS for plant fuel gas as an alternative to direct S02 measurement, to determine some 

of the emissions and emission factors, but this subsection of the draft SIP doesn't clearly 

require the operation of CEMS. This does not appear to be addressed by the General . 

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

related comment on IX.H.11.g. 

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

be addressed. 

t) Proctor & Gamble Paper Products 

1) Page 9 ofthe RACT Evaluation Report identifies low-NOx burners and good combustion 

practices as RACT for the paper machine dryer burners. Draft SIP subsection IX.H.12.s., 

however, does not propose any NOx emission limits as RACT for the paper machine dryer 

burners. The current NSR permit (Approval Order), dated August 2, 2013, includes NOx 

emission limits for the paper machine process stacks of0.09lb/MMBtu and 13.50 lb/hr. 

Please explain why the NOx limits in the current NSR permit are not included as RACT 

emission limits. 

2) Draft SIP subsection IX.H.12.s. indicates that a PM2.5 RACT emission limit is "to be 

determined" for the Paper Machine Process Stacks, following stack testing that is proposed to 

be required by January 1, 2015, to "establish the ratio of condensable PM2.5." The SIP 

subsection indicates that a PMz.s limit will then be established in the Approval Order. This is 

not approvable. RACT needs to be included in the SIP (including condensable PM2.s), not 

determined at a future date or specified in an AO. 

3) Page 3 of the revised TechLaw RACT Evaluation Report indicates that there are three diesel 

tanks at Proctor & Gamble which emit a total of over 150 tpy ofVOCs. TechLaw 

35 
recommends a RACT evaluation for these tanks. Please explain why the state's own RACT 

Evaluation Report does not include any such evaluation. 

4) Stack testing is proposed to be required once every five years. We are concerned with stack 

test frequencies longer than one year. Please explain why this test frequency is sufficient to 

ensure continuous compliance with the limits. 

u) University ofUtah 

1) The table provided to us on October 31 , 2013 indicates that the emissions used for NAAQS 

attainment modeling were projected actual emissions. It is not clear what this means, 

considering that the following changes at the University have occurred, or will occur, after 

the 2008 emission baseline year, as outlined in the RACT Evaluation Report: 

Lower campus heating plant (Building 303): 

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

operating 

• Boiler 5 (105 MMBtu!hr) was shut down by 2012 and is being replaced by two 40 

MMBtu!hr boilers, expected to be operational by 2017; net expected Ox reduction is 

13.15 tpy. 

• Boiler 4 (105 MMBtu!hr) will be decommissioned by 2016 and replaced by two 

40 MMBtu/hr boilers, expected to be operational by 20 19; net expected NOx reduction is 

13.15 tpy. 

• Boiler 3 (105 MMBtu!hr) will be decommissioned by 2018 and replaced by two 40 

MMBtu!hr boilers, expected to be operational by 2021 ; net expected NOx reduction is 

13.15 tpy. 

Upper campus heating plant (Building 302): 

• Boiler 4 (87.5 MMBtu/hr) received an upgraded burner management system in 2012; 

estimated NOx reduction was 6.04 tpy. 

• Boilers 1 and 3 (87.5 MMBtu!hr each) will each receive an upgraded burner 

management system by 2016; expected NOx reduction is 6.04 tpy at each boiler. 

Please explain whether the projected actual emissions take all this into account and how the 

projected actual emissions were calculated, on a daily basis. Please also explain what the 

allowed emissions are for the same time period, on a daily basis. Our objective here is to see 

if there is a substantial difference between the proposed allowable emissions and the 

emissions used for modeling. 

2) The only proposed RACT emission limits in draft SIP subsection IX.H.l2.t. are for the lower 

campus heating plant: 

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

• 9 ppmdv for the cogen turbine when it is operating alone, or 15 ppmdv when it is 

operating with the WHRU duct burner 

• 187 ppmdv for boiler 3 (because it will not be replaced until 2021) 

There are no proposed RACT emission limits or emission control requirements for the 

boilers at the upper campus heating plant, even though the RACT Evaluation Report 

identifies RACT for NOx at the upper campus boilers to be an upgraded burner management 

system ("02 trim technology"). The RACT Summary Table identifies 0 2 trim technology as 

RACT for NOx at the upper campus heating plant and indicates that the upper campus plant 

is being credited with 12.07 tpy ofNOx reduction as a result. If the University is being 

credited with an emission reduction due to new controls, then this needs to be reflected as 

proposed RACT in the SIP, with a requirement to install such a system by a specific 

deadline. 

As stated in our General Comment #3, ifRACT consists of existing controls, the state needs 

to identify the existing local measures in the area that contribute to attainment of the NAAQS 

in that area, so that EPA can approve those measures specifically as RACT. 

3) The RACT Summary Table indicates that one (or more) boilers at the lower campus heating 

plant will be replaced for PM, S02, NOx and VOC control by 2017. The Table also indicates 

that 0 2 trim technology will be installed for NOx control at the upper campus heating plant 

units 1 & 3 by 2015 . Please explain why earlier dates would not be achievable. 

Similarly, the draft SIP specifies dates in 2017, 2018 and 2019 for initial stack tests for 

various boilers and for Boiler #3 to convert to backup/peaking status. Please explain why 

earlier dates would not be achievable. 

4) No NOx test method is specified in draft SIP subsection IX.H.12.t. Draft SIP subsection 

IX.H.11.e. should be cross-referenced for stack test methods, as was done for other sources 

(e.g., Central Valley Water Reclamation; Chemical Lime). 

5) Stack testing is proposed to be required once every three years at the boilers for NOx. We are 

concerned with stack test frequencies longer than one year. Please explain why this test 

frequency is sufficient to ensure continuous compliance with the limits. 

v) Vulcraft!Nucor Building Systems 

1) The table provided to EPA on October 31, 2013 indicates that NAAQS attainment modeling 

was based on emissions that are "90% of PTE" and that the proposed RACT allowable 

emissions are also "90% of PTE." Draft SIP subsection IX.H.12.u. lists a proposed RACT 

emission allowable for VOC of 305.07 tons per rolling 12-month period. We note that this is 

90% of the allowable in the current NSR permit (Approval Order), which is 338.97 tons per 

rolling 12-month period. Please explain how it was determined that application oflow-VOC 

paint results in a calculation of305.07 tons ofVOC per rolling 12-month period as RACT. 

This is not explained in the RACT Evaluation Report. Please also explain how a rolling 12-

37 
month emission limit can represent RACT in a plan that is intended to attain a 24-hour 

NAAQS. 

2) Page 6 ofthe RACT Evaluation Report says R307-350 requires the use oflow-VOC paint 

and identifies the requirement as RACT. The Report says the requirement under R307-350 is 

to use paint at Vulcraft with less than 2.8 lbs/gallon VOCs, and to use paint at Nucor 

Building Systems with less than 2.3 lbs/gallon VOC, unless the products are air-dried, in 

which case less than 2.8 lbs/gallon must be used. However, draft SIP subsection IX.H.12.u. 

says only that R307-350 applies to Vulcraft. Please explain why the specific limits in R307-

350 are not cited as RACT in draft SIP subsection IX.H.12.u. 

3) Page 5 of the RACT Evaluation Report says "It is not technically feasible to construct a 

collection system at every degreaser" to capture and control VOCs. No analysis was provided 

to support this conclusion. Facilities frequently do install such collection systems. Please 

explain further. 

4) The draft SIP needs to specify a means to determine compliance with the emission limit. 

w) Wasatch Integrated Waste Management 

1) Draft SIP subsection IX.H.l2.v. requires SNCR to be installed and operating for NOx control 

by January 1, 2019. Please explain why an earlier date would not be achievable. 

2) Draft SIP subsection IX.H.l2.v. specifies a NOx emission limit of350 ppmdv, but does not 

say whether the limit is already in effect, or is intended to go into effect after installation of 

SNCR. The current NSR permit (Approval Order) dated October 22, 2007, already specifies 

350 ppmdv, therefore it appears to us that subsection IX.H.12.v. needs to specify what new 

NOx limit will go into effect after installation of SNCR, along with a deadline for initial 

compliance testing and a test method. 

3) Draft SIP subsection IX.H.l2. v. says compliance shall be determined by CEMS. If a NOx 

CEMS is not already installed and certified, then a deadline should be specified by which it 

must be certified. Also, the draft SIP subsection doesn't clearly require the operation of 

CEMS. This does not appear to be addressed by the General Requirements at draft SIP 

subsection IX.H.ll. Requirements to operate and maintain CEMS should be included in 

IX.H.11 or in IX.H.l2.v. 

4) Page 1 of the RACT Evaluation Report indicates that 40 CFR 60, subpart BBBB (emission 

guidelines for small municipal waste combustors) applies to this source, but does not identify 

it as RACT. Subpart BBBB contains numerous requirements for emission control. Please 

explain why the requirements that affect control of PM2.5, S02, NO~ and VOC should not be 

considered part of RACT and incorporated as requirements in draft SIP subsection 

IX.H.l2.v., along with a requirement to continue operating and maintaining the existing 

emission control equipment for these pollutants. As we explained in the General Comments 

above, for an approvable attainment demonstration, the state needs to identify the existing 

local measures in the area that contribute to attainment of the NAAQS in that area, so that 

EPA can approve those measures specifically as RACT. 

38 
5) Page 5 of the RACT Evaluation Report indicates that RACT for PM2.5, VOC and NOx 

includes replacement of the emergency diesel generator with a Tier 4 generator upon 

equipment replacement, but says there is no timeline established for this replacement at this 

time. Draft SIP subsection IX.H.12.v. says nothing about replacing this generator. Please 

explain why the state considers this to be RACT when there is no timeline and no mention of 

it as a requirement in the draft SIP subsection. 

6) Page 5 of the RACT Evaluation Report also indicates that RACT includes the requirements 

for municipal solid waste landfills at 40 CFR 63, subpart AAAA. However, no specific 

requirements are cited and draft SIP subsection IX.H.12.v. does not include any requirement 

to comply with 40 CFR 63 subpart AAAA. Please explain whether the state considers the 

landfill to be part of this source for purposes of the PM2.s SIP, and if so, whether the state 

considers the landfill rule to be part ofRACT. We note that the current NSR permit includes 

the landfill. 

x) Brigham Young University- Main Campus 

1) The current NSR permit (Approval Order) dated June 19, 2012, specifies NOx emission 

limits of95 ppmdv at Boiler #1 and 127 ppmdv at Boilers #4 and #6. The RACT Evaluation 

Report explains that Boiler #1 is utilized as a standby heat source and was not included in the 

RACT analysis. Boilers #2, #3 and #5 are coal-fired but are prohibited from burning coal in 

winter months, therefore were also not included in the RACT analysis. We think all ofthese 

units should be assessed for RACT. For example, if Boilers #2, #3 and #5 are capable of 

burning natural gas, the RACT analysis should address potential control technologies and 

limits for that fuel. 

2) Draft SIP subsection IX.H.13.a. proposes a NOx RACT limit of30 ppmdv for Boilers #1, #4 

and #6, with compliance testing required at #4 and #6 by January 1, 2017. We assume this 

means that LNB + FGR is expected to be able to achieve 30 ppmdv. Boiler #1 is only 

required to be retrofitted with LNB + FGR, and then tested, if it operates more than 300 

hours per rolling 12-month period. All six boilers are restricted to natural gas as fuel from 

November 1 to February 28. No emission limits are specified prior to January 1, 2017. 

Assuming that EPA concludes that seasonal controls are creditable in the attainment 

demonstration, and that the proposed limits and deadlines are consistent with CAA 

requirements, the SIP must nonetheless include the existing emission limits (cited above) for 

Boilers #1, #4 and #6, and indicate that these limits remain in effect until the new limits take 

effect on January 1, 2017. The SIP must also specify provisions sufficient to determine 

compliance with the limits. 

3) As mentioned above, draft SIP subsection IX.H.13.a. says Boiler #1 may be operated for up 

to 300 hours per rolling 12-month period without triggering the need to comply with the 30 

ppm emission limit that represents RACT (i.e., LNB + FGR). What is the impact if those 300 

hours occur during a PM2.s episode? How did the state model Boiler #1? 

Again, we caution that EPA is still evaluating whether seasonal controls are an acceptable 

approach to address PM2.s under the CAA; in other words, EPA must determine whether a 

seasonal restriction on coal burning, or seasonal limits, are creditable in the state's attainment 

demonstration. 

39 
4) Pages 2 and 5 of the Report identify NOx RACT for Boilers #4 and #6 as replacement of the 

burner spud tips and adding 18% FGR (Flue Gas Recirculation). The RACT Summary Table 

refers to this as LNB + FGR and indicates this is expected to yield 11.1 tpy ofNOx reduction. 

The RACT Summary Table indicates that LNB and FGR will be installed at Boilers #4 and 

#6 by 2017. Please explain why an earlier date would not be achievable. 

5) Regarding Boilers #2, #3 and #5: Assuming that EPA concludes that seasonal controls are 

creditable in the attainment demonstration, and that the existing limits for these units are 

consistent with CAA requirements for RACT/RACM, the NOx emission limits for these 

boilers (331 ppmdv, listed in the current NSR permit) should be included as part of RACT in 

draft SIP subsection IX.H.13.a., along with provisions sufficient to determine compliance 

with the limits. It is not clear whether these units are capable of burning natural gas. This is 

relevant to the RACT analysis and should be explained. 

6) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31 , 2013 indicates that projected actual emissions were used as the basis for 

modeled emissions. The RACT Evaluation Report provides some information on 2008 

baseline actual emissions for portions of the plant, but we are unable to determine what the 

emissions were on a daily basis in winter months, for the boilers that have operated in winter. 

Also, we are unable to determine from draft SIP subsection IX.H.13 .a. how much emissions 

are proposed to be allowed on a daily basis during those months. Our objective here is to see 

ifthere is a substantial difference between the proposed allowable emissions and the 

emissions used for modeling. 

7) No NOx test method is specified in draft SIP subsection IX.H.13 .a. Draft SIP subsection 

IX.H.11.e. should be cross-referenced for stack test methods, as was done for other sources 

(e.g., Central Valley Water Reclamation; Chemical Lime). 

8) Two items should be clarified for the benefit of all readers: First, the SIP should specifically 

identify the number of central heating plant units and their names, instead of merely 

referencing " [a]ll central heating plant units." Second, the testing requirements for Unit #1 

are not clear. We suggest rephrasing the relevant part of the footnote to read," ... then, within 

18 months of exceeding 300 hours of operation, low NOx burners with Flue Gas 

Recirculation shall be installed and an initial stack test shall be performed to determine 

compliance with the emission limit in H.13 .a.ii.A above. A stack test shall be required every 

three years thereafter." 

9) Stack testing is proposed to be required at Units #4 and #6 once every three years. We are 

concerned with stack test frequencies longer than one year at these Units. Please explain why 

this test frequency is sufficient to ensure continuous compliance with the limits. 

y) Geneva Nitrogen 

1) Page 2 of the RACT Evaluation Report states, "The Prill Tower is a low density prill 

production unit with no emission control equipment. The uncontrolled prill tower is the 

major source of ammonium nitrate (NH4N03) particulate matter." Page 3 rejects a wet 

40 
scrubber as not economically feasible for PM10/PM2.5 control. Page 5 says RACT is 

represented by the following: "The Prill Tower shall continue to use pollution prevention 

measures of reducing microprill formation and reduce carryover of fines through 

entrainment." No such measures are proposed as RACT in draft SIP subsection IX.H.13. b. 

Page 28 of Geneva Nitrogen's own RACT analysis describes some pollution prevention 

measures that have already been accomplished during 1995 through 2012. Please explain 

whether the intent is to require Geneva Nitrogen to continue to look for additional pollution 

control measures, and if so, why this is not included as a requirement in draft SIP subsection 

IX.H.13.b. 

2) Please explain how the emissions used for NAAQS attainment modeling compare to the 

emissions that are proposed to be allowed, on a plantwide daily basis. The table provided to 

us on October 31, 2013 lists emission figures in tons/year that were used for modeling. The 

basis for these figures (e.g., projected actuals, proposed allowables, 90% of PTE, or possibly 

something else) is not indicated. Also, please provide information on what the proposed 

allowables equate to, in terms of plantwide emissions. Our objective here is to see if there is 

a substantial difference between the proposed allowable emissions and the emissions used for 

modeling. 

3) Please explain why condensable PM is not accounted for in the RACT Evaluation Report, 

nor in the proposed PM10 emission limit in draft SIP subsection IX.H.13.b. (which is 0.22 tpd 

at the Prill Tower). The draft SIP subsection does not indicate whether stack testing needs to 

include condensable PM. Please also explain why PM10 is specified rather than PM2.s· 

4) No stack test methods are specified in draft SIP subsection IX.H.l3.b. Draft SIP subsection 

IX.H.ll.e. should be cross-referenced for stack test methods, as was done for other sources 

(e.g., Central Valley Water Reclamation; Chemical Lime). 

5) There appear to be conflicting provisions for stack testing. Testing is specified in draft SIP 

subsection IX.H.l3.b.ii.A, in 13.b.v., and in 13.b.v.A.I. Subsection 13.b.ii.A says that 

emissions shall be tested every three years but does not indicate testing for which limit or 

when testing shall commence. Subsection 13.b.v. says compliance testing is required on the 

Prill Tower, Montecatini Plant, and Weatherly Plant, but says that testing shall be performed 

no later than January 1, 2019. Again, this subsection does not specify testing for which 

limits, and it is not clear how this dovetails with subsection 13.b.ii.A. 

Furthermore, we do not understand why it is appropriate to defer testing until January 1, 

2019. Subsection 13.b.v.A.I. indicates that stack testing for the NOx limits must occur every 

three years, but does not specify a date for the initial test. The SIP must clearly state a 

reasonable date by which stack testing must start, the frequency of testing after that, and the 

limits for which the testing is required. 

6) Draft SIP subsection IX.H.13.b.v.B appears to be a requirement derived from the 

Compliance Assurance Monitoring rule. The language raises several questions. First, since it 

requires use of a NOx CEMS, why should it not be used for determining emission 

compliance, rather than just a compliance "indicator"? Second, there's a lack of clarity- for 

which NOx emission limit(s) is this supposed to be used? Third, it says excursions trigger an 

41 
inspection, corrective action, and a reporting requirement. Inspection by whom? Corrective 

action by whom? What sort of report and to whom? This subsection should be clarified. 

z) Pacificorp - Lakeside Power Plant 

1) Page 5 of the RACT Evaluation Report identifies RACT for VOC as retention of the existing 

oxidation catalyst systems at Block #1 and Block #2, and indicates that Block #2 has a 

permitted VOC emission limit of2.8 ppmdv from each turbine/HRSO stack, on a 3-hour 

average. However, draft SIP subsection IX.H.13.c. does not include any proposed VOC 

emission limit or required controls for VOC at Block #1 or Block #2. Please explain why this 

is not included. 

2) Please explain how the emissions used for modeling for NAAQS attainment compare to the 

proposed allowable emissions. The table provided to us on October 31 , 2013 indicates that 

for Lakeside Block 1, modeling was based on projected actual emissions. For Block 2, 

modeling was based on 90% of PTE. The only RACT allowable proposed in draft SIP 

subsection IX.H.13.c is 2.0 ppmdv for each turbine/HRSO stack. Please explain what the 

equivalent plantwide emissions are in tons per day, and what emissions in tons per day were 

used for modeling. 

3) Draft SIP subsection IX.H.13 .c uses the word "permittee." We suggest using 

"owner/operator" or "Pacificorp" instead. 

aa) Pacific States Cast Iron Pipe Company (PSCIPCO) 

1) Draft SIP subsection IX.H.l3.d. indicates that low NOx burners (LNB) with flue gas 

recirculation (FOR) technology shall be required to be in operation on the Annealing Oven 

by January 1, 2017. This is identified as RACT on page 7 of the RACT Evaluation Report. It 

is not clear why page 6 of the Report indicates that the current NOx emission rate for the 

Annealing Oven at PSCIPCO (3 .98 lb/hr and 0.098 lb/MMBtu), without L Band FOR, is 

about the same as the emission rates for "annealing furnaces" at other facilities where LNB + 

FOR has already been installed (4.34 lb/hr and 0.095 lb/MMBtu). This would seem to imply 

that addition ofLNB + FOR at PSCIPCO would not get much NOx reduction, if any. 

However, the RACT Summary Table indicates an expected reduction at PSCIPCO of 11.9 

tpy ofNOx. Please explain how that amount of expected reduction was estimated. 

2) Draft SIP subsection IX.H.13.d. does not propose any NOx emission limit or minimum 

required NOx control efficiency at the Annealing Oven after installation of LNB + FOR. If 

the plant is being credited with a NOx emission reduction due to new controls (11.9 tpy, cited 

above), then this needs to be reflected in proposed RACT requirements for NOx in draft SIP 

subsection IX.H.13 .d., in terms of an emission limit or control efficiency, with appropriate 

testing requirements to determine compliance. 

3) Draft SIP subsection IX.H.13 .d. proposes to require installation of a 95% efficient thermal 

oxidizer by January 1, 2018, to control VOC emissions from Painting Operations. The RACT 

Summary Table proposes to credit the oxidizer with a 129.1 tpy VOC reduction. The draft 

SIP subsection indicates that compliance with the efficiency requirement shall be determined 

"using a method acceptable to the Director." This language is a form of director discretion 

42 
that undermines federal enforceability of the SIP. The language should be revised to specify 

a test method for VOC, or else subsection IX.H.11.e should be revised to specify a test 

method for VOC and this subsection would then cross-reference it. 

4) The RACT Summary Table indicates that LNB & FGR will be installed for NOx control at 

the Annealing Oven by 2017, and that thermal regenerative oxidation will be installed for 

VOC control at the Painting Operations by 2019. Please explain why earlier dates would not 

be achievable. 

5) Draft SIP subsection IX.H.l3.d. indicates that a VOC limit for the thermal oxidizer 

controlling the painting operations shall be established in the Approval Order (AO) by no 

later than January 1, 2019. As we have noted in other instances, this approach is not 

approvable. RACT limits need to be specified in the SIP, not determined at a future date or 

specified in an AO. 

6) The table provided to EPA on October 31, 2013 indicates that the emissions used for 

NAAQS attainment modeling were the 2008 actual emissions. The RACT Evaluation Report 

does not indicate what those emissions were for NOx and VOC (the pollutants emitted in 

greatest quantity from PSCIPCO). Please explain what the actual 2008 plantwide NOx and 

VOC emissions were, and what the allowed plantwide emissions are estimated to be after 

application ofRACT, on a daily basis. Our objective here is to see ifthere is a substantial 

difference between the proposed RACT allowable and the emissions used for modeling. 

bb) Payson City Power 

I) Page 2 of the RACT Evaluation Report indicates that 2008 actual NOx emissions, for all four 

IC engines combined, were 4.0 tons/year. From information elsewhere in the RACT 

Evaluation Report, it appears that this figure represents virtually all of the NOx emissions 

from Payson City Power in 2008. This figure is equivalent to average daily emissions of 

0.011 tons. We expect that the projected actual emissions would be only slightly higher. The 

table provided to us on October 31, 2013 indicates that the emissions used for NAAQS 

attainment modeling were the projected actual emissions. Draft SIP subsection IX.H.13.e. 

indicates that the proposed RACT allowable for NOx is 1.54 tpd and 268 tons per rolling 12-

month period, for all engines combined. Please explain how the projected actual emissions 

could be a valid basis for modeling, when the proposed allowable emissions are 140 times 

higher (1.54 tpd allowed versus 0.011 tpd actual). Please also explain how 1.54 tpd was 

calculated to be an appropriate RACT limit. No such explanation appears in the RACT 

Evaluation Report. 

2) The current NSR permit for Payson City Power, dated September of 1996, contains 

performance-based NOx emission limits, in grams per kilowatt-hour, for each of the four 

engines. Limits are 4.96 grams per kW-hr at two engines, 7.60 grams per kW-hr at the third 

engine, and 8.76 grams per kW-hr at the fourth engine. Please explain why these limits were 

not included in draft SIP subsection IX.H.l3 .e. as part of proposed RACT. 

3) Pages 5 and 7 of the RACT Evaluation Report appear to be taking credit for VOC reductions 

that may result from the requirements of 40 CFR 63 subpart ZZZZ, which will require the 

engines at Payson City Power to meet a CO emission limitation as a surrogate for HAP 

43 
emissions. The Report lists the reductions as occurring on the basis that "it is likely" that 

Payson City Power will be required to install oxidation catalyst controls. The RACT 

Summary Table projects a 1.4 tpy VOC reduction resulting from installation of oxidation 

catalyst by 2017. However, draft SIP subsection IX.H.13.e. does not include any proposed 

VOC allowable or requirement for VOC controls. If Payson City Power is being credited 

with a VOC emission reduction, either due to installation of new controls, or due to new 

requirements applicable to existing controls, then this needs to be reflected in proposed 

RACT requirements in the SIP. 

4) The RACT Summary Table indicates that oxidation catalyst for VOC control will be 

installed at the IC engines by 2017. Please explain why an earlier date would not be 

achievable. 

5) The draft SIP does not specify a requirement for stack testing or use of CEMS. It must do so. 

If stack testing will be used, the text should specify the method to be used (or cross-reference 

SIP subsection IX.H.ll.d), the initial test date, and the frequency of testing. Also, how will 

power production on a daily basis be determined? And what records must the 

owner/operator keep? 

6) The draft SIP should specifically identify the number and types of emitting units at Payson 

City Power, e.g. "Payson City Power has four dual-fuel internal combustion engines of 

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

cc) Provo City Power 

1) Page 2 of the RACT Evaluation Report indicates that 2008 actual NOx emissions, for all four 

IC engines combined, were 20.1 tons/year. From information elsewhere in the RACT 

Evaluation Report, it appears that this figure represents virtually all of the NOx emissions 

from Provo City Power in 2008. This figure is equivalent to average daily emissions of 0.055 

tons. We expect that the projected actual emissions would be only slightly higher. The table 

provided to us on October 31, 2013 indicates that the emissions used for NAAQS attainment 

modeling were the projected actual emissions. Draft SIP subsection IX.H.l3.f. indicates that 

the proposed RACT allowable for NOx is 2.45 tpd and 254 tons per rolling 12-month period 

for the overall plant. Please explain how the projected actual emissions could be a valid basis 

for modeling, when the proposed allowable emissions are at least 44 times higher (2.45 tpd 

allowed versus 0.055 tpd actual). Please also explain how 2.45 tpd was calculated to be an 

appropriate RACT limit. No such explanation appears in the RACT Evaluation Report. 

2) The current NSR permit for Provo City Power, dated December of 2004, contains 

performance-based NOx emission limits, in grams per kilowatt-hour and ppmdv, for each of 

the boilers and engines. The limits are 1.46 grams per kW-hr and 155 ppmdv at each oftwo 

boilers, and 10.4 gram,s per kW-hr and 1,660 ppmdv at each of four engines. Please explain 

why these emission limits, covering the main emitting units at the facility, were not included 

as part of RACT. 

3) Pages 5 and 10 of the RACT Evaluation Report appear to be taking credit for VOC 

reductions at the four IC engines that may result from the requirements of 40 CFR 63 subpart 

ZZZZ, which will require the engines at Provo City Power to meet a CO emission limitation 

44 
as a surrogate for HAP emissions. The Report lists the reductions as occurring in 2017 as a 

result of the addition of oxidation catalyst controls. The RACT Summary Table projects a 1.4 

tpy VOC reduction resulting from installation of oxidation catalyst by 2017. However, draft 

SIP subsection IX.H.13 .f. does not include any proposed VOC allowable or requirement for 

VOC controls. If Provo City Power is being credited with a VOC emission reduction, either 

due to installation of new controls, or due to new requirements applicable to existing 

controls, then this needs to be reflected in proposed RACT requirements in the SIP. 

4) The RACT Summary Table indicates that oxidation catalyst for VOC control will be 

installed at the IC engines by 2017. Please explain why an earlier date would not be 

achievable. 

5) Regarding compliance demonstration requirements: 

i) Stack testing is proposed to be required every 8,760 hours of operation and/or at least 

every five years. We are concerned with stack test frequencies longer than one year. 

Please explain why this test frequency is sufficient to ensure continuous compliance 

with the limits. 

ii) The text should specify the date for the initial stack test for each unit and the test 

method to be used (or cross-reference subsection IX.H.ll.d.). 

iii) Subsection IX.H.13.f.iii. should be clarified to say that stack testing is required every 

8.760 hours of operation or every five years, whichever occurs sooner. 

iv) It is not clear how power production will be determined or how 12-month rolling 

totals of power production would be adequate to determine compliance with a daily 

limit. 

v) The SIP needs to specify what records the owner/operator must keep. 

vi) The draft SIP should specifically identify the number and types of emitting units at 

Provo City Power, e.g. "Provo City Power has four dual-fuel internal combustion 

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

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

____ and have a generating capacity of " 

dd) Springville City Corporation- Whitehead Power Plant 

1) Page 2 of the RACT Evaluation Report indicates that 2008 actual NOx emissions, for all 

seven IC engines combined, were 0.1 tons/year. From information elsewhere in the RACT 

Evaluation Report, it appears that this figure represents virtually all ofthe NOx emissions 

from the plant in 2008. This figure is equivalent to average daily emissions of 0.00027 tons. 

We expect that the projected actual emissions would be only slightly higher. The table 

provided to us on October 31, 2013 indicates that the emissions used for NAAQS attainment 

modeling were the projected actual emissions. Draft SIP subsection IX.H.13.g. indicates that 

the proposed RACT allowable for NOx is 1.68 tpd and 248 tons per rolling 12-month period, 

for all engines combined. Please explain how the projected actual emissions could be a valid 

45 
basis for modeling, when the proposed allowable emissions are approximately six thousand 

times higher (1.68 tpd allowed versus 0.00027 tpd actual). Please also explain how 1.68 tpd 

was calculated to be an appropriate RACT limit. No such explanation appears in the RACT 

Evaluation Report. 

2) The current NSR permit, dated December of2003, contains performance-based NOx 

emission limits, in lb/hr and grams per kilowatt-hour for each of seven engines. Limits are 

27.00 lb/hr and 2.50 grams per kW-hr at the four Enterprise engines, and 24.00 lb/hr and 4.90 

grams per kW-hr at each of the three General Motors EMD engines. Please explain why 

these emission limits, covering the main emitting units at the facility, were not included as 

part ofRACT. 

3) Pages 4 and 10 of the RACT Evaluation Report appear to be taking credit for VOC 

reductions that may result from the requirements of 40 CFR 63 subpart ZZZZ, which will 

require the engines at the Whitehead power plant to meet a CO emission limitation as a 

surrogate for HAP emissions. The Report lists the reductions as occurring on the basis that " it 

is likely" that the plant will be required to install oxidation catalyst controls. However, draft 

SIP subsection IX.H.13.g. does not include any proposed VOC allowable or any proposed 

requirement for VOC controls. If the plant is being credited with a VOC emission reduction, 

either due to new controls, or due to new requirements applicable to existing controls, then 

this needs to be reflected in proposed RACT requirements for VOCs in the SIP. 

4) The RACT Summary Table indicates that oxidation catalyst for VOC control will be 

installed at the IC engines by 2017. Please explain why an earlier date would not be 

achievable. 

5) The draft SIP should specify the requirement for the owner/operator to operate and maintain 

CEMS and output meters for each engine, and state or cross-reference the relevant CEMS 

requirements. 

6) The draft SIP should specifically identify the number and types of emitting units at 

Springville City Power, e.g. "Springville City Power has seven dual-fuel internal combustion 

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

as well as one natural gas fired boiler of size that is used to and has a 

generating capacity of , as well as one boiler fired on digester gas of stze 

that is used to and has a generating capacity of " 

46 
ATTACHMENT 3 

EPA Region 8 Comments on Modeling Technical Support Documents for Utah SIP Control 

Measures for Area and Point Sources, Fine Particulate Matter, for the Salt Lake and Utah 

Nonattainment Areas. 

1) Pre-Baseline Emission Reduction Credits. 

Either the state must include any banked emission reduction credits in the projected 

inventory and model them as part of the attainment demonstration, or the applicable SIP rules 

must include definitive language stating that no pre-baseline emission reduction credits 

(a.k.a. banked emissions) may be used within the 2006 24-hour PM2.5 nonattainment areas to 

offset increases of PM2.5, NOx, S02, or VOC from major stationary source construction or 

modification. If the emission reduction credits will be added to the modeled emissions, a 

description of the emissions scenarios should specifically identify by species, location and 

layer any banked emissions. Also, it was indicated by the state that there is no intent to adopt 

a minor source offset rule for PM2.5 and its precursors within the PMz.s nonattainment areas. 

While we have indicated that our regulations contain no specific requirement for minor 

source offsets, we have also indicated that the SIP or SIP rules must specify an enforceable 

approach by which Utah will determine whether minor source construction or modifications 

will interfere with attainment or maintenance of the PMz.s NAAQS or the control strategy 

and will prohibit such construction or modification if it would interfere with attainment or 

maintenance of the PM2.5 NAAQS or the control strategy. We have suggested that the 

approach could consist of a tracking system through which Utah compare actual minor 

source emissions growth to the attainment demonstration's projected minor source emissions 

growth. There may be other approaches as well. We are not suggesting that source-by-source 

modeling is required, although, if Utah wishes, modeling could be required. It does not 

appear that the existing minor source NSR rules require any type of impact analysis or 

tracking for construction or modification in nonattainment areas. 

We recommend including in the modeling TSD a summary of the post-SMOKE modeled 

emissions for each year. This is a useful quality assurance product and is helpful in 

comparing and verifying that the emissions input to CMAQ are consistent with the raw 

emissions data that was input to the SMOKE emissions processing system. For example, 

plots of daily total emissions for each major emissions sources category and selected species 

could be included in the TSD. 

2) SIP Narratives Section 5.6 and CMAQ Modeling, p. 4.d-22-23 and Appendix D. 

The SIP narrative and TSD for CMAQ indicate that the emission inventory factors for wood 

smoke were updated for the 2010 baseline inventory, which improved model performance for 

organic carbon (OC). OC fractions shown in figures 5.11, 5.12 and 5.13 of the Provo and Salt 

Lake City SIP narratives, for Hawthorne, Bountiful and Lindon model performance, are 

identical to the figures shown in 2012 for the Logan SIP, prior to the wood smoke updates. 

Are the figures in the 2013 public comment documents current? 

3) The Provo SIP narrative for figures 5.11, 5.12 and 5.13 states (p. 36, 38): 

47 
"At all 3 [Speciation Trends Network] STN sites, the percentage of simulated nitrate is 

over-predicted by 5 to 7%. The simulated ammonium percentage is nearly identical to the 

observed STN speciation. At the Hawthorne site, organic carbon looks to be underpredicted by CMAQ with a percentage ofPM2.5 at 12% and an observed organic carbon 

at 21%. This discrepancy in organic carbon is not apparent at the Bountiful and Lindon 

site." 

"Speciation and composition of the modeled PM2.5 matches the observed speciation quite 

well. Modeled and observed nitrate are between 40% and 50% of the PM2.5. Ammonium 

is between 15% and 20% for both modeled and observed PM2.5. Organic carbon is 

underestimated at the Hawthorne location, but is reasonably estimated at the other 

locations (Bountiful, Lindon)." 

The speciation category "other" is not addressed in this discussion; at Hawthorne, monitored 

and modeled "other" agree at 15 and 14%, respectively, but at Bountiful, modeled "other" is 

only about ~ monitored (9% vs. 17%) while at Lindon, the modeled "other" is 11% of the 

mass on episode days over 25ug/m

3

, while the monitor records fully 26% of the mass as 

"other" on these days. This is a significant fraction of the PM mass on high concentration 

days, and a significant underperformance of the model not discussed in the narrative or the 

TSD. Depending on the components represented by "other" it could represent unexplored 

opportunities for additional control strategies that could lead to more expeditious attainment. 

4) The composition of "other" will depend on the method used to convert speciation data to 

simulated PM2.5 filter mass. At a minimum, "other" likely contains primary PM2.5 crustal 

emissions; one way "other" could be too low from the model, would be to have a significant 

shortfall in primary PM2.

5 emissions in the inventory. Breakdown of the composition of 

"other" as was done in figure 3 .2, for both the speciation data and the model output, would 

help to clarify the nature of the shortfall. In addition, a description and data on the mass 

reconstruction calculation in either the CMAQ or Weight of Evidence TSD sections would 

help to allow an assessment of the model-to-monitor comparison. 

5) To assess whether the "other" in Lindon's pie graph was dominated by crustal, the EPA 

extracted elemental speciation data for several likely "other" components for winter days 

above 25ug/m3 for 2008-2013 at Lindon, Hawthorne and Bountiful. Peak elemental mass 

fractions were for chlorine, potassium and iron, rather than silicon which is usually expected 

to be the largest contributor by mass for crustal samples. This was true for all three speciation 

samplers. Potassium was the third largest contributing element by mass fraction, although 

potassium is often not included in the calculation of filter mass reconstruction algorithms. It 

is not known whether UDAQ used potassium in the reconstruction algorithm used to derive 

Figures 5.11-13. Derivation information is requested to complete our review. 

48 
4.5% 

4.0% 

3.5% 

3.0% 

2.5% 

2.0% 

1 1.5% 

1.0% 

0.5% 

Top 3 Contributor Comparison 

. / 

\./ 

..... / 

,.· I 

./ I 

I 

/ 

- ProvoCI% 

- Provo Fe% 

•• - ProvoK% 

- ProvoK+% 

- · SLCCI% 

-41 • SLCFe% 

-41 • SLCK% 

..... • SLCK+% 

..... BountCI% 

• • -· • Bount Fe% 

• .. ... BountK% 

........ BountK+% 

I 0.0% I 

2007 2008 2009 2010 2011 2012 2013 2014 

6) Speciation data from 2009 and 2010 episodes was used in generating Figures 5.11-13; Figure 

5.11 for Hawthorne shows good agreement for "other" between the monitor and model. The 

figure above shows very marked differences, year to year, in chlorine contribution to PM2.s 

mass on high PM2.5 days. In most mass reconstruction algorithms, chlorine is assumed to be 

contained in sea salt particles; since ions in sea water are 55% chlorine by mass, chlorine 

mass is converted to sea salt mass by multiplying by 1.8 (1 /55%). Chlorine also composes 

approximately 55% of the ion mass in the Great Salt Lake, so if the chlorine in the Wasatch 

·Front speciated PM2.5 is assumed to be in salt particles derived from evaporation of Great 

Salt Lake droplets, multiplication by 1.8 would also be appropriate. This would imply that in 

2013, with chlorine content on high PM2.5 days at Hawthorne reaching 4.18%, assumed 

sea/lake salt particle mass reached 7.5% of total PM2.s mass. This variation year-to-year in a 

single component of "other" might suggest that the agreement between the model and 

monitored data in 2009 and 2010 at Hawthorne but not at Bountiful or Lindon may be more 

random chance than an indication that the model is replicating the actual filter chemistry for 

the speciation components of "other". A trend analysis of SIN "other" at the speciation sites 

within the weight of evidence section might be valuable to identify, evaluate, and potentially 

recommend or rule out alternative control strategies that could lead to more expeditious 

attainment dates. 

7) While most mass reconstruction algorithms assume chlorine will be in the form of sea salt on 

speciation filters, most speciation data for high chlorine loaded filters over 25ug/m3 at 

Hawthorne do not seem to support this assumption. Second high ion content in both sea 

water and the Great Salt Lake would be sodium at 30.8% by mass in sea water and 32.8% in 

Great Salt Lake water. If chlorine is primarily on speciation filters as salt particles from the 

49 
lake, then the chlorine to sodium ratio should be approximately 54.55/32.8 or 1.66 (by mass). 

If the chlorine to sodium ratio is much larger than 1.66, chlorine would appear to be in some 

form other than salt (either in minerals as a portion of crustal or presumably as ammonium 

chloride as a secondary aerosol product of gaseous chlorine or hydrochloric acid chemistry in 

the atmosphere). Examination of chlorine to sodium ratios on high PM2.5 speciation sampling 

days in 2008-2012 shows chlorine to sodium ratios generally range from 12 to 100 or more, 

suggesting a robust secondary chlorine aerosol chemistry is present. This would make the 

assumptions of sea salt composition inappropriate for mass reconstruction, and also point to a 

secondary aerosol pathway not currently captured in modeling. Weight of evidence 

evaluation of chlorine speciation data would be helpful in understanding model shortcomings 

and mismatches (if any) between speciation reconstruction assumptions and modeled 

"other". 

8) It would be helpful in assessing issues like that above, and projected model and SIP 

performance, if the CMAQ TSD included breakdowns of speciated relative response factor 

(RRF) by location for each of the future projections (2014, 2017, and 2019). This would 

show which portions of the PM2.5 aerosol are moving toward attainment under the SIP 

controls expeditiously, and which are decreasing more slowly (or growing) under the SIP 

control measures. 

9) For the SIP narrative Table 3.2, the 3-year design values are shown in whole numbers, 

rounded in accordance with 40 CFR Part 50, Appendix N rounding rules, but the baseline 

design values shown cannot be derived by averaging the design values shown. Instead, 

Region 8's understanding of the MATS calculation is that the baseline design values shown 

are derived by averaging 3-year averages of981

h percentile values, truncating to the right of 

the 0.1 ug/m

3 decimal place, averaging the truncated three 3-year averages in a 5-year design 

value period, then again truncating to the right of the 0.1 ug/m

3 decimal place. A note to this 

effect, or showing the decimal values in the table would make the table more understandable. 

1 0) MATS TSD, 4.d-3 . "Spatial interpolation options, "blank mass" amount and boundaries used 

OC mass estimation are left set at MATS default values (please see MATS documentation)." 

Presumably this should have read "and boundaries used for the OC mass estimation"? The 

reference to the MATS documentation with a citation, such as Sec. 7 .1.2.2, p. 172 for the OC 

mass estimation defaults, would help our review and the public's review. 

11) Weight of Evidence, Trends in Exceedance Days, p. 4.3-8 & 9. It is not clear whether the 

data shown in Figure 1.1 is exceedance days for all of the Salt Lake nonattainment area. For 

example, in 2000, the chart shows about 14 exceedance days, while the Air Quality System 

(AQS) database shows 22 separate exceedance days just considering the monitors in Salt 

Lake County. Given that, the conclusion "The number ofPMz.s exceedances between 1999 

and 2012 has decreased by approximately 31% in the Salt Lake non-attainment area" is not 

well supported. Is this based on a rolling average over some period of time, the slope of the . 

linear regression, or some other method? The conclusion should be qualified, given that the 

number of monitors operating and their sampling frequencies have changed over time. This is 

particularly pronounced in Logan, where in 2002 the monitor recorded 11 exceedances 

between January 8 and February 22 on a one day in 3 schedule, before moving to a daily 

schedule May 14 ofthat year; therefore measured exceedances in 2000-2002 in Logan could 

be approximately 113 of the number of days which actually had PMz.s above the NAAQS. 

50 
This makes the quoted decrease statistics in numbers of exceedance days unreliable, or 

difficult to interpret accurately. There needs to be further discussion on the derivation of the 

data presented, since there is such a large discrepancy between what is stated in the SIP and 

what is in AQS. 

12) Section 1.1 trends vs. Section 1.2 trends. Where section 1.1 cited trends in exceedance days 

based on 1999-2012 data (2001-2012 for Logan), 1.2 shows data through the first half of 

2013. Section 1.1 did not include this 2013 exceedance day data, but, if included, only Salt 

Lake City would then have a downward trend in exceedance days since the start of 

monitoring; the long term trend for Utah County is essentially flat, while the long term trend 

for Logan (without correcting for the monitoring frequency change in 2002) is upward. 

Long Term Trends, Numbers of Exceedance Days, Utah PM2.5 

NonattainmentAreas 

45 ~----~----~------,------,------.-----~-----.------, 

--Logan 

Salt Lake City 

Provo 

- Linear (Logan) 

- Linear (Salt Lake City) 

- Linear (Provo) 

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

0 1998 2000 2002 2004 2006 2008 2010 2012 2014 

13) 1.2.3 Meteorology, p. 4.e-20-21: "Although 2012's snow depth was nearly half the average 

and temperatures were 1.5°F warmer, 2012's snow depth and surface temperatures were not 

as extreme as 2013 and therefore should be included in the baseline design value period." 

This is a matter of opinion without much technical support. For example, various baseline 

design value periods could be evaluated for their degree of deviation from long term 

temperature and snow depth means; considering the 2007-2011,2008-2012 and 2009-2013 

baseline periods, 2009-2013 is nearest the means for Salt Lake County, while 2008-2012 is 

nearer the means for Utah County. Technical support could be quantified and should be 

provided for review so that the selection of baseline period looks less arbitrary. 

Salt Lake County Snow Depth Utah County Snow Depth 

51 
Long Term Avg. 2.7 30.8 Long Term Avg. 1.74 28.6 

2007-2011 2.754 29.66 2007-2011 1.938 25.92 

2008-2012 2.512 30.4 2008-2012 1.72 26.68 

2009-2013 2.768 30.48 2009-2013 2.16 26.12 

Deviation from Mean 

Green: Most Typical; Red least Deviation from Mean 

2007-2011 0.054 -1.14 2007-2011 -7.72867 25.92 

2008-2012 -0.188 -0.4 2008-2012 -7.94667 26.68 

2009-2013 0.068 -0.32 2009-2013 -7.50667 26.12 

14) Meteorology, p. 21. "The NWS launches a weather balloon twice a day, one at 12 Zulu ( 12Z) 

and one at 00 Zulu (OOZ). Only data from the morning sounding (12Z) (which is launched at 

5 or 6 AM local time depending on whether it is Daylight Savings Time) was used." Note 

that the guidance for the National Weather Service (NWS) upper air sounding programs . 

directs that the balloons be launched as close to 1-hour earlier than the scheduled time as 

possible, in order to have the balloon reach the stratosphere at approximately 12Z; therefore 

Salt Lake City launch time is actually 12Z-8 hours, rather than 12Z - 7 hours, or 4 or 5 AM. 

See http://www.nws.noaa.gov/directives/sym/pd01014001curr.pdf: "Actual release times for 

the 00 and 12 UTC standard scheduled upper air observations should be as close as possible 

to H-60 minutes, where His one of the standard times." 

15) Inversion Strength, p. 4.e-23. Inversion Strength is the difference in temperature at 2134 

meters minus temperature at 1289 meters; as a temperature difference, conversion to degrees 

F is simply multiplication by 9°F /5°C, not multiplication by 9/5 + 32°F. Therefore converting 

inversion strengths of 5°C to 10°C to °F gives 9 to 18°F, not the 41 to 50°F shown. The 25°C 

strongest inversion in 15 years was 45°F, not the 77°F stated. 

16)Page 4.e-22&23. The assessment of inversion strength in 2012 versus 2013 is somewhat 

qualitative and therefore a matter of opinion; the data could be assessed quantitatively. 

Seasonal inversion strength-day units could be calculated, or, for example, both 2013 and 

2010 show 32 days with inversions. Looking at the entire 1999-2013 data set, rather than just 

2008-2013 would allow a more objective analysis of the degree to which 2013 is, or is not, 

an outlier compared to a greater sample size. 

17) Page. 4.e-23. "Year 2013 exhibited extreme inversion periods, while 2012's inversions were 

more typical in terms of strength". Some objective quantitative comparisons of the two years 

with the long term means would validate this statement. 

18) Unmonitored Area Analysis, p. 4.3-45. "We then compare the FDV at each grid-cell to the 

NAAQS (35~g/m )." The highest scale level shown on Figure 1.25, p. 4.e-48 is 35.5 to 39.0; 

should the text actually state" ... at each grid-cell to the NAAQS (35.4~g/m )"? 

19) Figure 1.25, p. 4.e-48. The description of the figure indicates that only one grid cell, just NE 

ofthe Kennecott Bingham Canyon mine, shows a 2019 unmonitored modeled violation. 

From the color scale, however, it appears that 2 grid cells in Box Elder County, probably at 

the ATK location, could also be the 35.5 to 39ug/m3 color. Perhaps peak modeled 

concentration in each county could be tabulated? 

52 
20) Section 1.8. Could more clarification be provided on how MATS is treating the non-winter 

days ofTable 1.11 and 1.12? Are any RRFs for any species applied to these data by MATS 

(other than an RRF of 1.0)? If so, which species have RRFs different from 1.0, and what 

speciation profiles are used for the non-winter days? If RRF outside winter months are all 

1.0, please add that for clarity. 

53 
ATTACHMENT 4 

EPA Region 8 Comments on Mobile Sources, Transportation Conformity, Related Contingency 

Measures, and 1/M. 

Mobile Sources and Transportation Conformity 

I) Mobile Sources Comments on the Salt Lake Section of the SIP Narrative: Salt Lake Section; Control 

Measures for Area and Point Sources, Fine Particulate Matter, PM2.s SIP for the Salt Lake City, UT 

Nonattainrnent Area Section IX. Part A.21 

a) Issue 1 

On-road mobile sources; the SIP Narrative states the following on page 58: 

"A decentralized, test-and-repair program was evaluated for Box Elder and Tooele counties 

within the nonattainrnent area. For the evaluation, all model year 1968 and newer vehicles would 

be subject to a biennial test except for exempt vehicles. The program would exempt vehicles less 

than four years old as 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 (TSI). Based on this 

evaluation, this program was not included because it was determined that implementation of such 

a program would not affect PM2.5 concentrations at the controlling monitor (Hawthorne) for the 

Salt Lake-Ogden-Clearfield nonattainrnent area." Additional information is provided in the 

Technical Support Document." 

There would have been emission reductions ofNOx and VOCs identified with the state's 

evaluation. Taken only by themselves, these I/M emission reductions may not have shown a 

modeled difference at the Hawthorne monitor. However, such an I/M program would likely 

produce viable PM2.5 precursor emission reductions ofNOx and VOCs for the Salt Lake-OdgenClearfield nonattainrnent area. UDAQ has not provided the EPA with their evaluation, and it 

would be helpful in our review to see UDAQ's analysis, with the estimated potential emission 

reductions from an I/M program, to further understand the state's conclusion. We note that 

Section 5.e of the TSD ("Control Strategies, On-Road Mobile Sources") only provides the 

following additional paragraph regarding this question: 

"UDAQ also tested the inclusion ofthe above liM programs in both Box Elder and Tooele 

counties within the Salt Lake nonattainrnent area. However, photochemistry model sensitivity 

runs revealed that the effect of these controls on PM2.s concentrations at the controlling air 

monitor located at Hawthorne Elementary School (1675 South 600 East in Salt Lake City, Utah 

at an elevation of 1306 m or 4285 ft) was negligible. Therefore, the effectiveness of an liM 

program was not included in the modeling in either of these counties. However, liM programs 

already exist in Salt Lake, Davis, Utah, and Weber counties and are reflected in the inventories." 

b) Issue 2 

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

"The plans and programs produced by the transportation planning process of the [Wasatch Front 

Regional Council] WFRC are required to conform to the on-road mobile source emissions 

budgets established in the SIP. Approval of conformity is determined by the FHWA and FTA." 

54 
To be accurate, the EPA notes the last sentence should be revised to read as follows: "Approval 

of conformity is determined by the FHW A and FTA after receipt of concurrence on the 

conformity determination by EPA." 

c) Issue 3 

On-road mobile sources; SIP Narrative, WFRC Transportation Conformity Budgets, on page 62: 

There may be discrepancies between the Vehicle Miles Traveled (VMT) data developed by the 

Metropolitan Planning Organization (MPO), the Wasatch Front Regional Council (WFRC), for 

use in the SIP and those VMT data used in the latest (August 22, 2013) conformity determination 

performed by the WFRC. This potential issue of inconsistent data for VMT would have impacts 

on the MOVES modeling performed by the UDAQ to develop mobile sources emissions 

estimates for inventory data tables, the dispersion modeling, and for defining the respective 

nonattainment area Motor Vehicle Emissions Budgets (MVEBs). 

To illustrate this concern the EPA compared the MVEB emissions data for direct PM2.s, NOx, 

and VOCs contained in the SIP narrative Table 7.1 to the mobile source emissions data from the 

conformity determination, dated August 22, 2013 (specifically Tables 12a and 12b), as provided 

in the WFRC's Air Quality Memorandum Report No. 29 (dated August 22, 2013): 

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

Year PM2.s NOx voc 

2014 5.01 80.00 47.50 

2017 4.55 66.98 40.11 

2019 3.71 51.68 30.55 

Mobile Sources Emissions From WFRC Tables 12a & 12b; all in Tons Per Day 

Year PM2.s NOx voc 

2015 7.11 66.52 N/A* 

2020 6.77 47.90 N/A 

*Not Available. 

Noted discrepancies; PM~ Emissions: 

1) Clarification is needed from UDAQ (and WFRC) as to why the mobile sources direct PM2.s 

emissions for 2015 (WFRC) would be 2.1 tpd more than the SIP's 2014 (UDAQ) figure. We 

further note that the 2019 (UDAQ) PM2.5 emissions of 3.71 tpd are significantly lower than the 

2020 (WFRC) emissions of 6. 77 tpd. In addition, we note that the WFRC August 22, 2013 

conformity determination did not include re-entrained road dust emissions. 

Noted discrepancies; NOx Emissions: 

1) Clarification is needed from UDAQ (and WFRC) as to why the mobile sources NOx 

emissions would be 80.00 tpd in 2014 (UDAQ), but only 66.52 (WFRC) tpd for 2015 for the 

same nonattainment area. We note the SIP narrative shows the decline to a figure of66.98 tpd 

would not occur until 201 7. 

2) Clarification is needed from UDAQ (and WFRC) as to why the mobile sources NOx 

emissions would be 51.68 tpd in 2019 (UDAQ), but 4 7.90 (WFRC) tpd for 2020 for the same 

55 
nonattainment area. The SIP narrative shows a decrease of28.32 tpd ofNOx from 2014 to 2019, 

but the WFRC only shows a decrease of 18.62 tpd ofNOx from 2015 to 2020. 

The state needs to provide the specific VMT data (or point to the data's exact location in the 

TSD) that were used for the mobile sources emissions estimates for the SIP-identified MVEBs 

for 2014, 2017, and 2019 for the Salt Lake PM2.5 nonattainment area (also refer to the EPA 

comment A.4 below). In addition, the state needs to provide clarification regarding the abovenoted potential inconsistencies. The EPA will use the state's VMT data to compare to those 

VMT data used by the WFRC in its conformity determination of August 22, 2013. Consistent, 

accurate VMT data and subsequent mobile sources emission calculations are a requirement for 

both the PM2.s nonattainment SIP and any conformity determinations performed by the WFRC 

with respect to the SIP's MVEBs. 

d) Issue 4 

Overall Comments on VMT Data: TSD Section 3.e.iii "Technical Support Document for OnRoad Mobile Sources: PM2.s Emissions Inventory for PM2.5 SIP 2010 Baseline Year and 

Projection Years 2014, 2017, and 2019" 

The state needs to provide the specific VMT data that were used for the mobile sources 

emissions estimates for 2014, 2017, and 2019 for the Salt Lake PM2.5 nonattainment area. There 

may be potential discrepancies between the VMT data developed by the WFRC which was then 

used in the EPA's MOVES2010a model to develop mobile sources emissions estimates for SIP 

inventory data tables, the dispersion modeling, and for defining the respective nonattainment 

areaMVEBs. 

The EPA considered the following information regarding VMT that was readily available in 

TSD Section 3.e.iii (and welcome further direction from UDAQ to additional available data); the 

table on page 3.e.iii-3 "2010 Winter Weekday Emissions", the table on page 3.e.iii-4 "2014 

Winter Weekday Emissions", the table on page 3.e.iii-5 "2017 Winter Weekday Emissions", and 

the table on page 3.e.iii-6 "2019 Winter Weekday Emissions". We considered the data under the 

heading "Distance" as being the whole-county sum total ofVMT for each county listed. We 

extracted the "Distance" data for Box Elder, Davis, Salt Lake, Tooele, and Weber counties and 

inserted those data in the table below: 

EPA Table A-1: Daily VMT ("Distance" 

County 2010 2014 2017 2019 

Box Elder 2,603,591 2,918,146 2,988,107 2,841 ,624 

Davis 7,561 ,284 9,387,728 9,773,674 9,391 ,628 

Salt Lake 25,349,568 31 ,743,818 33,152,583 31 ,922,324 

Tooele 2,474,433 3,555,173 3,853,553 3,794,593 

Weber 4,622,292 5,913,152 6,196,599 5,979,191 

EPA Comment: Inconsistent VMT figures. From the county-by-county VMT data extracted 

from Section 3.e.iii of the TSD, there is a predicted growth, as would be anticipated, in VMT 

from 2010 to 2014 and to 2017 for all five counties. However, for 2019, all five counties' VMT 

are then estimated to be he! ow their 20 1 7 levels. Also, for 2019, Davis County and Weber 

County VMT are almost the same as their respective 2014 VMT levels, and Box Elder County is 

56 
estimated to be less than its 2014 level. The above identified VMT inconsistencies need to be 

explained by the state. 

For an additional comparison, the EPA consulted the WFRC's transportation conformity "Air 

Quality Memorandum, Report 29, Conformity Analysis for the WFRC Amended 2040 Regional 

Transportation Plan" dated August 22, 2013 and found at: 

http://www.wfrc.org/air gualitv/AQ%20memo29 RTP2040 FINAL.pdf 

We looked at Tables 11a and 11 b for projected VMT figures for seasonal VMT for 2015 and 

2020 for Salt Lake County only (Note: We reviewed the seasonal VMT from the 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 whole county and winter time seasons). 

The VMT appear to be inconsistent between the SIP TSD and the WFRC. For the Salt Lake 

County only comparison, it appears that the PM2.s TSD daily VMT for 2014 are 31 ,743,818. 

However, from the WFRC conformity determination, Report 29, the 2015 daily VMT are only 

28,969,518. Typically, we would expect to see the 2014 figure to be smaller and then the 2015 

figure to be larger to account for projected growth. We also note that between the SIP TSD 2019 

VMT and the 2020 WFRC conformity determination Report 29 VMT, the VMT essentially show 

minimal growth between those two years (2019 TSD VMT 31 ,922,324 and 2020 WFRC 

conformity determination shows 31 ,957,83 7). 

As an additional comparison of projected VMT growth, we considered the total county data for 

Utah County (which includes the Provo PM2.5 nonattainment area). Utah County data from the 

above noted tables in TSD Section 3.e.iii show the following anticipated trend in growth for 

VMT: 

2019 

16,740,301 

Finally, the EPA requests that UDAQ provide the specific VMT for the Salt Lake nonattainment 

area only for each of the five counties and for 2010, 2014, 2017 and 2019. Once this information 

is provided, we will compare the total nonattainment area VMT for those years to the total 

nonattainment area VMT that were used in WFRC's Report 29 in Tables 12a and 12b for 2015 

and 2020. This comparison is important as it should reflect the VMT that were used to calculate 

the mobile source emissions that led to the derivation of the MVEBs contained in Table 7.1 on 

SIP narrative page 62, the same MVEBs to which WFRC will need to demonstrate conformity. 

e) Issue 5 

EPA concerns with the proposed amendments to "Salt Lake County Health Department, 

Health Regulation #22 -Vehicle Emissions Control Program" as proposed for public 

comment by Salt Lake County (see: http://www.slcohealth.org/envRegs/proposedRegs.html) 

EPA Comment: The EPA submitted comments on the proposed amendments to "Salt Lake 

County Health Department, Health Regulation #22 - Vehicle Emissions Control Program" on 

November 20, 2013. In our comments we identified a number of areas of concern with the 

provisions in the proposed regulation and with Appendix A of the regulation. We note that 

57 
emission reductions credit from the County's motor vehicle inspection and maintenance 

regulation were used in the modeling inventories for 2014, 2017 and 2019. Therefore, if the 

County does not address our concerns in its final, adopted version of county Regulation #22, we 

may be unable to approve the amended regulation, and this would affect the approvability of the 

SIP as a whole. 

II) Comments on the Utah County Section of the SIP Narrative: Utah County: Control Measures for 

Area and Point Sources, Fine Particulate Matter, PM2.s SIP for the Provo, UT Nonattainrnent Area. 

a) Issue 1 

"The plans and programs produced by the transportation planning process of the MAG are 

required to conform to the on-road mobile source emissions budgets established in the SIP. 

Approval of conformity is determined by the FHW A and FT A." 

To be accurate, the EPA notes the last sentence should be revised to read as follows: "Approval 

of conformity is determined by the FHW A and FT A after receipt of concurrence on the 

conformity determination by EPA." 

b) Issue 2 

Potential inconsistent VMT figures. 

The TSD Section 3.e.iii presents whole county VMT for Utah County; we have extracted those 

data and they appear in the table below: 

EPA Table B-1: Daily VMT ("Distance") 

County 2010 2014 2017 2019 

Utah 10,620,608 13,991 ,478 15,581 ,282 16,740,301 

The only readily available means we have to evaluate these whole county VMT was to compare 

the VMT data to those provided in the most recent (20 11) Mountainland Association of 

Government's (MAG) transportation conformity data from the "Conformity Determination 

Report, Mountainland MPO, 2040 Metropolitan Transportation Plan" dated May, 2011 and 

found at: 

http:/ /www.mountainland.org/site/downloads/planning/Transportation Plans/20 11 Metropolitan 

Transportation Plan/Document/ Air Quality Conformity Determination. pdf 

Relevant VMT data from the table entitled "Utah County Regional Travel Model 

Characteristics" show that county VMT for 2009 were 9,998,092 and for 2020, 14,670,890. 

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

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

County-wide VMT of 16,740,301 for 2019 and MAG's 2020 VMT figure of 14,670,890. The 

EPA would appreciate a discussion from UDAQ regarding these VMT differences. 

In addition, the EPA requests that UDAQ provide the specific VMT for the Provo PM2.5 

nonattainrnent area only, for 2014, 2017, and 2019, that were used by UDAQ to estimate the 

emissions for the MVEBs contained in Table 7.1 on page 61 of the Provo SIP narrative. This 

VMT information is important as it should reflect the VMT that were used to calculate the 

mobile source emissions that led to the derivation of the MVEBs and will be instrumental in our 

evaluation of future PM2.

5 conformity determinations that are prepared by MAG. 

58 
c) Issue 3 

Derivation of the Provo PM2.5 SIP's MVEB trading ratios. 

The EPA requests a further discussion of how the MVEB trading ratios were developed for the 

Provo PM2.5 nonattainment area. These ratios are discussed in the full paragraph on page 62 of 

the Provo SIP narrative and on pages 4.e.-58 and 59 of the Weight of Evidence section (section 

4.e.) of the TSD. The trading ratios for NOx:PM2.s of 11.26:1 and VOC:PM2.5 of 6.33:1 are 

significantly different than previously reported ratios. Typically, a higher ratio would be 

expected for VOC than for NOx. Please provide additional information on how these ratios were 

derived. 

III) TSD Comment: 

TSD Section 5.e., page 5.e.-1: Clarification: The state notes under the "On-Road Mobile 

Sources" RACM analysis that "Federal Controls (Tier II & III)" apply. To clarify, at this point in 

time only Tier I and Tier II apply as the EPA has not yet promulgated, by a final rule, the onroad vehicle and fuels Tier III requirements. 

59 
ATTACHMENT 5 

EPA Region 8 Comments on Emission Inventories and Area Source Rules. 

I) Reasonable Further Progress, Emission Inventory, and Smoke Model Comments 

a) Reasonable Further Progress (RFP) 

In the EPA's letter to UDAQ dated November 1, 2012, we pointed out that the state's draft SIP 

RFP plan fell short of constituting an approvable plan. The draft plan showed that the identified 

control measures did not indicate a linear progress toward attainment. The RFP columns showed 

what the tons per day emission value should be in order to show linear progression towards 

attainment. Linear progress was delayed until the later years of SIP implementation for all 

emissions other than VOC, as well as for projected ambient PM2.s concentrations. In order to 

show linear progress, the EPA emphasized that the RFP plan would need to have additional 

emission reductions by both 2014 and 201 7. 

Salt Lake Cit RFP 

350 

- PM2.5 Pro 

300 - Nox 

NOx Pro 250 -- so2 

io 200 - 502 Pro Cll 

> 

- - voc "' c: 

~ 150 - VOC Pro 

- Precursors 

100 

- Precur Pro 

- Total 

so 

- Total Pro 

0 

2008 2010 2012 Year 2014 2016 2018 

Figure 6.1 RFP for the Salt Lake City area. Dashed line shows the state's projected progress toward lowering 

emissions in order to reach attainment. 

In the state's revised Salt Lake City PM2.5 SIP Section IX. Part A.21 , Area and Point Source 

Control Measures, new projections are provided. These projections are developed using annual 

emissions from the year 2010 instead of the original baseline year of2008 and projected 

emissions totals from dispersion modeling in the attainment demonstration results for the interim 

years of 20 14 and 20 17. Attainment of the PM2.s standard is reached in 2019. 

For the milestone years of2014 and 2017, the values representing straight linear progress are 

shown in Figure 6.1 as a solid line for five pollutants considered in the SIP. Modeled projections 

for the pollutants are shown as dashed lines. Emissions are held constant by the state for direct 

60 
PM2.5 (not shown in Figure 6.1) and SOz. Figure 6.1 shows a near linear progression in the 

decrease of emissions for the interim years for NOx and VOC pollutants. The EPA had stated in 

our November 1, 2012 letter that in the draft Salt Lake City SIP linear progress is delayed until 

the later years of SIP. In order to show linear progress, the RFP plan would need to have 

additional emission reductions by both 2014 and 2017. 

... 

10 

Cll 

80 

70 

60 

so 

~ 40 "' c: 

~ 30 

20 

10 

0 

-.... 

....... 

2008 2010 2012 

Provo RFP 

- PM2.5 Pro 

~ - Nox 

~ - NOx Pro .__., oti: - so2 

- so2Pro 

- voc 

-- - VOCPro 

- - Precursors 

- Precur Pro 

- Total 

- - - - Total Pro 

2014 2016 2018 

Year 

Figure 6.2 RFP for the Provo area. Dashed line shows the state's projected progress toward lowering emissions in 

order to reach attainment. 

Figure 6.2 shows a similar decease in emissions in the interim years as had been demonstrated 

for the Salt Lake City. Both demonstrations satisfy the point the EPA made in its letter that a 

linear decrease in emissions is needed. 

b) Emission Inventory Requirements 

In our November 1, 2012 letter to the state we said that "The state needs to show that point 

source emissions for the baseline year are representative 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 the EPA, the state agreed to provide sensitivity analyses to determine that 

emissions in 2008 represent an average emission year, but to date these analyses have not been 

provided to the EPA. These sensitivity analyses will determine whether the recent economic 

recession caused fewer emissions to be released during.2008 because the demand for products 

and services was less." 

Our review of the most recent drafts of the Salt Lake City and Provo SIPs shows that this 

analysis has not been done. Although the state chose to use 2010 rather than 2008 as its baseline 

year, sensitivity analyses are still needed. During 2010 the economic recession had matured to 

the point that the economy was improving but the downturn was still apparent and any decrease 

in emissions lowering the baseline concentration may still be attributed to an economy affected 

by the recession. 

61 
An analysis of2010 emissions is also warranted because the state used projections from the 2008 

triennial inventory to develop the 2010 inventory. An analysis should be done to determine if the 

projected emissions were consistent with actual emissions that occurred in 2010. 

c) Smoke Model Output 

We have asked the state on numerous occasions to provide an output of the SMOKE model for 

the episodic days modeled. The EPA just received the information and we have not as yet, 

reviewed the data. Our review of the technical support document prior to receiving the SMOKE 

data and the state's air quality web site has shown daily emission amounts for categories rather 

than individual sources. The state provides a daily emission rate by category, i.e. point, area, 

road and non-road sources but does not provide point source inventories showing each source's 

daily emissions. We will compare the emission inventory we recently received for consistency 

within the larger emission inventory in the SIP and with emissions limitations indicated in the 

SIP. 

II) Area Source Comments 

a) General (applicable to all): 

1) While Control Technologies Guidelines (CTG), Alternative Control Techniques documents 

(ACTs), other EPA source documents, and other states rules are often appropriately 

referenced for RACT, there is little discussion on what was evaluated and then used in the 

Utah rules/requirements. More detail is needed on the evaluations ofthe rules and which 

were used for each rule. 

2) In its TSD, UDAQ frequently refers to the " 186 Compliance Advisories" over the past 4 

years. Are the advisories a subset of the total number of inspections, or a separate category? 

It would appear that the 186 advisories cover inspections for all types of facilities. Therefore, 

when only one advisory is negative for a type of facility, it could still be significant if only 

two others facilities - from that facility type were inspected. Further information is needed 

on Compliance Advisories. This is applicable to the rule effectiveness (RE) analysis for the 

area source rules within the SIP and will help with our evaluation. 

3) The state references Attachment 2: Non-Point Source Rule Effectiveness Ranges, Emissions 

Inventory Guidance for Implementation of Ozone and Particulate Matter National Ambient 

Air Quality Standards and Regional Haze Regulations, EPA 12/2005 as the basis for its RE 

evaluation. While this is evidenced in the state's evaluation, it would strengthen the 

evaluation to directly reference the applicable "most important", "other important" and 

"other factors" listed in the reference document. 

4) R307-307 - Road Salting and Sanding: 

No RE or RACM analysis was done. 

5) R307-312 - Aggregate Processing Operations: 

We were not able to find the referenced RACM analysis or spreadsheet in the TSD for this 

rule. 

6) R307-345 - Fabric and Vinyl Coatings: 

62 
In the RACM analysis, EPA CTG 450/2-77-008- "Surface Coating of Cans, Coils, Paper, 

Fabrics, Automobiles and Light-Duty Trucks," is referenced as providing presumptive 

RACM. However, a 1977 CTG is arguably out of date and no longer presumptive RACM. 

An analysis of current controls that are being used nationally is needed to evaluate if the 

1977 CTG can still be used as RACM or if a more current control should be used for RACM. 

Other sources (The South Coast Air Quality Management District rule 1128 and the San 

Joaquin Valley Air Pollution Control District rule 4607) were referenced as having also been 

evaluated for RACM. However, no details of the analysis of these rules are provided. The 

details of the analysis need to be included to complete a RACM analysis for this rule. 

7) R307-350- Miscellaneous Metal Parts and Products Coatings: 

Missing RACM Analysis with individual rule (page Sb-140). Appears to have been placed at 

end ofRACM analysis for R307-354 (page Sb-189). See comments for that rule below. 

8) R307-353- Plastic Parts Coatings: 

REanalysis for this rule is somewhat weaker than the other rules reviewed. We were not able 

to fmd the referenced RACM analysis or spreadsheet in the TSD for this rule. Please include 

this information in the TSD for the plastic parts coating section as you have in other area 

source rules in the TSD. 

9) R307-354- Automotive Refinishing: 

An example of a category with one violation out of 186 Compliance Advisories, but out of 

how many inspections specific to the category? See General Comment (a)(2) above for 

explanation. 

After the RACM analysis for this rule, a second RACM analysis is presented that appears 

meant for rule R307-350- Miscellaneous Metal Parts and Products Coatings. See comment 

for that rule above. 

63