DAQ-2024-008501

June 14, 2024

Ryan Bares
Erica Pryor
Utah Division of Air Quality
P.O. Box 144820
Salt Lake City, Utah 84114-4820

Delivered by Email: [e-mail] and [e-mail]

Subject: Comments from the Utah Petroleum Association, Utah Mining Association, and
Utah Manufacturing Association on May 2024 Proposed Changes to Small and Large Boiler
Rules R307-315 and R307-316

Dear Ms. Pryor and Mr. Bares:

UDAQ recently finalized small and large boiler rules, R307-315 and R307-316, respectively, to
control ozone forming NOx emissions from these sources in the counties of the Northern and
Southern Wasatch Front ozone nonattainment areas .1 After a recent Air Quality Board approval
to propose additional changes to these rules,2 the Utah Division of Air Quality (UDAQ) published
the additional proposed changes in the Utah Bulletin, opening a 30-day comment period.3

The Utah Petroleum Association, Utah Mining Association, and Utah Manufacturers Association
jointly thank you for providing the opportunity that allows us to offer these comments on the
proposed changes.

The Utah Petroleum Association is a statewide oil and gas trade association established in 1958
representing companies involved in all aspects of Utah’s oil and gas industry. Members range
from independent producers to midstream and service providers, to major oil and natural gas
companies widely recognized as industry leaders responsible for driving technology advancement
resulting in environmental and efficiency gains. Five member companies each operate a
petroleum refinery in the Northern Wasatch Front ozone nonattainment area (“NWF”).
Additionally, member companies operate oil and gas production and midstream facilities within
the Uinta Basin ozone nonattainment area. Thus, our member companies have an interest in air
quality and air emissions contro ls throughout Utah.

The Utah Mining Association was founded in 1915 and serves as the voice of Utah’s mine
operators and service companies which support the mining industry. The member companies

1 Air Quality Board meeting, May 3, 2023.
2 Air Quality Board meeting, May 1, 2024.
3 Utah Bulletin; Number 2024-10; May 15, 2024; Notice of Proposed Rules, Air Quality, R307 -315 NOx
Controls for Natural Gas Fired Boilers 2.0-5.0 MMBtu (page 24) and R307-316 NOx Controls for Natural
Gas Fired Boilers Greater Than 5.0 MMBtu (page 28).
Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 2 of 10

operate hardrock, industrial mineral, and coal mines throughout the State of Utah. The Utah
Mining Association has an interest in air quality in support of the communities in which our
member companies operate and air emissions controls in Utah.

The Utah Manufacturers Association has been the voice of manufacturing in the state of Utah
since 1905. The Association exists to connect and strengthen Utah’s manufacturing community.
The Manufacturers Association represents over 1200 manufacturing and service providers, big
and small, in every inch of Utah.

Except as otherwise noted, all our comments apply to both the small and the large boiler rules,
R307-315 and R307-316, respectively.

We understand the purpose of the boiler rules to be to ensur e that new boilers and physical boiler
modifications including burner replacements in boilers employ stringent NOx controls to reduce
NOx emissions and therefore reduce local ozone formation over time. We support this purpose
in the interest of cost-effective improvements to air quality. Nonetheless, the changes to the rules
must be appropriate and workable.

We support the proposed changes that align the applicability requirements for the rules into
sections R307-315-2 and R307-316-2. These changes increase the clarity of the rules.

UDAQ proposed a definition for “combustion analysis”:

“Combustion analysis” means an analysis performed on flue gases using a portable
instrument which measures a range of variables relevant to the byproducts of combustion
including temperatures, draft pressure, concentrations of oxygen, and concentrations of
pollutants.

We support this definition as proposed. It provides necessary information about how a boiler
operator may use the combustion analysis compliance options provided in R307-315-6(1)(c) and
in R307-315-6(1)(d).

We have concerns with the proposed changes to the “construction” and “modification” definitions
as these proposed changes carry unintended consequences and do not serve the purpose of the
rules, namely, to reduce NOx emissions over time when owners and operators of applicable
boilers upgrade or replace burners in a boiler or replace the boilers themselves. Instead of
modifying these definitions, we recommend eliminating the use of these terms and eliminating the
corresponding definitions.

We disagree with adding carbon monoxide (CO) limits to the rules as these limits are
unnecessary, lack important details needed for compliance , and do not meet the requirements
imposed by the Utah Code when adopting rules that do not align with or address federal
requirements.

We thank you for providing updated versions of the rules which correct the incorrect references
in R307-316-6(1), R307-316-4(3), and R307-315-6(1). The updated versions of the two rules
have different references but should be similar.

We explain these concerns and our recommendations in detail below.

Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 3 of 10

Comment #1: Instead of modifying the definitions of “construction” and “modification,”
we recommend eliminating the use of these terms and eliminating the definitions from the
boiler rules.

UDAQ proposed the following changes to the definitions of “construction” and “modification”:

"Construction" means any physical change or change in method of operation including
fabrication, erection, installation, demolition, or modification of a n emission unit [boiler
which] that would result in a[n] potential increase in [actual NOx ]emissions.

"Modification" means any planned change in a [boiler]source which results in a[n increase
of actual NOx] change in emissions.

These proposed changes to the definitions incur several problems . The definitions of
“construction” and “modification” have been subject to extensive discussion in three sets of prior
comments4 (copies attached) and UDAQ ultimately finalized the definitions in a manner that
appropriately tailors them to the specific purpose of the rules. The proposed modifications to
these definitions will result in unintended and inappropriate consequences and misalignment with
the purpose of the rules. Nonetheless, eliminating the use of these terms and associated
definitions and focusing the rule where intended , namely controlling NOx emissions from new
boilers and those boilers undergoing significant physical modification including change out of 50%
or more of the burners, provides a simple, effective, and appropriate approach.

We understand the proposed changes to the definitions to be aimed at aligning the definitions
more closely with definitions used for federal rules for new source review (NSR) or prevention of
significant deterioration (PSD) air permitting. Definitions used for air permitting do not serve the
purpose of the boiler rules. For example:

• The definitions should be limited to NOx emissions increases , not to other pollutants as
the proposal would do. The rule title refers to NOx controls (and CO per proposed revision,
which we disagree with as described in our comments below). Not limiting the definitions
to the intended pollutant(s) leads to confusion and is inappropriate as it has no bearing on
limiting ozone production, the purpose of the rule .
• The proposed changes could trigger the rule based on boiler tuning, changing a set point
or firing rate within permitted limits , or turning down the boiler firing rate , all unintended
and untenable consequences of the proposed “modification” definition, which would
trigger the rule on a change in emissions rather than an increase.
• Boiler maintenance could trigger a temporary change in particulate matter emissions such
as during boiler online tube cleaning and soot blowing, thus triggering the rules in another
untenable way.
• An operator might want to install a new burner management system to improve boiler
operating safety. The burner management system might control the burners closer to the

4 See letter, Rikki Hrenko-Browning and Brian Somers to Bryce Bird and Members of the Utah Air Quality
Board, Concerns and Comments on Final Boiler Rules Submitted for Approval at the May 3, 2023, Air
Quality Board Meeting, April 28, 2023. Also see letter, Rikki Hrenko-Browning and Brian Somers to Bo
Wood, Ryan Bares, and Mat Carlile, Comments Regarding Proposed Rulemakings for Natural Gas -Fired
Boilers Greater than 5.0 MMBtu and 2.0-5.0 MMBtu, February 15, 2023. And see letter, Rikki Hrenko-
Browning and Brian Somers to Robert Wood and Ryan Bares, Comments Regarding Advance Notice of
Rulemaking for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters , October 17, 2022.
Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 4 of 10

desired excess oxygen level and thereby reduce NOx emissions, but this change could
trigger the rules. We do not agree with triggering the rules for minor changes such as this.

These are just some of the examples that could occur.

Some of these examples such as boiler maintenance and tuning illustrate the importance of the
need to focus the rules on increases in potential to emit rather than changes in actual emissions,
in conflict with what the proposed “modification” definition would do. See “potential to emit”
definition in R307-101.5

The proposed use of the term “emission unit” in the “construction” definition and the term “source”
in the “modification” definition lead to confusion and potential misinterpretation, possibly even
within the agency such as with the passage of time. Reinterpretation could even trigger air
permitting requirements. The applicability sections limit the rule to changes to a boiler, but use
of these terms as proposed contradicts the applicability. Further, we do not understand the use
of one of these terms in one of the definitions and the use of the other term in the other definition.
If the changes to t he definitions remain in the final rule, “emission unit” should be used in both
definitions. Otherwise, the entire source could potentially be pulled into the analysis to determine
when the rules would be triggered for a specific boiler. We do not believe this to be the intent,
nor do we agree with this possibility.

Air permit applicability determinations require far more analys es than simply considering these
definitions. The analyses are complex and typically require a significant technical undertaking to
reach a correct applicability determination. Simply adopting the definitions from air permitting fails
to recognize these very important details, too numerous to list here.

Using definitions employed in air permitting rules is unnecessary. If construction or modification
triggers air permitting, the project would be subject to all associated air permitting requirements
including lowest achievable emission rate (LAER) or best available control technology (BACT).
Thus, a NOx limitation would be imposed through LAER or BACT.

Please refer to comments on the prior proposed version of this rule , submitted February 15, 2023,
specifically item 7 starting on page 9, “The Associations recommend narrower definitions for
“construction” and “modification” that limit applicability to changes in NOx emissions due to
physical changes in the boiler.” We attached a copy of these comments for your convenience.

The Environmental Protection Agency (EPA) uses different definitions for New Source
Performance Standards (NSPS) than for air permitting to support the different purposes of these
very different sets of rules. NSPS provides a better analogy to the purpose of the boiler rules
than air permitting because, like the boiler rules, NSPS establishes emissions limits for certain
types of emissions, for certain new or modified equipment as applicable. In fact, in our original
October 2022 comments on the advanced notice version of these rules, we recommended
adopting the NSPS definitions. In our February 2023 comments on the proposed version of these
rules, we recommended narrower definitions then those proposed, to limit the scope to changes

5 ’Potential to Emit’ means the maximum capacity of a source to emit a pollutant under its physical and
operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant
including air pollution control equipment and restrictions on hours of operation or on the type or amount of
material combusted, stored, or processed shall be treated as part of its design if the limitation or the effect
it would have on emissions is enforceable. Secondary emissions do not count in determining the
potential to emit of a stationary source.
Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 5 of 10

in NOx emissions due to physical changes in a boiler. Finally, in our April 2023 letter to Bryce
Bird and the Air Quality Board, we recommended again narrowing these definitions to focus on
the purpose of the rule s rather than bringing in changes not intended to require burner
replacements. The rules were finalized at the May 2023 Air Quality Board meeting with
appropriately tailored definitions, but now once again, broad definitions that do not serve the
intended purpose have been proposed .

EPA uses the following definitions for NSPS:

Construction means fabrication, erection, or installation of an affected facility.

Modification means any physical change in, or change in the method of operation of, an
existing facility which increases the amount of any air pollutant (to which a standard
applies) emitted into the atmosphere by that facility or which results in the emission of any
air pollutant (to which a standard applies) into the atmosphere not previously emitted.6

The NSPS rules provide further context and narrowing of the definitions and applicability,
including but not limited to the following:

• Upon modification, an existing facility shall become an affected facility for each pollutant
to which a standard applies and for which there is an increase in the emission rate to the
atmosphere.7 [emphasis added]
• The addition of an affected facility to a stationary source as an expansion to that source
or as a replacement for an existing facility shall not by itself bring within the applicability of
this part any other facility within that source .8
• The following shall not, by themselves, be considered modifications under this part:9
o Maintenance, repair, and replacement which the Administrator determines to be
routine for a source category [subject to certain limitations]
o An increase in production rate of an existing facility, if that increase can be
accomplished without a capital expenditure on that facility.
o An increase in the hours of operation.
o The addition or use of any system or device whose primary function is the reduction
of air pollutants, except when an emission control system is removed or is replaced
by a system which the Administrator determines to be less environmentally
beneficial.
[emphasis added]

Some of the key points from the NSPS definitions and the analogy to the boiler rules include the
following:

• The definitions only apply to an affected facility for the pollutant for which the standard
applies, not for any pollutant nor for all pollutants. Similarly, any definitions in the boiler
rules should apply only to changes in NOx emissions and not to changes in emissions of
other pollutants.

6 40 CFR §60.2.
7 40 CFR §60.14(a).
8 40 CFR §60.14(c).
9 40 CFR §60.14(e)(1), (2), (3), and (5).
Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 6 of 10

• The “modification” definition relies on an increase in pollutants, not a change in pollutants.
Similarly, any definition of “modification” in the boiler rules should rely on an increase in
emissions, not a change in emissions.
• Maintenance, repair, and replacement do not in themselves trigger a modification.
However, as these definitions have been proposed to be changed, maintenance and
repair could but should not trigger the rules.
• Other changes in the method of operation, such as production rate increases and changes
in hours of operation do not trigger a modification. The definitions as proposed do not
make these exclusions, but should make them.

Thus, the proposed definitions for the boiler rules do not take these important limitations into
account but, if retained in the final rules, must consider them.

NSPS applicability also relies on reconstruction, triggered when the fixed capital cost of the new
components exceeds 50 percent of the fixed capital cost that would be required to construct a
comparable entirely new facility, and it is technologically and economically feasible to meet the
applicable standards set forth in the NSPS.10 The capital cost test ensures that the significant
investment of meeting an NSPS becomes required only in the case of a significant investment in
the equipment. In contrast, the boiler rules as proposed for modification could be triggered by
small and inexpensive modifications. Companies might avoid making otherwise beneficial
modifications (such as the burner management system modification discussed above) if a small
modification triggers the rule applicability and requires a significant investment in burner
technology. We don’t think UDAQ intended this.

The “construction” definition as proposed considers a change in method of operation, but should
be limited to newly constructed or replaced boilers. Moreover, as proposed, it would allow
replacing a boiler with a smaller boiler or any boiler with lower emissions even if it does not meet
the 9 ppm NOx limit, an unintended consequence and one that does not meet the purpose of
these rules.

The simplest approach to address all of these concerns would be to simply eliminate the use of
the terms “construction” and “modification” from the rules and eliminate the definitions as well.
We recommend the following changes to proposed R307-316-2(1)(e) and comparable changes
to R307-315-2(1)(e):

undergoes one of the following after the compliance date defined in Subsection R307-
316-6(4):
(i) begins construction, or modification of a boiler installs a new boiler, replaces an existing
boiler, or modifies a boiler such that the fixed cost of the modification exceeds 50% of the
fixed capital cost to install a new boiler ;
(ii) replaces a burner in a boiler having only a single burner; or
(iii) replaces 50% or more of the burners in a multi -burner boiler.

We chose the 50% Cost threshold to align the boiler rules with the threshold used in the
reconstruction definition in federal EPA NSPS rules.11

10 40 CFR §60.15(b).
11 See 40 CFR §60.15.
Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 7 of 10

If UDAQ does not agree with eliminating the use of these terms and these definitions, then we
strongly urge that the definitions remain intact in their current form, unchanged from the current
versions as finalized in May 2023 .

Comment #2: A CO limit should not be added to the rules.

The board memos for the proposals seem to suggest that adding CO limits to the rules would
provide an additional compliance mechanism,12 but the rules already have compliance
mechanisms, so an additional means is not needed. UDAQ has made no information available
to justify the additional means or to justify the level of the proposed CO limits, 200 ppm.
Furthermore, we do not understand setting the proposed CO limits at 200 ppm, half the level of
various boiler rules in California. We do not agree with adding the CO limits.

Salt Lake and surrounding counties do not have a CO attainment problem. A portion of Salt Lake
County had been designated nonattainment under the 1971 National Ambient Air Quality
Standard (NAAQS) for CO and was redesignated to attainment 25 years ago, in 1999.13 Air
quality in the area remains in attainment for the CO NAAQS.14 Therefore, new limitations on CO
are not needed to protect air quality.

Moreover, CO emissions do not have a relationship to ozone formation and therefore the CO
limits do not have a relationship to the purpose of the boiler rules.

UDAQ provided no technical information to justify the proposed 200 ppm limit for CO emissions
from boilers other than oral statements that boiler manufacturers and distributors said that these
limits could be met.15 We have no information regarding which boiler manufacturers provided this
information, any limitations to the information that they provided, the size or technical design of
boilers and burners for which they provided the information, the range of operating conditions for
which their statements apply, whether the proposed limits take into account start up and shut
down periods, whether the proposed limit can be achieved under operating turn down conditions,
or any other details. Under the short time of the comment period, it is impossible for stakeholders
to assess whether the proposed CO limits can be achieved under the broad range of
circumstances needed for operations.

Additionally, UDAQ provided no averaging time for the proposed CO limit and no test method or
means of demonstrating compliance. Yet these details are crucial for commenters and
stakeholders to understand whether compliance can be achieved and how to demonstrate
compliance. In the absence of these important details that would define compliance
demonstration mechanisms for the CO limits, adding these limits as an additional compliance
mechanism makes no sense because compliance with the CO limits cannot be demonstrated.
Furthermore, the required compliance information cannot be added at the time of finalizing

12 Ryan Bares to Air Quality Board, PROPOSE FOR PUBLIC COMMENT: Amend R307 -315. NOx
Emission Controls for Natural Gas-Fired Boilers 2.0-5.0 MMBtu, April 18, 2024. Also, Ryan Bares to Air
Quality Board, PROPOSE FOR PUBLIC COMMENT: Amend R307 -316. NOx Emission Controls for
Natural Gas -Fired Boilers Greater than 5.0 MMBtu, April 18, 2024.
13 64 FR 3216; Approval and Promulgation of Air Quality Implementation Plans; State of Utah; Salt Lake
City Carbon Monoxide Redesignation to Attainment, Designation of Areas for Air Quality Planning
Purposes, and Approval of Related Revisions; January 21, 1999.
14 See EPA design value spreadsheets for 2023 (the most recent available at the time of this writing),
located at https://www.epa.gov/air-trends/air-quality-design-values (accessed on June 6, 2024).
15 See statement at the 15:00 time mark in the recording of the Air Quality Board in consideration of these
proposed rule changes, May 1, 2024, located at https://www.utah.gov/pmn/files/1116865.mp3.
Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 8 of 10

the rules because that would not provide the appropriate notice and comment required or give
stakeholders the needed time to evaluate the information .

Applying CO limits to the boiler rules does not meet Utah Code requirements of 19-2-107 which
sets out the criterion to add something not required by the Federal government. Under this part
of the Utah Code, UDAQ must find that “the different rule will provide reasonable added
protections to public health or the environment of the state or a particular region of the state .” The
findings must be in writing and must be “based on evidence, studies, or other information
contained in the record that relates to the state of Utah and type of source involved.” In the case
of adding CO limits to the boiler rules, UDAQ provided no such information. Again, adding it at
the time of adoption would be inappropriate because it would not provide adequate time for the
regulated community to consider, evaluate, and comment on the information.

Furthermore, EPA did not include a CO limit in NSPS Subparts D, Da, Db, or Dc for boilers, except
under very limited circumstances as a compliance alternative in lieu of an opacity limit for certain
steam generators. EPA made no other mention of CO in the preamble to these proposed or final
NSPS rules.16 The prior version of the rules did not mention CO at all.17 From this, we conclude
that EPA did not consider limiting CO to be an appropriate or necessary enhancement to its NSPS
boiler rules.

In the federal rules for boilers, only the Maximum Achievable Control Technology (MACT) rules
for controlling hazardous air pollutants (HAPs) include a limit for CO, and only as a surrogate for
HAPs.18

We understand from conversation with staff that the CO limit s are intended to prevent a boiler
operator from installing a burner rated for higher NOx emissions and tuning it to lower NOx
emissions, which will in turn increase CO emissions. However, the proposed rules already
prevent this without adding a CO limit because they require the operator to “install a burner that
meets a NOx emission rate of nine parts per million by volume (ppmv) or less at 3% volume
stack gas oxygen on a dry basis.”19 [emphasis added] Specifying the stack gas oxygen

16 See final rule, 72 FR 32710, Standards of Performance for Fossil-Fuel-Fired Steam Generators for
Which Construction Is Commenced After August 17, 1971; Standards of Performance for Electric Utility
Steam Generating Units for Which Construction Is Commenced After September 18, 1978; Sta ndards of
Performance for Industrial -Commercial-Institutional Steam Generating Units; and Standards of
Performance for Small Industrial -Commercial-Institutional Steam Generating Units. See also proposed
rules, 72 FR 6320, Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which
Construction Is Commenced After August 17, 1971; Standards of Performance for Electric Utility Steam
Generating Units for Which Construction Is Commenced After September 18, 1978; Standards of
Performance for Industrial -Commercial-Institutional Steam Generating Units; and Standards of
Performance for Small Industrial -Commercial-Institutional Steam Generating Units; Reconsideration and
Amendments.
17 See final rules, 71 FR 9866, Standards of Performance for Electric Utility Steam Generating Units for
Which Construction Is Commenced After September 18, 1978; Standards of Performance for Industrial -
Commercial -Institutional Steam Generating Units; and Standards of Performance for Small Industrial-
Commercial -Institutional Steam Generating Units. See also proposed rules, 70 FR 9706 - Standards of
Performance for Electric Utility Steam Generating Units for Which Construction Is Commenced After
September 18, 1978; Standards of Performance for Industrial- Commercial-Institutional Steam
Generating Units; and Standards of Performance for Small Industrial- Commercial-Institutional Steam
Generating Units.
18 See 40 CFR Part 63 Subpart DDDDD, National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters .
19 Proposed rules R307-316-4(1)(a) and R307-315-4(1)(a).
Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 9 of 10

concurrently with the NOx emission limit precludes installing a burner and tuning it to lower NOx
emissions at the expense of CO emissions; such tuning would inevitably alter the stack gas
oxygen. Therefore, any additional limitation for CO is unnecessary.

In summary, EPA did not set a CO limit for any of its NSPS rules for natural gas fired boilers and
UDAQ has not presented appropriate or required justification to do so in its boiler rules.
Furthermore, as proposed, operators cannot demonstrate compliance with the CO limits due to
the lack of averaging times and compliance demonstration mechanisms. We recommend that
the final rules do not include a CO limit. We also recommend removing the proposed addition of
“and CO” from the titles of the rules.

Comment #3: The corrected reference in R307-315 needs another correction, to match the
corrected reference in R307-316.

The corrected reference in R307-315-6(1) should match the corrected references in R307-316-
6(1) and R307-316-4(3). The corrected reference provided for the large boiler rule R307 -316
states:

R307-316-4(1)[(c)]

On the other hand, the corrected reference provided for the small boiler rule R307 -315 states:

R307-315-4[(1)(c)]

The reference to paragraph (1) should be retained in the small boiler rule, like the corrected
reference in the large boiler rule.

Conclusion

In conclusion, the proposed changes to the definitions of “construction” and “modification” do not
enhance the rules and bring unintended and undesirable consequences. These definitions should
be eliminated, and the use of the terms eliminated as well. Alternatively, the definitions should
remain intact, unchanged from the current version. Furthermore, a CO limit should not be added
to either boiler rule as it has not been properly justified , does not serve a useful purpose, and
lacks important detail required to demonstrate compliance .

Please contact us if you would like to discuss our comments in more detail.

Sincerely,

Rikki Hrenko-Browning Brian Somers Todd Bingham
President,
Utah Petroleum Association
President,
Utah Mining Association
President/CEO
Utah Manufacturers Association

cc: Bryce Bird – [e-mail]
Becky Close - [e-mail]
Chad Gilgen – [e-mail]
Comments from the Utah Petroleum Association, Utah Mining Association, and Utah Manufacturing
Association on May 2024 Proposed Changes to Small and Large Boiler Rules R307-315 and R307-316
Page 10 of 10

Attachment: Letter, Rikki Hrenko-Browning and Brian Somers to Bryce Bird and Members of the
Utah Air Quality Board, Concerns and Comments on Final Boiler Rules Submitted for Approval at
the May 3, 2023, Air Quality Board Meeting , April 28, 2023, with attachments.

April 28, 2023

Bryce Bird - [e-mail]
Members of the Utah Air Quality Board (by email)
Randy Martin, Chair - [e-mail]
Michelle Bujdoso - [e-mail]
Kevin R. Cromar - [e-mail]
Kim Frost – [e-mail]
Cassady Kristensen - [e-mail]
Erin Mendenhall - [e-mail]
Sonja Norton - [e-mail]
John Rasband, Vice-Chair - [e-mail]
Kimberly D. Shelley - [e-mail]

Utah Division of Air Quality
P. O. Box 144820
Salt Lake City, Utah 84114 -4820

Subject: Concerns and Comments on Final Boiler Rules Submitted for Approval at the
May 3, 2023, Air Quality Board Meeting

Dear Bryce and Members of the Air Quality Board:

The Utah Petroleum Association (“UPA”) and Utah Mining Association (“UMA”) jointly (“the
Associations”) submit these comments regarding our concerns with the rules for Air Quality Board
(“AQB”) final approval to control NOx emissions from Boilers, R307-315 NOx Emission Controls
for Natural Gas-Fired Boilers 2.0-5.0 MMBtu and R307-316 NOx Emission Controls for Natural
Gas-Fired Boilers greater than 5.0 MMBtu (collectively, “boiler rules” or “rules”).

The Associations submitted comments on the rulemakings during the formal comment period1
and during the Advance Notice period.2 We appreciate the care and diligence that the Utah
Division of Air Quality (“UDAQ”) exercised in reviewing our comments and in fully adopting many
of them. As a r esult, we find the final rules for adoption to be clearer and more practical to
implement.

1 Letter, Rikki Hrenko-Browning and Brian Somers to Bo Wood, Ryan Bares, and Matt Carlile, Comments
Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and 2.0-5.0
MMBtu, February 15, 2023 (“comments letter on the proposed rules”).
2 Letter, Rikki Hrenko-Browning and Brian Somers to Robert Wood and Ryan Bares, Comments
Regarding Advance Notice of Rulemaking for Natural Gas-Fired Boilers, Steam Generators, and Process
Heaters, October 17, 2022 (Advance Notice comments letter”).
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 2 of 8

Nonetheless, while we realize that the comment period has ended and that UDAQ and the AQB
are under no obligation to consider additional comments at this stage of the rulemaking, we
thought it important to highlight remaining observations and concerns with the final rules that
should be addressed prior to the final adoption of the rules.

In short, we noted the following issues as listed below. We raised some of these issues in our
previous comment letters, while other issues only arose in the final rule language for adoption.
For those issues that we raised in prior comments, in some cases UDAQ’s Response to
Comments (“RTC”) speaks to the issue raised, albeit not satisfactorily, and in other cases, the
RTC does not acknowledge the prior comment; we note each situation accordingly.

We recommend that each of these issues be addressed prior to final adoption of the boiler
rules.

Rather than prioritizing the issues, we present them in the order of appearance in the boiler rules.

1. Fueled by natural gas in R307 -315-2(1)(a) and R307-316-2(1)(a) – The language of R307-
315-2(1)(a) and R307-316-2(1)(a) with respect to applicability for boilers fueled by natur al
gas leaves room for significant ambiguity for boilers fueled in part by natural gas and in
part by other fuels (e.g., refinery fuel gas). As written, the language could be
misinterpreted to mean that the rule applies to boilers that burn natural gas al one or in
combination with other fuels. The Board memos indicate UDAQ’s intent, that the rules
apply only to boilers fueled exclusively by pipeline quality natural gas when they state, “It
is important to note that the definition of natural gas proposed i n this rule results in the
exclusion of boilers not operating on pipeline quality gas,” and similarly in the Response
to Comment (“RTC”), “it is important to note that the proposed rules only apply to boilers
utilizing pipeline quality natural gas, and thus many of the larger boilers in the NAA
where unanticipated maintenance requirements would be of concern are not
covered under these rules.” [emphasis added]

We believe UDAQ’s intent was that the boiler rules apply to boilers fueled exclusively or
only by pipeline quality natural gas. Therefore, we recommend the following clarification
to R307-315-2(1)(a) and R307-316-2(1)(a):

is fueled exclusively by natural gas

2. Process Heaters in R307-315-2(2)(d) and R307-316-2(2)(d) – These paragraphs exempt
“process heat boilers as defined by this rule” but should instead state, “process heaters
as defined by this rule.” The rules contain definitions for process heaters but not for
process heat boilers. The RTC indicates the addition of an exemption for process heaters.
Therefore, we believe the intention was to exempt process heaters as defined in both
rules. The equipment serves to heat process fluids and, as such, are not boilers.

Therefore, we recommend changing the exemption in both rules as follows:

process heat boilers heaters as defined by this rule

3. R-307-315-3 and R-307-316-3 definitions for construction and modification – In our
comment letter on the proposed rules, we explained that these definitions are overly
broad. We understand UDAQ’s explanation in the RTC with a preference to maintain the
definitions as they are defined and used elsewhere in the air quality rules . However, these
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 3 of 8

definitions do not fit the stated purpose of the boiler rules . As written, these definitions
go far beyond simply replacing a burner in a boiler or replacing a boiler, and they pull in
the entire source, which could include several other process units. Not only do these
definitions pull in the entire source, but they also trigger applicability upon change in
method of operation and, furthermore, do not limit to changes in NOx emissions but could
apply to other types of emissions as well .

Nothing in the explanations of these rules and in the discussions that we had with UDAQ
indicated a desire to trigger applicability of the boiler rules based on such varying and
broad types of changes elsewhere at the source. Yet these definitions do exactly that.

Without better tailoring these definitions, the boiler rules could be triggered by a
change in any other process unit at the source, or a change in the method of
operation (even without a burner or boiler replacement, which is the intended
trigger), that changes any emissions, independent of the actual or potential effect
on boiler NOx emissions. We do not believe this to be UDAQ’s intention.

Therefore, we reiterate our two alternative recommendations for the definition of
construction and one option for the definition of modification to provide narrower definitions
tailored to fit the intended purpose in the context of these boiler rules, as follows:

Preferred alternative: Construction means fabrication, erection, or installat ion of
an affected facility.3

Second alternative:
“Construction” means any physical change or change in the method of operation
including fabrication, erection, installation, demolition, or modification of a source
boiler which would result in a change an increase in actual NOx emissions.

“Modification” means any planned change in a source boiler that results in a
potential an increase of actual NOx emissions.

4. R-307-315-3 and R-307-316-3 definition for Temporary Boiler - The temporary boiler
definitions in the proposed boiler rules were copied verbatim from the definitions in 40
CFR Part 60 Subpart Db, §60.41b, including the clause “and is capable of being carried
or moved from one location to another by means of, for example, wheels, skids, carrying
handles, dollies, trailers, or platforms.” However, in the final rules for adoption, in R-307-
315-3, the language “by means of, for example, wheels, skids, carrying handles, dollies,
trailers, or platforms” is underlined as though it is being added to the proposed language,
even though these words were in the original proposal. On the other hand, in the final
rules for adoption, in R-307-316-3, the language “by means of, for example, wheels, skids,
carrying handles, dollies, trailers, or platforms” is struck out as though it is being deleted
from the proposed language.

We do not understand this differing treatment of the two definitions nor does the Response
to Comment (“RTC”) address any reason to change either definition.

3 Definition from 40 CFR Part 60 §60.2.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 4 of 8

We recommend retaining the original language of the proposa l, which matches the well-
established and well-understood language of 40 CFR Part 60 Subpart Db.

5. R-307-316-4(1) incorrect cross reference – This paragraph begins with the phrase,
“Except as provided in Subsection R307 -316-4(8)” but the final rule for adop tion does not
include a Subsection R307-316-4(8). Based on the language of the proposed rule, we
believe this reference should now be to R307-316-4(3), which contains the language of
the alternate means of control.

Therefore, we recommend the following change to R-307-316-4(1):

Except as provided in Subsection R307 -316-4(83)

6. Inclusion of alternate means of control in small boiler rule, in R-307-315-4(1) – The small
boiler rule does not include a similar alternate means of compliance as the large boiler
rule. The Associations recommended adding this to the small boiler rule,4 but the RTC
makes no mention of this comment and why it was not addressed. We recommended
this in consideration of concerns raised by the American Boiler Manufacturers Ass ociation,
that the possibility exists that some small boilers may not be able to achieve 9 ppm or at
least without a trade -off in increased fuel. We do not see where the cost of this tradeoff
was incorporated into the economics for the rulemaking.

Therefore, we recommend adding a comparable alternate means of compliance to the
small boiler rule by wording R-307-315-4(1) the same as R-307-316-4(1) (corrected as
noted above) and adding a comparable R307-315-4(3). If this is not added to the small
boiler rule, we kindly request an explanation be added in the RTC.

7. Ambiguity between replacing a burner and 50% of the burners in R-315-4(1)(b) and R-
316-4(1)(b) – These paragraphs establish requirements when a person “replaces a burner
in a boiler.” However, this language is seemingly incongruent with R -315-4(1)(c) and R-
316-4(1)(c), which establish requirements when a person “replaces 50% or more of the
burners in a multi-burner boiler.” As written, the rule implies that the rule is triggered if a
person replaces a burner in a boiler (e.g., any single burner in any boiler) – effectively
making the following trigger “replaces 50% or more of the burners in a multi -burner boiler”
null. We do not believe this was UDAQ’s intent.

In our comments letter on the proposed rules, we stated, “We recommend clarifying that
R307-316-4(1)(b) applies to boilers with only a single burner. As written, (c) indicates
applicability to boilers with 50% of the burners being changed, and seems to stand in
conflict with (b).”5 This comment was not addressed in the RTC, nor was it addressed in
the final rule.

To clarify and eliminate the incongruity, we reiterate our recommendation of our comments
letter to revise R-315-4(1)(b) and R-316-4(1)(b) as follows, with a small adjustment in
wording to further clarify:

replaces a burner in a boiler having only a single burner

4 Comments letter on proposed rules, p. 5.
5 See comments letter on proposed rules, pp. 11-12.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 5 of 8

8. Certification in R-315-4(1)(c) and R-316-4(1)(c) - The RTC states, “The certification
requirements have been removed from the rule ,”6 and explains why certification falls
outside the scope of the rules. However, when purchasing burners and boilers, they must
be “certified” for 9 ppm NOx, per R-315-4(1)(c) and R-316-4(1)(c).

If “certification” falls outside the scope of the rules, then the language of these two
paragraphs should be changed to avoid the use of the word “certified.”

We recommend the following change to these two paragraphs:

. . . install a burner that is certified specified to meet a NOx emission rate . . .

9. Cross reference in R-307-316-4(c) – Apparently, the cross reference was not updated to
match the final rule numbering. The alternate means of control language states that “the
proposed alternate produces an equ al air quality benefit as required by Subsection R307 -
316-4(2)” but correct cross-reference should now be R307-316-4(1)(c).

10. R-307-316-4(c) regarding burner technology and add on controls – In our comments letter
on the proposed rules, the Associations indicated that the alternate method of control
should clarify that it does not require add -on controls other than burners if they cannot be
shown to be comparably cost effective. This rulemaking addresses burners only and does
not address other add -on controls which, typically, are more costly and less cost effective.
We recommended the following addition to the alternate method of control paragraph,
which is now R-307-316-4(c):

Unless a means of control other than burner technology can be shown to be
equally or more cost-effective, nothing in this rule requires consideration of add -on
controls other than burners.

The RTC does not address this comment, one which the Associations believe to be
important for maintaining parity between those facilities that change burners and those
that consider the alternate means of control, and we therefore reiterate our comment and
recommend adding the proposed language. If the language is not added, we kindly ask
that an explanation be included in the RTC.

11. Cross reference in R307-316-6(1) – Similar to the apparent incorrect cross reference in
R-307-316-4(c) as noted above, it appears that the cross reference for the NOx emission
requirement in R307-31 5-6(1) and R307-316-6(1) should refer to R307-315-4(1)(c) and
R307-316-4(1)(c), respectively, instead of R307-315-4(2) and R307-316-4(2),
respectively, included in the final rule text.

12. Compliance Timing and Flexibility – In our comments, we indicated that “The final rules
must accommodate situations where a facility cannot comply instantaneously upon
triggering the requirements.” We can think of many situations where flexibility in
compliance timing may be needed. We provided the following comments. While we spoke
about refineries in these comments, these comments should more aptly have been written
about any facility.

6 See UDAQ response a) to Public Comment 8).
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 6 of 8

[I]f a problem arises resulting in an immediate need for repairs, modification, or
replacement that would trigger the requirements of the boiler rules, significant
timing and cost problems could arise and, in many or all of these situations, it will
be impossible to comply instantaneously as the rules would suggest the need to
do. The final rules must explicitly accommodate these situations.

For example, if an unexpected situation results in damage to burners or other need
to replace burners quickly, refineries need the time to conduct engineering
analyses, design the required changes, procure equipment, and install the
changes. The refinery might need to replace burners i n-kind or perhaps even with
a similar but not identical design in the interim while it conducts these other
activities.

If an alternate means of control will require approval from UDAQ because the new
design cannot achieve 9 ppm NOx, additional time will be needed to accommodate
discussions with the agency and agency approval, followed by the time needed to
design, procure, and install the new burner system (or boiler, if the changes require
replacing the boiler).

Installing the repairs, modification, or replacement might require a shutdown of all
or portion of the facility. If not done as part of a planned turnaround, this would
likely incur a significant lost profit opportunity, a large cost not incorporated into the
boiler rule economic analysis. Furthermore, for petroleum refiners, any
unscheduled shutdown also reduces the supply of gasoline and diesel in markets
that are already tightly constrained, potentially causing gasoline and diesel
shortages and/or price increases.

These situations might be avo ided by allowing in -kind or temporary repairs or
replacements in the interim [obviously while also requiring diligent efforts to work
with UDAQ on implementation of the rule or an alternate means of control] until the
final design can be installed during a planned outage.

The RTC indicates that the rule already accommodates these situations through the
alternate means of compliance. However, given the constraints for the alternate means
to achieve BACT or equal air quality benefit, we do not see how this provision could be
used to allow installation of in-kind or similar burner replacements during the interim period
needed to design, negotiate a final alternate means of compliance, procurement,
construction, and startup. Furthermore, the time required by these activities may well
exceed the 180 days allowed for a temporary boiler.

If UDAQ was referring to enforcement discretion as a way to allow a facility to operate with
in-kind or similar burner replacements to provide the time needed to conduct the
necessary activities, we do not consider enforcement discretion to be a viable means
to plan and provide for compliance assurance, as companies are obligated to do .

Furthermore, while we appreciate the extension of the compliance date to May 2024, even
this will not address the need. Technology changes constantly and burner technology
continues to evolve. Any design developed over the next year, prior to the May 202 4
compliance date, would likely be inadequate in future years; the more time that passes
between now and the future time of need, the less adequate a design developed now
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 7 of 8

would be and the less likely that an appropriate alternate means of compliance could be
based on a design developed during the next year.

Therefore, we reiterate our recommendation that the final rules accommodate
situations where a facility cannot comply instantaneously upon triggering the
requirements.

One approach would be for the rules to state that in the case of triggering the rule due to
an unplanned event and upon approval by UDAQ, a facility may install in -kind or similar
burner replacements for a to -be specified period to allow the facility to undergo design,
procurement, construction, and, if appropriate, agreement with UDAQ on an alternate
means of compliance.

13. Cost for Rule Implementation – In our comments letter on the proposed rules, we indicated
that, “The economic analysis for the rules significantly underestimates costs in some
situations and these substantially higher costs need to be acknowledged.” Although the
RTC identifies this comment, the response misses the point. The response identifies that
UDAQ added the alternate method of compliance in response to these co sts. However,
UDAQ has never acknowledged the actual cost estimates in the written record for
the rulemaking and that is what this comment seeks. The Associations believe this to be
important to justify the alternate method of compliance and ensure that all stakeholders
have the opportunity to fully understand its necessity.

As stated in our comments, documentation for the PM 2.5 Best Available Control
Technology (“BACT”) analyses by both individual facility and by UDAQ shows costs as
high as $40,000 to $80,000 per ton of emissions reduced for ultra -low NOx burners,
whereas the RTC, board memos, and rule analyses only acknowledge costs up to $26,000
per ton of emissions reduced.

Our Advance Notice comments letter explains why these costs may be so high in some
cases, that burners cannot simply be swapped out for burners of different technology , but
the entire firebox may require redesign and reconstruction . We reiterate from our
comments letter on the proposed rules:

[T]hese cost estimates illustrate the importance of including the alternate method
of control in the rules. Cost effectiveness this high lies far outside the realm of the
intended purpose of the boiler rules.

UDAQ must acknowledge these higher cost estimates and their legitimacy
vis-à-vis the boiler rules by discussing these estimates in the rulemaking
record. These cost estimates justify the need for the alternate method of control
and clearly illustrate why this provision cannot be omitted from the rulemaking.
[emphasis added]

Once again, we request a robust discussion of the substantially higher costs that replacing
burners may have in some instances in the RTC.

In conclusion, we find that the errors in rule language and references, the remaining ambiguities,
and the significant comments left unaddressed and not discussed in the RTC or where the RTC
misses the point of the comment, collectively justify postponing adoption of the boiler rules to
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 8 of 8

provide UDAQ with sufficient time to address these issues. Considering that the rules have an
effective date of May 2024, we see no harm in taking this extra tim e to ensure the rules are clear
and support implementation and enforcement. We understand that this may result in the need
for an additional public comment period. Considering the importance of these issues and the
number of significant changes to the ru les, providing an additional comment period may be
appropriate and justified.

Sincerely,

Rikki Hrenko-Browning Brian Somers
President, Utah Petroleum Association President, Utah Mining Association

cc: Becky Close - [e-mail]
Ryan Bares - [e-mail]

Attachment: Comments Letter on Proposed Ru les

February 15, 2023

Bo Wood
Ryan Bares
Mat Carlile
Utah Division of Air Quality
P.O. Box 144820
Salt Lake City, Utah 84114 -4820

Submitted by email to [e-mail], [e-mail], and [e-mail]

Subject: Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers
Greater than 5.0 MMBtu and 2.0-5.0 MMBtu

Dear Mr. Bares, Mr. Wood, and Mr. Carlile:

On December 7, 2022, the Air Quality Board (“AQB”) approved for proposal two boiler rules,
R307-315 and R307-316, NOx Emission Controls for Natural Gas-Fired Boilers 2.0-5.0 MMBtu
and greater than 5.0 MMBtu , respectively, (collectively, “proposed boiler ru les” or “boiler rules”).
Subsequently, Utah published notice of the comment period in the Utah Bulletin 1 and the Utah
Division of Air Quality (“UDAQ”) provided notice on their webpage of the open comment period.2

The Utah Petroleum Association (“UPA”) and the Utah Mining Association (“UMA”) (jointly, “the
Associations”) appreciate the opportunity to provide these comments on the proposed boiler rules.

Thank you for addressing many of our comments from our prior letter sent in response to the
Advance Notice of the rulemakings 3 and for meeting with us to discuss the boiler rules and
UDAQ’s intent. These discussions help ed the Associations to conform our comments to better
address UDAQ’s intent. Furthermore, we believe that dialogue to better understand each other’s
positions leads to the best rulemakings considering enhanced technical feasibility and cost-
effectiveness. We refer to our Advance Notice Comments in several places in this comment
letter, and we attached a copy for your convenience.

1 Utah State Digest, January 15, 2023, Volume 2023, Number 02, pp. 16 and 1, respectively.
2 Rules Open for Public Comment, NOx Emission Controls for Natural Gas -Fired Boilers, located at
https://deq.utah.gov/public-notices-archive/air-quality-rule-plan-changes-open-public-comment (accessed
on January 17, 2023).
3 Letter, Rikki Hrenko-Browning and Brian Somers to Ryan Bares, Comments Regarding Advance Notice
of Rulemaking for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters, October 17, 2022
(“Advance Notice Comments”),
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 2 of 14

UPA is a statewide oil and gas trade association established in 1958 representing companies
involved in all aspects of Utah’s oil and gas industry. UPA members range from independent
producers to midstream and service providers, to major oil and natural gas companies widely
recognized as industry leaders responsible for driving technology advancement resulting in
environmental and efficiency gains. Five member companies each operate a petroleum refinery
in the Northern Wasatch Front ozone nonattainment area (“NWF”). Additionally, UPA member
companies operate oil and gas production and midstream facilities within the Uinta Basin ozone
nonattainment area. Thus, our member companies have an interest in air quality and air
emissions controls throughout Utah.

UMA was founded in 1915 and serves as the voice of Utah’s mine operators and service
companies which support the mining industry. The member companies operate hardrock,
industrial mineral, and coal mines throughout the State of Utah. UMA has an interest in air quality
in support of the communities in which our member companies operate and air emissions controls
in Utah.

Although the proposed boiler rules have not been proposed to be applicable in the Uinta Basin
ozone nonattainment area, considering the air quality and the nonattainment status of the Uinta
Basin, it is possible that UDAQ may consider extending the rules to the Uinta Basin in the future.
For the most part, our comments consider operations in the NWF. In the case of the definition of
“natural gas”, our comments also consider potential future extension of the rules to the Uinta
Basin.

Our comments speak primarily to the large boiler rule except as noted but are intended to address
both the small and large boiler rules similarly.

As explained in our Advance Notice Comments, we support the applicability of the proposed boiler
rules to the full counties of the NWF and Southern Wasatch Front ozone nonattainment areas.4
The NOx from boilers in the five counties proposed for applicability of the proposed rules
constitutes approximately 8% of the locally generated NOx in the five counties, and UDAQ staff
estimates that over 80% of this NOx can be red uced by implementing these rules.5 Extending
the rules to the full five counties will help to maximize any reduction in locally formed ozone.

We also support the addition of the alternate method of control, exemption for temporary boilers,
and the requirements trigger of replacing 50% of the burners in a boiler having more than one
burner. Please refer to our Advance Notice Comments for justification.

In summary, the Associations have the following comments on the proposed rules:

• The final rules must accommodate changes to the implementation schedule for situations
when the facility cannot comply instantaneously upon triggering the requirements.

4 See Advance Notice Comments, Recommended #8 and associated discussion.
5 For total emission inventories, see Marginal Ozone Inventory, Southern Wasatch Front, June 2020, and
Marginal Ozone Inventory, Southern Wasatch Front, June 2020, both attached to letter, Governor Gary R.
Hebert, Governor, Utah to Gregory Sopkin, US EPA Region 8 Administrator, July 29, 2020. For emission
reductions expected from the proposed boiler rules, see Board Memo dated November 22, 2022,
PROPOSE FOR PUBLIC COMMENT: New Rules R307-315. NOx Emission Controls for Natural Gas-
Fired Boilers 2.0-5.0 MMBtu; and R307-316. NOx Emission Controls for Natural Gas-Fired Boilers greater
than 5.0 MMBtu, Ryan Bares through Bryce C. Bird to Air Quality Board.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 3 of 14

• The alternate method of control language needs additional clarifications.
• Substantially higher costs to replace burners with ultra -low NOx burners as documented
in the Best Available Control Technology (“BACT”) analyses for major sources under the
PM2.5 Serious State Implementation Plan (“SIP”) need to be acknowledged .
• The rules should define “natural gas” to mean pipeline quality natural gas and not other
gases.
• The rules should explicitly exclude CO Boilers at petroleum refineries.
• The rules need to include a definition for “waste heat boiler”.
• The entire “boiler” definition should be written into the rules.
• The definitions for “construction” and “modification” need to be narrowed.
• The definition or expectations for “certification” need to be clarified.
• The meanings of the terms “industrial”, “commercial”, and “institutional” are not clear.

We describe our comments in detail below.

1. The final rules must accommodate situations where a facility cannot
comply instantaneously upon triggering the requirements.

The compliance schedules for the boiler rules begin on May 1, 2023. When a petroleum refinery
wishes to upgrade a boiler or replace one as part of the normal course of business during a
planned turnaround, this timing poses no problem ; the requirements of the boiler rules would be
triggered at the time of modification. In other words, the modifications would coincide with the
timing of when the boiler must meet the requirements of the proposed rules . On the other hand,
if a problem arises resulting in a n immediate need for repairs, modification, or replacement that
would trigger the requirements of the boiler rules, significant timing and cost problems could arise
and, in many or all of these situations, it will be impossible to comply instantaneously as the rule s
would suggest the need to do.6 The final rules must explicitly accommodate these situations.

For example, if an unexpected situation results in damage to burners or other need to replace
burners quickly, refineries need the time to conduct engineering analyses, design the r equired
changes, procure equipment, and install the changes. The refinery might need to replace burners
in-kind or perhaps even with a similar but not identical design7 in the interim while it conducts
these other activities.

If an alternate means of control will require approval from UDAQ because the new design cannot
achieve 9 ppm NOx, additional time will be needed to accommodate discussions with the agency
and agency approval, followed by the time needed to design, procure, and install the new burner
system (or boiler, if the changes require replacing the boiler).

Installing the repairs, modification, or replacement might require a shutdown of all or portion of
the facility. If not done as part of a planned turnaround, this would likely incur a significant lost
profit opportunity, a large cost no t incorporated into the boiler rule economic analysis.8
Furthermore, for petroleum refiners, any unscheduled shutdown also reduces the supply of

6 Please refer to Advance Notice Comments, Recommendation #1.1 and associated discussion.
7 For example, identically designed burners might not be available at the time.
8 Typically, planned turnarounds on refinery process units occur on a three to five year schedule,
depending on the process unit(s) involved.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 4 of 14

gasoline and diesel in markets that are already ti ghtly constrained, potentially causing gasoline
and diesel shortages and/or price increases.9

These situations might be avoided by allowing in -kind or temporary repairs or replacements in the
interim until the final design can be installed during a planned outage.

The operator might install a temporary boiler in the meantime, but a temporary boiler can only be
used for up to six months, which may not provide enough time .

During our discussions with UDAQ, the breakdown rule was mentioned as a po tential option;
however, member companies generally do not consider this rule to be a viable option as it relies
on the Director granting enforcement discretion on a case-by-case basis.10 Reliance on
enforcement discretion puts the facility at significant risk of noncompliance. Member companies
as a matter of policy will not plan to rely on enforcement discretion to assure compliance with
situations that may be anticipated. The operator must be allowed to replace burners in -kind and
to perform other in-kind or temporary repairs in the meantime, to allow sufficient time for the
above-mentioned activities.

Considering the potential need to conduct the repairs, modification, or replacement during a
planned turnaround and the costs of incurring an unplanne d or extra turnaround , the rules must
accommodate in-kind repairs or temporary replacements to be installed for up to five years after
triggering the requirements of the boiler rules to accommodate the timing needs.

If UDAQ is reluctant to allow this need ed time outright in the rules, perhaps a provision could be
added to the rules to allow time to come into compliance on a case -by-case basis. If allowed on
a case-by-case basis, the rules should describe criteria for approval. In deciding whether to grant
a case-by-case extension for compliance, we recommend that that UDAQ consider the time
needed for engineering, design, procurement, construction, and agency approvals of alternate
compliance methods, if needed, as well as the normal planned turnaround schedule of the facility.
The criteria for granting a case-by-case extension should be documented in the rules or, at a
minimum, in the response to comment for the rulemaking. Otherwise, it is subject to changing
interpretations over time, which will result in unacceptable compliance uncertainty.

2. The alternate method of control language needs to be further clarified.

UDAQ appreciates the addition of R307-316-4(8) providing an “alternate method of control” to the
9 ppm NOx limitation.

The phrase “best achievable level of control available” (“BALOCA”) needs to have appropriate
boundaries drawn around it. As written, it has no clear regulatory meaning.

We recommend replacing BALOCA with the term “Best Available Control Technology” (“BACT”).
The intended purpose of the rulemaking is to apply BACT on all boilers, evidenced by the
incremental costs determined by UDAQ for burner upgrades .11 Therefore, using BACT as the

9 Typically, a petroleum refinery implements plans in advance of planned turnarounds to enable
maintaining product supplies through the turnaround, but there may not be enough time to implement
plans to maintain product supply for an unplanned outage.
10 See R307-107. General Requirements: Breakdowns.
11 See “Fiscal Analysis Statement” in the “Fact Sheet: Natural Gas-Fired Boilers; 2 - 5 MMBtu” issued with
the Advance Notice request for comment. The range of costs shown fall within the traditional definition of
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 5 of 14

term for the level of control that a case-by-case analysis must achieve will ensure that the case -
by-case sources do not have to take on a greater burden for rule compliance than all other
sources. Furthermore, BACT has a clear regulatory meaning that considers both econom ic and
technical reasonableness, concepts that were incorporated into the rulemaking and should be
similarly incorporated into the alternate method of control.

In the past, in R307-327-7(1), the Environmental Protection Agency (“EPA”) required its approval
for case-by-case evaluations of alternate methods of control. That rule was developed many
years ago and does not clearly specify the RACT or BACT level of control . EPA and states have
far more experience now with RACT and BACT calculations and, similar to BACT calculations for
a permit, there is no need for express EPA approval of a case-by-case BACT analysis to define
an alternate method of control for a specific process unit . Nothing in the Clean Air Act would
require this level of interaction from EPA during the implementation of the Boiler rules. Therefore,
it would be unreasonable for EPA to apply such a requirement.

The alternate method of control should clarify that it does not require add -on controls other than
burners if they cannot be shown to be comparably cost effective. This rulemaking addresses
burners only and does not address other add -on controls which, typically, are more costly and
less cost effective.

Thus, we recommend changing the wording of R307-316-4(8) as follows:

Any person may apply to the director for approval of an alternate method of control. The
application must include a demonstration that the proposed alternate produces an equal
air quality benefit as required by Subsection R307 -316-4(2) or the best achievable level
of control available meets the Best Available Control Technology level of control
considering technical and economic reasonableness . Unless a means of control other
than burner technology can be shown to be equally or more cost-effective, nothing in this
rule requires consideration of add -on controls other than burners.

In addition, we recommend including a similar option in the small boiler rule. Considering
concerns raised by the American Boiler Manufacturers Association, the possibility exist s that
some small boilers may not be able to achieve 9 ppm or at least without a trade -off in increased
fuel. We do not see where the cost of this tradeoff was incorporated into the economics for the
rulemaking.

3. The economic analysis for the rules significantly underestimates costs in
some situations and these substantially higher costs need to be
acknowledged.

The rule analysis indicates a cost between $13,000 and $26,000 for the cost to use burners rated
for 9 ppm NOx as retrofits, for a 6.7 MMBtu/hour standard boiler. However, this cost does not
recognize the far greater costs associated with individual burner retrofits for larger, more complex
industrial boilers. For example, the individual case -by-case BACT analyses submitted by major
sources for the SLC PM2.5 Serious Nonattainment SIP indicate costs well above $40,000 per ton

BACT and likely apply to the vast majority of boilers for which the boiler rules would be applicable. While
the published rule analysis for the formal comment period indicates cost ranges up to much higher dollar
amounts, the high end of the range would not meet the economic reasonableness standard for BACT and
likely indicate facilities that may seek the alternate method of control.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 6 of 14

of NOx reduced.12 Even UDAQ’s PM2.5 BACT report states that replacement costs start at
$29,489 for a 30 MMBtu/hour boiler to $37,508 for a 15 MMBtu/hour boiler for 8,760 hours of
operation per year and $64,581 for a 30 MMBtu/hour boiler to $82,142 for a 15 MMBtu/hour boiler
for 4,000 hours of operation per year .13

As individual case -by-case cost estimates, these values represent the most legitimate costs for
these process units, considering physical and operational constraints specific to the process unit.
These much higher cost estimates were developed in 2017, and would likely be even higher
today. Considering the actual inflation rates as well as the effects of the labor and supply chain
shortages, capital construction costs have risen considerably since 2017.

Furthermore, these cost estimates illustrate the importance of including the alternate method of
control in the rule s. Cost effectiveness this high lies far outside the realm of the intended purpose
of the boiler rules.

UDAQ must acknowledge these higher cost estimates and their legitimacy vis -à-vis the boiler
rules by discussing these estimates in the rulemaking record. These cost estimates justify the
need for the alternate method of control and clearly illustrate why this provision cannot be omitted
from the rulemaking.

The Board memo for the proposal states that “staff recognizes that within this large range of
boilers, there is a substantial array of applications within industry, and that there will be instances
where it may not be either technologically or financially feasible to meet this emission standard.”
While the statement recognizes that costs may be higher than quoted in the rule analysis or Board
memo, it falls short of recognizing the substantially higher costs documented in the PM 2.5 BACT
analyses.

We request that UDAQ document in the Board memo, the rule economic analysis, and the
response to comment the very substantial costs to upgra de burner NOx technology as
documented by major sources and by UDAQ in the PM2.5 BACT analyses.

4. The rules should define “natural gas” as pipeline quality natural gas to
avoid unintended consequences of broader definitions.

In the Advance Notice Comments, the Associations indicated that the rules should apply only to
those boilers burning pipeline quality natural gas and the rules should include a corresponding
definition of natural gas. We recommended modeling a definition provided in the South Coast
Rule 1109-1, a rule that UDAQ used to model these Boiler rules.

The South Coast definition is simple:

12 See individual facility “Point Source Control Strategies by Source-Specific BACT Analysis” posted on
UDAQ website at https://deq.utah.gov/air-quality/control-strategies-serious-area-pm2-5-sip (accessed on
February 11, 2023). See, for example, Chevron costs of $54,767 and $43,095/ton for two boilers (Table,
Summary of UNLB Costs for Boiler #5 F11005 and Boiler #6 F11006, page 8) and U of U cost of
$109,755 per ton for a boiler 87.5 MMBTU/hr (Appendix A).
13 Appendix A, BACT for Various Emission Units at Stationary Sources, DAQ-2018-00716, located at
https://documents.deq.utah.gov/air-quality/pm25-serious-sip/DAQ-2018-007161.pdf (accessed on
February 11, 2023), p. 40.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 7 of 14

NATURAL GAS means a mixture of gaseous hydrocarbons, with at least 80 percent
methane (by volume), and of pipeline quality, such as the gas sold or distributed by any
utility company regulated by the California Public Utilities Commission.

Adapting the definition to Utah would require only changing to the Utah Division of Public Utilities.

However, the proposal includes a definition copied from the Boiler MACT rule 14. We understand
that UDAQ chose this definition to allow for inclusion of propane and liquified propane gas (LPG)
within the covered fuels. We question the validity of including propane fueled boilers within the
rules because we are not aware of any technical analysis performed to justify the required NOx
level when burning propane. In fact, UDAQ’s 2023 analysis for Reasonably Available Control
Measures (“RACM”) indicates that there are “n o known control measures” for industrial boilers
using liquified petroleum gas.15

Furthermore, the Associations do not agree with using the Boiler MACT definition which has an
entirely different purpose, defining units not covered by the rule rather than defining units covered
by the rule. Moreover, the Boiler MACT regulates Hazardous Air Pollutants (“HAPs”) and not
NOx, regulates only smaller area sources, and does not regulate any uni ts fired with gas of any
type. In other words, the purpose of the Boiler MACT definition of natural gas has no similarities
whatsoever to the purpose of a definition of natural gas for the boiler rules.

Specifically, UPA has concerns with using the Boiler MACT definition of natural gas because this
definition could, in some circumstances, include refinery fuel gas, which, as explained in our
Advance Notice Comments, cannot achieve 9 ppm due to its higher hydrogen content. Varying
analytical composition of refinery fuel gas could also affect NOx levels.16

UPA also has concerns that the Boiler rules could at some future date be extended to the Uinta
Basin ozone nonattainment area, where raw natural gas, not of pipeline q uality, is used to power
significant amounts of equipment. Further studies would be needed to determine the degree to
which raw natural gas with its varying properties and quality could potentially meet the specified
NOx levels. At this time, we know of no such studies. Extending the boiler rules to equipment
fired by raw natural gas would not be appropriate.

The Associations continue to recommend that the definition of natural gas in the South Coast rul e
be adopted and adapted for Utah. Use of this definition addresses both of our concerns, that of
high hydrogen content of refinery fuel gas forming more NOx emissions and that of unknown NOx
emissions from burning raw natural gas (not pipeline quality).

If UDAQ believes that it can properly include boilers fired by propane or combinations of natural
gas and propane, UDAQ could further adapt the definition similar to the following:

NATURAL GAS means a mixture of gaseous hydrocarbons, with at least 80 percent
methane (by volume), and of pipeline quality, such as the gas sold or distributed by any
utility company regulated by the California Public Utilities Commission Utah Public Utilities

14 40 CFR Part 63 Subpart JJJJJJ (“Boiler MACT” or “Boiler MACT rule”).
15 Northern Wasatch Front Area Source Reasonable Available Control Measures (RACM) Analysis for
Ozone Control Technical Supporti ng Document (TSD) 2023, located on UDAQ website at
https://documents.deq.utah.gov/air-quality/planning/DAQ-2023-001246.pdf (accessed on February 11,
2023), VOC RACM Assessment Summary table, p. 7.
16 See Advance Notice Comments and, in particular, recommendation #1.3 and associated discussion.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 8 of 14

Division (“pipeline quality natural gas”) or Liquefied petroleum gas, as defined by the
American Society for Testing and Materials in ASTM D1835 (incorporated by reference,
see § 63.14) or propane or propane-derived synthetic natural gas, or mixtures thereof.

Added definition:
Propane means a colorless gas derived from petroleum and natural gas, with the
molecular structure C3H8.

5. The rules should explicitly exclude coverage of CO Boilers at petroleum
refineries.

The Associations’ Advance Notice Comments discuss our concerns about NOx emissions from
refinery CO boilers, which receive much of their NOx from combusting coke or carbon buildup on
the catalyst in the regenerator of the Fluid Catalytic Cracker (“FCC”) and/or from burning excess
CO in the CO boiler. CO Boilers receive part of their fuel as FCC regenerator off -gas which
contains NOx unaffected by the burners.17

We surmise that UDAQ did not explicitly exclude CO boilers based on an understanding that
these boilers burn FCC regenerator off-gas and an erroneous belief that they do not also burn
refinery fuel gas and/or natural gas. However, CO boilers commonly burn supplemental refinery
fuel gas and/or natural gas during normal operation and at other times such as during startup.
This supplemental gas could subject the CO boiler to applicability with the proposed rules as
currently written.

Therefore, we reiterate our recommendation to explicitly exclude CO boilers from the rules.

6. We reiterate our recommendation to include the entire Boiler definition
from Boiler MACT, adapted to UDAQ’s purposes, within these Boiler rules.

As stated in our Advance Notice Comments, reliance on a definition from a rule with an entirely
different purpose, namely, to control hazardous air pollutants (“HAPs”) rather than NOx, to control
only smaller area source boilers, and to exclude from control any boiler fired with gas of any kind,
raises concerns about whether the definition could change in undesirable ways in the future
without regard to its use in these rules intended to control NOx in natural gas fired boilers of all
sizes.

For example, exemptions could be added or deleted from the Boiler MACT definition in the future
without regard to what the exemptions mean to NOx emissions.

Furthermore, the Boiler MACT rules co ntain various exemptions within and outside of the
definition of Boiler. By not including the full definition and associated exemptions within the Utah
boiler rules, the rules lack clarity as to which boilers were meant to be included and which were
meant to be excluded.

We understand that UDAQ intended its rules to address only standard boilers of varying sizes
and firing natural gas (and possibly propane or LPG) and not equipment of any other kind. We
agree with this approach, as it excludes any other equipment of unknown ability to meet the NOx
requirements of the Boiler rules.

17 See Advance Notice Comments, recommendation #3.3 and associated discussion.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 9 of 14

We support UDAQ’s inclusion of an exemption for temporary boilers within the applicability of the
Boiler rules and we support the definition of temporary boiler included.18

We recommend including the following definition s within the Utah Boiler rules (we have shown
changes to the Boiler MACT definition with redlines and strikeouts):

Boiler means an enclosed device using controlled flame combustion of natural gas [or
mixtures of natural gas with LPG or propane] in which water is heated to recover thermal
energy in the form of steam and/or hot water. Controlled flame combustion refers to a
steady-state, or near steady-state, process wherein fuel and/or oxidizer feed rates are
controlled. A device combusting solid waste, as defined in § 241.3 of this chapter, is not a
boiler unless the device is exempt from the definition of a solid waste incineration unit as
provided in section 129(g)(1) of the Clean Air Act. Waste heat boilers, process heaters,
CO Boilers in a petroleum refinery, temporary boilers, and autoclaves are excluded from
the definition of Boiler.

Process Heater means an enclosed device using controlled flame, and the unit's primary
purpose is to transfer heat indirectly to a process material (liquid, ga s, or solid) or to a heat
transfer material (e.g., glycol or a mixture of glycol and water) for use in a process unit,
instead of generating steam. Process heaters are devices in which the combustion gases
do not come into direct contact with process materials. Process heaters include units that
heat water/water mixtures for pool heating, sidewalk heating, cooling tower water heating,
power washing, or oil heating.

Waste Heat Boiler means a device that recovers normally unused energy (i.e., hot exhaust
gas) and converts it to usable heat. Waste heat boilers are also referred to as heat
recovery steam generators. Waste heat boilers are heat exchangers generating steam
from incoming hot exhaust gas from an industrial (e.g., thermal oxidizer, kiln, furnace) or
power (e.g., combustion turbine, engine) equipment. Duct burners are sometimes used to
increase the temperature of the incoming hot exhaust gas.

We further recommend that UDAQ examine the exclusions in 40 CFR §63.11195 addressing “Any
boilers not subject to this subpart” to determine if UDAQ wishes to incorporate any additional
exclusions from the Boiler definition.19

7. The Associations recommend narrower definitions for “construction” and
“modification” that limit applicability to changes in NOx emissions due to
physical changes in the boiler.

The Advance Notice version of the Boiler rules did not include definitions of “construction” and
“modification” and the Associations therefore recommended adding definitions to these rules
because those provided in UDAQ’s General rules did not seem to suit the purpose of the Boiler
rules.20

UDAQ included the following definitions in the proposed boiler rules:21

18 See Advance Notic e Comments, recommendation #3.2 and associated discussion.
19 For example, UDAQ may wish to exempt residential boilers.
20 See R307-101, General Requirements.
21 See proposed R307-316-3, Definitions.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 10 of 14

“Construction” means any physical change or change in the method of operation including
fabrication, erection, installation, demolition, or modification of a source which would result
in a change in actual emissions.

“Modification” means any planned change in a source that results in a potential increase
of emission.

These definitions are far too broad to fit the purpose of these boiler rules and are more suited to
New Source Review or Prevention of Significant Deteriorat ion air permitting.

For example, under the proposed definitions, a change in the method of operation would trigger
the boiler rules applicability, which does not align with the stated concepts on which UDAQ
evaluated the boiler rules, namely changing a boiler or changing one or more burners in a boiler.
If changes in method of operation had been intended to be included in the rule s, then economics
should have been calculated on burner changeout compared to no burner changeout, but were
instead based on incremental costs to install an ultra-low NOx burner (“ULNB”) compared to a
standard burner. This difference in approach for the rule economics makes a significant
difference in the economic reasonableness determination.

The term source has a much broader definition in R307 -101-2, and applies to “all of the pollutant-
emitting activities which belong to the same industrial grouping ” but should be limited in the
context of these Boiler rules to only the boiler. Again, if UDAQ meant for changes to the entire
source to potentially trigger the requirements of the proposed boiler rules, the economics of the
rules should have been determined on a different basis.

A change in actual emissions could mean an increase or decrease and should be limited to an
increase only. Moreover, a change in actual emissions should be limited to NOx emissions.

Both “construction” and “modification” should have the same basis, i.e., increase in actual NOx
emissions.

We recommend the following changes to the definitions:

“Construction” means any physical change or change in the method of operation including
fabrication, erection, installation, demolition, or modification of a source boiler which would
result in a change an increase in actual NOx emissions.

“Modification” means any planned change in a source boiler that results in a potential an
increase of actual NOx emissions.

Alternatively, UDAQ could use a variation on the definitions included in 40 CFR Part 60 for New
Source Performance Standards, similar to our original recommendation to the Advance Notice:22

Construction means fabrication, erection, or installation of an a ffected facility.23

22 See Advance Notice Comments, recommendation #4.1 and associated discussion.
23 Definition from 40 CFR Part 60 §60.2.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 11 of 14

The Associations prefer this second option due to the years of interpretive history behind the
meaning of the definition, and because it appears to suit the purpose of these rules the most
closely, that is, that physical changes in the boiler (affected facility) constitute construction.

The Associations also note that the proposed rules do not include the term “reconstruction” which
had been included in the Advance Notice version. We agree that this term does not need to be
included because the above definitions accommodate reconstruction. However, should UDAQ
include the term in the final rules, we recommend including a definition that follows the principles
outlined above in that it be congruent with the rule analysis and limited in scope to NOx emissions
due to physical changes in a boiler.

8. R307-316-4 needs more clarification regarding what is required for a boiler
or burner manufacturer to “certify” the boiler or burner as complying with
the “emission rate” in R307-316-4(2) and clarification of other aspects as
well.

We reiterate our questions of the Advance Notice Comments regarding a manufacturer burner
certification:24

• What would be entailed in a certification?
• Would a simple manufacturer quote of expected NOx emissions be sufficient?
• What would be needed to turn the quote into a “certification”?
• What if the quote of anticipated NOx emissions level was based on an example fuel gas
composition but the composition changes over time?

Manufacturers typically provide an emissions estimate based on a set of assumptions about the
quality of the gas and operating conditions. Would this type of conditional emissions estimate
qualify as a certification?

These questions must be addressed in the final rules.

Manufacturers typically will not certify to a time period. We appreciate that the averaging period
was increased from 15 minutes to 24 hours, a more appropriate time fr ame considering the diurnal
cycle of ozone formation during the heat of the day. However, since burner manufacturers will
not guarantee emissions on an averaging period, and these rules rely on the manufacturer
certification, we recommend that the averagi ng period be removed entirely. Otherwise, boiler
operators will not be able to comply in the intended manner. We understand that this could result
in misconstruing compliance to be required on an instantaneous time period basis but careful
wording that this applies only to the manufacturer certification can address this concern.

We also have concerns about incongruency between the averaging period for the rule and the
test method for boilers > 40 MMBtu/hr. The test method should remain at its method -sp ecified 3-
hour period. The test method should be identified as the method of compliance for these larger
boilers.

We recommend clarifying that R307-316-4(1)(b) applies to boilers with only a single burner. As
written, (c) indicates applicability to boilers with 50% of the burners being changed, and seems to
stand in conflict with (b).

24 See Advance Notice Comments, Recommendation #4.3.
UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 12 of 14

Thus, we recommend the following changes to the rule s:

R307-316-4. Requirements.
(1) Except as provided in Subsection R307 -316-4(8), a person that:
(a) commences construction, or modification of a boiler;
(b) replaces a burner in a boiler with only a single burner; or
(c) replaces 50% or more of the burners in a multi-burner boiler,
for a boiler meeting the requirements of Section R307 -316-2 shall:
(2) Install a burner that is certified to meet a NOx emission rate of nin e parts per million
by volume (ppmv) or less at 3% volume stack gas oxygen on a dry basis averaged over a
24-hour period based on the manufacturer certification of R307-316-4(4).
(3) An owner or operator of a boiler subject to Subsection R307-316-4(1) shall operate
and maintain the boiler and boiler subsystems, including burner(s), according to the
manufacturer’s instructions.
(4) A manufacturer of a boiler or boiler burner meeting the requirement of Subsection
R307-316-4(2) shall certify the boiler or boiler burner as complying with the emission rate
in Subsection R307-316-4(2).
(5) Boilers over 40 MMBtu/hr shall be tested for compliance with the emission limit in
Subsection R307-316-4(2) no less than once every three years using EPA Reference
Method 7E and the compliance test over its normal test-specified duration shall serve as
the means to determine compliance in lieu of a manufacturers certification.
(6) Manufacturer's operational specifications, records, and testing of any control system
shall use the applicable EPA Reference Methods of 40 CFR Part 60, the most recent EPA
test methods, or EPA-approved state methods, to determine the efficiency of the control
device and shall be based on assumptions of the typical normal operation provided by the
owner or operator.
(7) The owner or operator must meet the applicable recordkeepin g requirements for any
control device.
(8) . . . . [see comments above regarding this paragraph]

Added definition:
“Certify” means for the manufacturer to provide certification documentation that the burner
or boiler will achieve 9 ppm NOx under the assumed normal operating conditions specified
by the owner or operator. The “certification” may be in the form of a manufacturer
guarantee, a statement on a quotation, or a letter to the owner or operator that explains
the circumstances for the certification.

9. We recommend wording changes to clarify the rules with respect to its
applicability in industrial, commercial, and institutional settings.

The terms “industrial”, “commercial”, and “institutional” have not been defined, and therefore the
meaning is vague. Various options exist to remedy this:

• The rules could define these terms, perhaps using NAICS groupings as the basis.
• Alternatively, the wording could be changed to “nonresidential”.
• If the rules were intended to apply to multi-family residential settings such as
condominiums and apartments, then applicability could be defined as any setting that is
not single-family residential.

UPA/UMA Comments Regarding Proposed Rulemakings for Natural Gas-Fired Boilers Greater than 5.0 MMBtu and
2.0-5.0 MMBtu
Page 13 of 14

10. Conclusion

The Associations appreciate the opportunity that UDAQ provided for comments at the advanced
notice stage, UDAQ’s consideration of our oral comments delivered at the December AQB
meeting, for meeting with our member companies to discuss concerns about the rule s, and for
consideration of these comments. We are confident that more effective, technically feasible, and
economically feasible rules that will withstand the test of time will result from consideration of our
comments.

Sincerely,

Rikki Hrenko-Browning Brian Somers
President, Utah Petroleum Association President, Utah Mining Association

cc: Bryce Bird – [e-mail]
Becky Close - [e-mail]

Attachment: Advance Notice Commen ts

Attachment I. Advance Notice Comments

Rikki Hrenko-Browning and Brian Somers to Ryan Bares, Comments Regarding Advance
Notice of Rulemaking for Natural Gas-Fired Boilers, Steam Generators, and Process
Heaters, October 17, 2022

October 17, 2022

Ryan Bares
Robert Wood
Utah Division of Air Quality
P.O. Box 144820
Salt Lake City, Utah 84114 -4820

Submitted by email to [e-mail] and [e-mail]

Subject: Comments Regarding Advance Notice of Rulemaking for Natural Gas-Fired
Boilers, Steam Generators, and Process Heaters

Dear Mr. Bares and Mr. Wood:

The Utah Petroleum Association (“UPA”) and the Utah Mining Association (jointly, “the
Associations”) appreciate the opportunity to comment on the Advance Notice of Rulemaking for
Natural Gas-Fired Boilers, Steam Generators, and Process Heaters (“draft Boiler Rules” or “Boiler
Rules”). Thank you for extending the comments due date to October 17, which allowed us to
provide more thoughtful and detailed comments towards developing rules that will be technically
and economically feasible for our member company operations.

UPA is a statewide oil and gas trade association established in 1958 representing companies
involved in all aspects of Utah’s oil and gas industry. UPA members range from independent
producers to midstream and service providers, to major oil and natural gas companies widely
recognized as industry leaders responsible for driving technology advancement resulting in
environmental and efficiency gains. Five member companies each operate a petroleum refinery
in the Northern Wasatch Front ozone nonattainment area (“NWF”). Additionally, UPA member
companies operate oil and gas production and midstream facilities within the Uintah Basin ozone
nonattainment area. Thus, our member companies have an interest in air quality and a ir
emissions controls throughout Utah.

The Utah Mining Association was founded in 1915 and serves as the voice of Utah’s mine
operators and service companies which support the mining industry. The member companies
operate hardrock, industrial mineral, and coal mines throughout the State of Utah. The Utah
Mining Association has an interest in air quality in support of the communities in which our
member companies operate and air emissions controls in Utah.

The Associations and our member companies support rules that will be cost effective
towards improving air quality and that are technically and economically feasible to
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 2 of 19

implement. For example, many of our member companies implemented emission reductions to
meet technically and economically feasible Best Available Control Technology (“BACT”) for the
Serious PM2.5 State Implementation Plan (“SIP”). Furthermore, petroleum refineries are now
supplying Tier 3 gas, thus providing significant benefit to local air quality , considering both PM2.5
and ozone. Similarly, we support this rulemaking with modifications needed to ensure technical
and economic feasibility and added detail for clarity and completeness. In general, the draft Boiler
Rules need broader recognition that not all boilers are the same; the Boiler Rules need a pathway
for larger and more complex industrial boilers to demonstrate compliance.

The concept of a rule that would phase in over a period of time as facilities need to change burners
for operational or maintenance re asons appears like a simple but effective means to phase in a
rule for greatest cost effectiveness and the least amount of operational difficulty, which the
associations appreciate. This may very well be so for smaller commercial and multi-family
residential boilers where a new burner can easily be installed, or the boiler swapped with a new
off-the-shelf commercial boiler. However, due to the complexity of our member company
operations and their boiler systems, this approach raises concerns for our member companies as
described in detail in these comments. Further, the member company Best Available Control
Technology (“BACT”) analysis submitted for the Serious PM2.5 State Implementation Plan (“SIP”)
provide further evidence of much higher costs and, in some cases, lack of technical feasibility.

We understand the rules to be based on swapping a standard or a low NOx burner (“LNB”) for an
ultra-low NOx burner (“ULNB”) whenever a burner needs to be replaced. This is not technically
viable for many large industrial scale boilers as discussed in detail in our comments below. To
address this, we ask that the rules include provision for a case -by-case analysis like the BACT
analysis performed for permits. It would be best to include this option for all boilers to ensure
feasibility in all cases.

Furthermore, for UPA member companies operating their boilers on refinery fuel gas, burner
manufacturers have confirmed that ULNB technology will not achieve 9 ppm, also explained
below in more detail. There may be other instances where 9 ppm cannot be achieved on industrial
boilers, especially with specialty equipment that may be required for certain manufacturing
operations.

Although the title of the rule includes process heaters and steam generators, the rule language
does not include these types of equipment within the applicability . We understand UDAQ’s stated
intent to be to change the title of the rule to apply to boilers only and to leave the applicability
language within the Boiler Rules as is, applying only to boilers and not to other equipment
mentioned in the draft Boiler Rule title. We support this approach with additional case-by-case
paths to compliance as described below. If the rule were to apply to process heaters, the number
of applicable units would increase significantly with an exponential increase in the diversity of
existing equipment that could be subject to retrofits and a variety of additional operating
constraints to work within. In this case, we would have additional comments not included in this
letter. We would need significantly more time to consider the ramifications of broader applicability.

Recommendation #1: The Boiler Rules should include provisions for case-by -case
analysis to set case-by -case NOx limits that are technically and economically feasible for
the individual operation.

Three concerns support the need for this recommendation:
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 3 of 19

1. Burners cannot be easily swapped for burners of different designs.

2. Large industrial boilers have complexities and constraints that drive costs up such that the
cost analyses for the draft Boiler Rules significantly under-represent actual costs
anticipated.

3. The level of 9 ppm NOx may not be technically feasible with current burner technology (or
possibly at all) in many types of industrial boilers including those in petroleum refineries.

We discuss each of these concerns in detail with recommendations .

Although our examples of the need for this provision center on larger industrial boilers, we have
not done an exhaustive search of smaller boilers within our member companies to assess specific
examples of the need for the provision. Therefore, we recommend including the provision in both
Boiler Rules to ensure technical and economic feasibility in all cases.

Recommendation #1.1: The draft Boiler Rules anticipate replacing a single existing burner with
a single ULNBs whenever one or more burners are replaced . However, swapping burners poses
design, safety, and operating problems in industrial boilers that could require significant re -
engineering of the entire firebox at substantially higher cost. This justifies the addition of case -
by-case feasibility analysis to the Boiler Rules.

Burners in large industrial boilers cannot simply be swapped out for ULNBs without extensive
engineering analysis and possible extensive redesign . Boilers and burners in the petroleum
refining industry are subject to three consensus Recommended Practice (“RP”) standards
published by the American Petroleum Institute (“API”) to ensure safety, reliability, and operability:1

• API RP 535, “Burners for Fired Heaters in General Refinery Services” – covers effect of
fuel gas hydrogen content on NOx emissions, flame stability, flame characteristics, retrofit
considerations, maintenance, burner testing, and numerous other pertinent topics.

• API RP 538, “Industrial Fired Boilers for General Refinery and Petrochemical Service ” –
covers important design and safety aspects such as burners and burner management
systems, igniters and igniter management systems, burner arrangements, protective
systems, CO boilers, safety switches, trips, alarms, and numerous other topics.

• API RP 560, “Fired heaters for general refinery service ” – covers numerous design details.

Each of these API RP standards has extensive detail, all of which must be considered and
addressed in boiler design, maintenance, and operation , and must be reconsidered for burner
redesign. In some cases, petrochemical companies also follow API standards.

1 API standards are developed under API’s American National Standards Institute accredited process,
ensuring that the API standards are recognized not only for their technical rigor but also their third-party
accreditation which facilitates acceptance by state, federal, and increasingly international regulators. For
more detail about API standards, see https://www.api.org/products-and-services/standards.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 4 of 19

ULNBs have a longer flame pattern than other burners . These longer flames can impinge on
boiler tubes, flames from other burners, refractory protecting the shell of the boiler f irebox, and
tube hangers within the firebox, thus subjecting the boiler parts to unacceptable damage, safety
concerns, and operability and reliability problems. For example, a communication from the burner
manufacturer John Zink to a member company states , “Flame is expected to be 40-50% longer
than current [burner design] (~23Ft now), which would exceed your furnace dimensions (30.17Ft
furnace depth).” The HollyFrontier Serious PM2.5 BACT report provides additional information:

An additional consideration with retrofitting existing heaters to LNB or ULNB is the flame
pattern. LNB and ULNB generally produce a longer flame in the fire box which can extend
to contact process piping or the convection section of the heater. Contact with process
piping can result in coking of the inside of the process pipes which results in a loss of heat
transfer and eventual plugging. Flame extension into the convection section can result in
heat transfer not consistent with engineered design resulting in process coking,
inadequate heat transfer, heater box temperature, and loss of process control.2

ULNBs may require more space than existing burner s of standard or LNB design and may not fit
within the existing firebox burner area, thereby requiring replacement of the entire boiler unit or
de-rating the boiler due to fitting in fewer burners, an unacceptable choice from an operating
standpoint. The required redesign would decrease cost effectiveness significantly and may not
be feasible due to operating schedules and s pace available to construct the new unit while the
old one operates. It would require rerouting piping and instrumentation at added cost, not included
in the cost analysis, and would need to be estimated on a case-by-case basis. Disruptions to the
operating schedule must be considered as lost profit opportunities within the cost analysis. For
example, the HollyFrontier BACT Report states:

An analysis was performed to evaluate the technically feasibility and cost effectiveness of
upgrading existing process heaters with LNB or ULNB. In conversations with
representatives from John Zink, when upgrading the existing units to LNB or ULNB, the
floor of each heater box would have to be reconstructed to insert the LNB or ULNB which
are typically longer and wider than the existing burners. Also, LNB and ULNB have a lower
heating duty per burner than traditional burners; therefore, in some cases, will result in a
need for additional burners to achieve the firing rate needed for the process application.
Most heaters at HollyFrontier are not designed to accommodate additional burners and
would need to be reconstructed all together. If additional burners cannot be added and
the heater is not reconstructed, then a process rate decrease would need to take pl ace.3

Thus, burners cannot simply be replaced with alternate design burners in many industrial boilers.

Recommendation #1.2: The incremental burner cost estimates for the draft Boiler Rules do not
represent the well-thought-out estimates provided for the PM2.5 BACT analysis, and allowance
must be made for case-by-case cost estimates as part of determining the appropriate NOx levels
in specific situations.

2 “Best Available Control Measure Analyses HollyFrontier’s Woods Cross Refinery ” prepared for
HollyFrontier Woods Cross Refining LLC and prepared by Meteorological Solutions Inc. a Trinity
Consultants Company, April 2017 (“HollyFrontier BACT Report”), p. 4-17. Report available at
https://deq.utah.gov/air-quality/control-strategies-serious-area-pm2-5-sip (accessed on October 11,
2022).
3 HollyFrontier BACT Report, p. 4-17.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 5 of 19

We understand that the cost estimates for the draft Boiler Rules consider replacing only a single
burner with ULNB technology at the time that a burner requires replacement, and thus the cost
estimates for the rule rely on incremental costs for single burner changeout compared to in-kind
replacement costs for the burner. UDAQ cost estimates were all based on small boilers with the
largest at only 6.7 MMBtu/hour ,4 not reflective of many of our member company industrial
operations. On the other hand, our member company boilers may be ten to twenty times larger,
with significant differences in design, operation, and safety considerations. As explained above,
single burners cannot typically be replaced with ULNBs in industrial boilers without re -engineering
the entire firebox.

The cost evaluation provided for the draft Bo iler Rules, based on the incremental cost to replace
a single burner with lower NOx technology, simply does not apply when the burner replacement
triggers a much larger modification of the entire boiler. The cost evaluation would need to
consider the entire redesign, as the Serious PM2.5 BACT analyses do where applicable.

Thus, the incremental cost estimates provided for the rulemaking vary by orders of magnitude
from the actual costs that our member companies expect to face to meet the requirements of the
draft Boiler Rules. Our member companies expect the costs to meet the draft Boiler Rules to be
more in line with cost estimates they provided for the PM 2.5 rulemaking because the retrofits will
be similar, i.e., often requiring complete redesign of the boiler. The PM2.5 BACT cost estimates
are more appropriate for large industrial boilers due to the numerous safety and operability
requirements of these operations that prohibit simply swapping burners.

In 2017, Chevron reported the cost to retrofit two of its boilers at $55,000 and $43,000 per ton of
NOx reduced, costs that consider the site-specific requirements and constraints.5

In cases where LNBs, ULNBs (that may not meet 9 ppm), or even Selective Catalytic Reduction
(“SCR”) have already been installed on a boiler, the current performance of these units with
respect to NOx emissions was not factored into the cost effectiveness determination for the draft
Boiler Rules, and the cost effectiveness of reducing NOx even further will be lower. In comments
provided by the Western States Petroleum Association (“WSPA”) for Best Available Retrofit
Control Technology (“BARCT”) for petroleum refinery boilers and heaters in development of South
Coast Rule 1109.1, WSPA showed that incrementally lower NOx levels carry a dollars per ton
cost effectiveness several times greater than the cost effectiveness of the control.6 UDAQ
recognized this in their Stationary Source BACT Report for the Serious PM 2.5 SIP, where they
show escalating costs per ton to reduce NOx from boilers with lower current NOx levels. The

4 Utah Department of Environmental Quality, “Best Available Control Technology (BACT) Analysis: Ultra -
Low NOx Burners on Natural Gas Fired Boilers” by John Persons, Environmental Engineer II, September
27, 2002.
5 Letter, Christina King, HES Manager, Chevron Products Company Salt Lake Refinery, t o Mr. Martin D.
Gray, Manager, Utah Air Quality Board, April 26, 2017. Attachment entitled “Boiler #1 FI 1001, Boiler #2
F11002, and Boiler #4 FI 1004 BACT Analysis,” table with “Summary of ULNB Costs For Boiler #5
F11005 and Boiler #6 F11006,” p. 8. Available at https://deq.utah.gov/air-quality/control-strategies-
serious-area-pm2-5-sip (accessed on October 11, 2022).
6 Letter, Patty Senecal, Senior Director, Southern California Region, WSPA, to Michael Krause, Manager,
Planning and Rules, South Coast Air Quality Management District, August 4, 2021.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 6 of 19

UDAQ analysis also recognizes the effect of remaining useful life of the boiler and the size of the
boiler on the cost per ton.7

Furthermore, UDAQ’s own cost analyses for its own stationary source PM2.5 BACT analyses far
exceed the costs provided in the memo for larger industrial sources, especially for those units
upgrading from burners that are not standard burners and for units requiring SCR. UDAQ’s
analysis recommends case-by-case BACT, similar to our request here as an option in the Boiler
Rules. The following excerpts from the report illustrate this :8

The economic feasibility analysis demonstrates that retrofit options and boiler replacement
could both be cost effective options depending on the boiler size, age, and hours of
operation. DAQ found through this analysis that SCR was not a cost -effective feasible
option.

Retrofitting or replacing existing low-NOX boilers with ultra-low NOX boilers proved to be
cost prohibitive for the scenarios evaluated. Retrofit costs start at $14,097 per ton of NOX
removed and replacement costs start at $29,489.

DAQ recommends good combustion practices as BACT for the existing boilers operating
at major sources within the nonattainment area. An evaluation to determine whether
retrofitting or replacing boilers with low-NOX or ultra-low NOX burners is economically
feasible should be conducted on a case-by-case basis.

Table 5 of the UDAQ Stationary Source BACT Report provides detail on incremental costs to
upgrade from LNB or ULNB to 9 ppm and an SCR retrofit. LNB replacement costs all exceed
$9,000 per ton of NOx reduced and ULNB replacement costs exceed $8,500 , thus costs are in
excess of the costs provided for the draft Boiler Rules . The table shows ULNB replacement to go
from 30 ppm to 9 ppm with costs exceeding $29,000 and SCR costs exceed ing $19,000.9

It is possible that the relatively low costs per ton of NOx removed reported in the UDAQ staff
analyses for the draft Boiler Rules may be due at least in part to the relatively small boilers
evaluated, less than 7 MMBtu/hr. The University of Utah reports costs of more than $100,000 per
ton of pollutant removed in a boiler of 87.5 MMBtu/hr but does not report any particular operating
constraints for the boiler.10

Additionally, SCR may not be technically feasible in some cases. For example, Big West Oil
provided the following information in their Serious PM2.5 BACT analysis:

7 See Table 5 in “BACT for Various Emission Units at Stationary Sources” DAQ-2018-007161, located at
https://documents.deq.utah.gov/air-quality/pm25-serious-sip/DAQ-2018-007161.pdf (accessed on
October 9, 2022) (“UDAQ Stationary Source BACT Report”) (p. 59).
8 Appendix A, “BACT for Various Emission Units at Stationary Sources” DAQ -2018-007161, located at
https://documents.deq.utah.gov/air-quality/pm25-serious-sip/DAQ-2018-007161.pdf (accessed on
October 9, 2022) (“UDAQ Stationary Source BACT Report”), each of the three quotes are on p. 40.
9 See Table 5. “Summary of Cost per Ton of NOX ($/ton) Removed Continuous Operation (8,760
hours/year)”, UDAQ Stationary Source BACT Report, p. 44.
10 See UCHWTP Boiler NOx analysis in “PM2.5 Serious Nonattainment SIP BACM Analysis” prepared for
the University of Utah, Salt Lake City, Utah, prepared by Trinity Consultants, April 2017, p. 3-10. Report
available at https://documents.deq.utah.gov/air-quality/pm25-serious-sip/DAQ-2017-005321.pdf
(accessed on October 11, 2022).
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 7 of 19

The BACT technology review showed potential additional control technologies including
SCR, flue gas recirculation (FGR), [Wet Gas Scrubber - WGS], and an [Selective Non-
Catalytic Reduction – SCNR]. However, the boilers have insufficient space for installing
SCR, FGR, WGS, or SNCR; therefore, they are technically infeasible.11

Proctor and Gamble provided the following information about technical infeasibility in their Serious
PM2.5 BACT analysis:

An ULNB most commonly uses an internal induced draft to reach the desired emission
limitations. Due to this induced draft, an ULNB cannot handle a quick change in load to
achieve the desired operational flexibility necessary f or the varied products and change
overs in the paper making operation. . . . P&G reviewed potential replacement burner
options with an emission rate of 9 ppm NOx or less that would also meet the same process
demands as the current Paper Machine Boilers. Due to the different types of products
from the paper machines, the Paper Machine Boilers must have ample turndown
capabilities to adjust the amount of steam. Due to the turn down requirements, P&G was
unable to find a burner that would meet this requirement at a lower emission rate.12

Again, we emphasize that since application of current generation ULNBs to existing industrial
boilers could require complete boiler redesign, the PM 2.5 BACT cost and technical feasibility
analyses provide a more appropriate feasibility evaluation for industrial boilers than the single
incremental burner analyses provided by UDAQ.

Recommendation #1.3: The 9 ppm NOx is not feasible in all situations ; case-by-case feasibility
analysis should be allowed within the Boiler Rules as a means to determine an appropriate
technically and economically feasible NOx level for an individual boiler.

Sustained operation at 9 ppm NOx has not been proven to be practicable in large refinery boilers.
For example, a John Zink communication to a member company states, “Retrofitting your current
[low NOx type] to a different ultra -low NOx burner technology that can fire both [natural gas] and
[refinery fuel gas] it is not an option . . . NOx is not expected to be achieved. We estimate
approximately 15 to 17 ppm at the best with FGR [flue gas recirculation].” [emphasis added]

Another member company reports consulting with another burner manufacturer, Zeeco, who
advises that 9 ppm will not be possible for any burner firing on refinery fuel gas with any amount
of hydrogen. They only see that kind of performance out of their best burners when firing 100%
natural gas in a relatively cool firebox.13

11 “Best Available Control Technology Evaluation - Utah PM2.5 State Implementation Plan” report prepared
for Big West Oil Company by Environmental Resources Management; April 2017, p. 10. Report available
at https://deq.utah.gov/air -quality/control-strategies-serious-area-pm2-5-sip (accessed on October 9,
2022).
12 “PM2.5 Serious Nonattainment SIP BACM/BACT Analysis” prepared for The Procter and Gamble Paper
Products Company, Box Elder, Utah, and prepared by Trinity Consultants, April 2017 (“P&G BACT
Report”), pp. 3-20 and 3-21. Report available at https://documents.deq.utah.gov/air -quality/pm25-
serious-sip/DAQ-2017-006104.pdf (accessed on October 11, 2022).
13 As a matter of economics, environmental protection, and practicality, refineries must use their excess
gas as fuel gas and cannot substitute natural gas in lieu of refinery fuel gas. Depending on the refinery
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 8 of 19

Furthermore, the Chevron PM2.5 BACT report provides the following information in its NOx BACT
options for Boilers #5 F11005 and #6 F11006:

ULNBs, the “next generation” burner after the Low NOx Burners (LNBs), alter the air to
fuel ratio in the combustion zone by staging the introduction of air to promote a “lean -
premixed” flame and by means of an internal flue gas recirculation. This results in lower
combustion temperatures and reduced NOx formation. While the boilers were installed
with what could have been considered ULNB technology at the time, further advances in
burner design make lower emissions possible. In new installations, NOx emissions as low
as 0.01 Ib/MMBtu have been achieved. However, based on discussions with relevan t
vendors, for a retrofit application a value of approximately 0.025 Ib/MMBtu is more
realistic.14

0.025 lb/MMBtu equates to approximately 21 ppm, far higher than the proposed level of 9 ppm.

The Serious PM2.5 BACT report for HollyFrontier presents a table of BACT results for process
heaters and boilers nationwide ranging in size from 10 to <100 MMBtu/hr and a second table for
equipment greater than 100 MMBtu/hr. The tables show NOx for units with ULNBs mainly ranging
from 0.025 to 0.040 lb/MMBtu, which equates to a range of approximately 20 to 35 ppm NOx.15

A report prepared by the Fossil Energy Resear ch Corporation developed for the South Coast
rulemaking identifies only two manufacturers of ULNBs that may achieve the levels of NOx sought
in the draft Boiler Rules within petroleum refineries, but neither have conducted full scale tests on
large boilers.16

The FERCO report also identifies that the South Coast Rule 1109.1 intends to require a variety
of different technologies including ULNBs, SCR, and other technologies, rather than only ULNB
burner technology used for the cost estimates provided by UDA Q. As noted above, these other
technologies may or may not be technically or economically feasible and must be evaluated on a
case-by-case basis as was done for the PM 2.5 BACT analysis. If installed, they would add
considerable cost.

Furthermore, South Coast Rule 1109.1 allows until 2034 for implementation, more than ten years
from promulgation , in contrast to the phased implementation of the draft Boiler Rules that may be
triggered at any time. Member companies with facilities in the South Coast jurisdictional area
report they may undergo complete redesign of their boiler facilities, which is well beyond the cost -

configuration, refinery fuel gas contains varying amounts of hydrogen and of heavier components, neither
found in natural gas with refinery fuel gas concentrations.
14 Letter, Christina King, HES Manager, Chevron Products Company Salt Lake Refinery, to Mr. Martin D.
Gray, Manager, Utah Air Quality Board, April 26, 2017. Attachment entitled “Boiler #1 FI 1001, Boiler #2
F11002, and Boiler #4 FI 1004 BACT Analysis” P. 6. Available at https://deq.utah.gov/air-quality/control-
strategies-serious-area-pm2-5-sip (accessed on October 11, 2022).
15 See Table 4-6 and 4-7, “BACT Determinations for N0X from Process Heaters and Boilers with Heat
Capacities between 10 and <100 MMBtu/hr” and “BACT Determinations for NOx from Process Heaters
and Boilers with Heat Capacities >100 MMBtu/hr” respectively, HollyFrontier BACT Report, p. 4-14.
16 “South Coast Air Quality Management District Rule 1109.1 Study Final Report,” prepared for South
Coast Air Quality Management District, prepared by Fossil Energy Research Corporation (FERCO),
November 2020 (“FERCO Report”). See discussion on pp. 3-1 to 3-2.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 9 of 19

effectiveness of this UDAQ rule. In fact, the South Coast NOx requirements were developed over
the course of decades, implementing successively lower NOx requirements through extensive
dialogue and regulatory negotiation between the regulatory agency and the regulated community.

Moreover, we do not consider SCR to be an acceptable alternative where ULNB technology
cannot be deployed or cannot attain 9 ppm under actual conditions.

If SCR were to be required by the UDAQ Boiler Rules, ammonia emissions would increase, the
effect of which would need to be evaluated and considered for wintertime PM 2.5. The FERCO
Report further states that, “Careful SCR design and frequent tuning of injected ammonia and flue
gas will be required in all cases,” to meet the South Coast limits for refinery equipment.17

A member company reports that installing SCR on their several boilers is not feasible due to lack
of space and/or because the flue gas is not hot enough for SCR to work properly on a given boiler.

Procter and Gamble reported the following in their Serious PM 2.5 BACT report:

There are a few other technical considerations with regards to use of an SCR on the
boilers. The need for turndown or modulation of the Paper Machine Boilers load will make
it difficult to maintain the suggested removal efficiencies in practice due to the inconsistent
exhaust stream. . . . The exhaust stream will require additional temperature from the
exhaust stream to meet the SCR operating temperature requirements (minimum of
480°∆F], This increase in exhaust temperature would require an additional combustion
device, also increasing NOx, S02, and PM2.5 emissions. . . . Due to the necessary
turndown requirements of the Paper Machine Boilers, an SCR is considered technically
infeasible for these units.18

Procter and Gamble reported a cost of $165,250 per ton of NOx removed to reduce NOx fr om
just 10 ppm to 9 ppm on the new utility boilers of their Project Maple.19

During the UPA meeting with UDAQ on September 23, there was some discussion about limits
even lower than 9 ppm being required in the South Coast and San Joaquin Valley rules. These
lower levels and, as explained above at times even 9 ppm, often require SC R to achieve. Also
as explained above, SCR would require an entirely different cost and feasibility analysis which
must be done on a case -by-case basis and must consider associated operating costs and other
design and siting constraints. Ultimately, SCR may not be technically feasible or cost effective.
For example, Chevron reported costs of $120,000 and $94,000 per ton of emissions reduced to
retrofit two of its boilers with SCR.20

Some member company facilities both within and outside of Utah have SCR on boilers that cannot
meet 9 ppm NOx including some with low NOx burners in combination with SCR. Limits for these

17 FERCO Report, p. 3-12.
18 P&G BACT Report, p. 3-21.
19 P&G BACT Report, p. 3-22.
20 20 Letter, Christina King, HES Manager, Chevron Products Company Salt Lake Refinery, to Mr. Martin
D. Gray, Manager, Utah Air Quality Board, April 26, 2017. Attachment entitled “Boiler #1 FI 1001, Boiler
#2 F11002, and Boiler #4 FI 1004 BACT Analysis,” table with “Summary of SCR Costs For Boiler #5
F11005 and Boiler #6 F11006,” p. 10. Available at https://deq.utah.gov/air-quality/control-strategies-
serious-area-pm2-5-sip (accessed on October 11, 2022).
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 10 of 19

boilers are near 20 ppm and in at least one case, 40 ppm. The cost effectiveness to achieve 9
ppm in these cases, would be far less than the cost effectiveness provided for the draft Boiler
Rules, if 9 ppm could be achieved at all, and must consider the effect of ammonia slip on
wintertime PM2.5.

The Salt Lake City elevation above sea level of approximately 4200 feet will affect the ability to
achieve the same NOx rates compared to sea level due to the lower partial pressure of oxygen ,
posing an additional barrier to achieving 9 ppm.

Some boilers may have air preheat, which may also make 9 ppm NOx impossible to achieve. Air
preheat saves fuel by using the heat remaining in hot flue gas to preheat the combustion air, but
it increases the NOx concentration in the flue gas, thus resulting in a tradeoff of efficiency and
total amount of emissions versus concentration of emissions. This phenomenon o ccurs because
of the formation of “thermal NOx” from the higher combustion temperatures caused by the air
preheat.21

During periods of high turndown , fluctuating refinery fuel gas composition, and fluctuating heat
input requirements typical in large industrial operations, NOx will fluctuate from the guaranteed
level. Also, whenever a burner must be taken out of service for individual burner maintenance,
the higher firing rate required of other burners could increase NOx emissions.

In summary, due to these many concerns including inability to replace a standard or LNB burner
with an ULNB on a burner-by-burner basis, accurate costs for large industrial boilers, feasibility
(or lack thereof) of achieving 9 ppm NOx, and unique characteristics of refinery fuel gas
combustion, we request that a provision for case -by-case technical and cost feasibility analyses
be included in the Boiler Rules for proposal.

Recommendation #2: The rule should apply only to those boilers burning pipeline quality
natural gas and should include a corresponding definition of natural gas.

The rule contains no definition of natural gas, nor do UDAQ’s definitions in its General Rules 22
include a definition of natural gas. In discussion with UDAQ staff, they did not articulate a clear
definition and thought that it included all types of gas. The staff also referred to the definition of
natural gas in 40 CFR Part 63 Subpart JJJJJJ (“Boiler MACT”). Boiler MACT has a very broad
definition of natural gas that includes propane and mixtures with at least 70 percent methane.23
Relying on this definition would not address our concerns about refinery fuel gas described here.

In general, the Associations do not consider the Boiler MACT definition of natural gas to be
suitable for defining gas burned in boilers in a rule regulating NOx emissions. The Boiler MACT
rule regulates HAP emissions and not NOx. The Boiler MACT definition does not clea rly exclude
refinery process gas. Refinery fuel gas has different characteristics for producing NOx than the
other gases contemplated in the Boiler MACT definition. For example, refinery fuel gas often
contains more hydrogen which burns very hot and incr eases thermal NOx formation. Reaching

21 See https://www.pollutiononline.com/doc/nox-emission-reduction-strategies-0001 (accessed
September 26, 2022).
22 See General Requirements, Definitions in R-307-101-2.
23 See 40 CFR Part 63 Subpart JJJJJJ §63.11237.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 11 of 19

9 ppm with ULNBs that burn refinery fuel gas does not have the same feasibility as with natural
gas. Consequently, burner manufacturers will not guarantee 9 ppm NOx for refinery fuel gas.

For example, John Zink provided the following information to one Salt Lake City petroleum
refinery:

Our RMB burner technology is our burner of choice for single digit NOx application
(<9ppm). This would be a good fit for your boiler when firing [natural gas], but unfortunately
it is not an option for your Refinery Gas (with current fuel blend containing hydrogen,
nitrogen and other heavy hydrocarbons, RMB burner will not work).” [emphasis added]

The rulemaking process in the San Joaquin Valley for Rules 4306 and 4 320 recognizes the
limitations of refinery fuel gas compared to natural gas and other design and operating issues
discussed above:

The proposed Rule 4306 NOx limits for boilers and heaters at petroleum refineries are
generally higher than limits for other boilers and heaters due to their design and
operating conditions. In addition, refineries use a mix of natural gas and non -[public
utility company] quality process gas to fuel their boilers and heaters. Process gas
contains differing amounts of impurities, including hydrocarbons, which create
additional NOx when combusted.24

We recommend defining natural gas in a manner that describes only pipeline quality natural gas.
South Coast rule 1109.1 provides a suitable definition:

NATURAL GAS means a mixture of gaseous hydrocarbons, with at least 80 percent
methane (by volume), and of pipeline quality, such as the gas sold or distributed by
any utility company regulated by the California Public Utilities Commiss ion.

We recommend that UDAQ adapt this definition to Utah, include it in the rule, and make the
rule applicable only to boilers burning natural gas.

Recommendation #3: The rule should include an expanded definition of “boiler” that is
included wholly within the rule (rather than including reference to a definition in an
unrelated rule), uses the Boiler MACT definition of boiler as a starting point, and includes
additional appropriate exemptions for temporary boilers and refinery CO Boilers as well
as other appropriate situations.

The only definition provided in the draft Boiler Rules is the definition of Boiler. The Boiler Rules
refer to the Boiler MACT defini tion of boiler which states:

24 “Proposed Amendments to Rule 4306 (Boilers, Steam Generators, and Process Heaters – Phase 3)
and Proposed Amendments to Rule 4320 (Advanced Emission Reduction Options for Boilers, Steam
Generators, and Process Heaters Greater Than 5.0 MMBtu/hr)” draft staff report, San Joaquin Valley
Unified Air Pollution Control District, November 25, 2020 (“SJV Staff Report”), p. 18. Report available at
https://www.valleyair.org/Workshops/postings/2020/12 -17-20_r4306-r4320/DraftStaffReport.pdf
(accessed on October 11, 2022).
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 12 of 19

Boiler means an enclosed device using controlled flame combustion in which water
is heated to recover thermal energy in the form of steam and/or hot water.
Controlled flame combustion refers to a steady-state, or near steady-state, process
wherein fuel and/or oxidizer feed rates are controlled. A device combusting solid
waste, as defined in § 241.3 of this chapter, is not a boiler unless the device is
exempt from the definition of a solid waste incineration unit as provided in section
129(g)(1) of the Clean Air Act. Waste heat boilers, process heaters, and autoclaves
are excluded from the definition of Boiler.

The Boiler MACT provides a good start to a definition for the Boiler Rules and includes some
necessary exemptions. The definition includes exemptions for waste heat boilers and process
heaters, which we support retaining in the definition for the Boiler Rules . Waste heat boilers
capture unused heat from equipment and are not themselves fired boilers with burners. Process
heater applicability would bring in other concerns that we are not addressing in these comments
based on our understanding of UDAQ’s intent to include only boilers and not proce ss heaters.

Nonetheless, we have three concerns with adopting the Boiler MACT definition of boiler without
further modification in these Boiler Rules, and we provide recommendations to resolve the
concerns.

Recommendation #3.1: We recommend including the full boiler definition into the UDAQ rule
rather than referring to it.

First, reliance on a definition from a rule with an entirely different purpose, namely, to control
hazardous air pollutants (“HAPs”) rather than NOx, raises concerns about whether the definition
could change in undesirable ways in the future without regard to its use in this rule intended to
control NOx. For example, exemptions could be added or deleted from the Boiler MACT definition
in the future without regard to what the exemptions mean to NOx emissions.

We recommend copying the Boiler MACT definition into the Boiler Rules. This has the added
advantage of allowing changes to the definition appropriate to the Boiler Rules, as explained
below.

Recommendation #3.2: The boiler definition needs to be expanded to exempt temporary boilers .
A definition of “temporary boiler” should be included in the rule .

Temporary boilers may be brought in for short periods of time, up to 180 days, for various reason s.
They are not likely to be available in the rental market at 9 ppm NOx or, if available, the cost may
be far greater, a factor not considered in the cost analysis for the Boiler Rules, especially
considering their short-term use. In communication with one large nationwide boiler rental
company, they stated, “Our 20+ mmBtu steam boilers are rated for 30 ppm NOx on natural gas.”25
Considering the composition of refinery fuel gas as discussed above, we expect these rental
boilers would have even higher NOx levels when burning refinery fuel gas instead of natural gas.

25 Email communication from Alex Taylor, National Account Representative, WARE, to Marise Textor,
October 9, 2022.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 13 of 19

We also recommend including a definition of “temporary boiler” within the rules for clarity. The
Boiler MACT includes a list of equipment not subject to the rule, includi ng temporary boilers.26
The New Source Performance Standard (“NSPS”) for very large industrial, commercial, and
institutional steam generating units, 40 CFR Part 60 Subpart Db, contains an exemption for
temporary boilers27 and a suitable definition in §60 .41b that could be copied into the UDAQ boiler
rules, as follows:

Temporary boiler means any gaseous or liquid fuel -fired steam generating unit that is
designed to, and is capable of, being carried or moved from one location to another by
means of, for example, wheels, skids, carrying handles, dollies, trailers, or platforms. A
steam generating unit is not a temporary boiler if any one of the following conditions exists:

(1) The equipment is attached to a foundation.

(2) The steam generating unit or a replacement remains at a location for more than 180
consecutive days. Any temporary boiler that replaces a temporary boiler at a location and
performs the same or similar function will be included in calculating the consecutive time
period.

(3) The equipment is located at a seasonal facility and operates during the full annual
operating period of the seasonal facility, remains at the facility for at least 2 years, and
operates at that facility for at least 3 months each year.

(4) The equipment is moved from one location to another in an attempt to circumvent the
residence time requirements of this definition.

Although the Boiler MACT excludes temporary boilers,28 the accompanying definition in Boiler
MACT, while similar to that in NSPS Db, allows the temporary boiler to stay onsite for a year
instead of 180 days and includes provisions for extension.29 Thus, NSPS Db provides a more
environmentally protective definition to copy into the Boiler Rules.

Recommendation #3.3: We request an exemption for CO boilers from Fluid Catalytic Cracking
Unit (FCCU) units at petroleum refine ries and recommend including a definition of “CO boiler” in
the Boiler Rules.

FCCU CO Boilers pose an entirely different set of challenges to meeting 9 ppm NOx. CO Boilers
receive part of their fuel as FCC regenerator off-gas which contains NOx unaffected by the
burners:

Most NOx emissions from the COB are due to the oxidation of reduc ed nitrogen
compounds entering the COB in the catalyst regenerator off gas. Low NOx Burners (LNB)
in the COB have no effect on fuel-based NOx formation, and therefore are not considered
further for analysis.30

26 See 40 CFR Part 63 Subpart JJJJJJ, §63.11195(h).
27 See 40 CFR §60.40b(m).
28 See 40 CFR Part 63 Subpart JJJJJJ, §63.11195(h).
29 See “temporary boiler” definition in 40 CFR §63.11237.
30 Section 4.3.2 of Best Available Control Technology Analysis, Tesoro Salt Lake City Refinery, Prepared
for Tesoro Refining & Marketing Company LLC by BARR, April 2017 (“April 2017 BARR PM2.5 BACT
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 14 of 19

The boiler definition in South Coast Rule 1109.1 includes the statement, “For the purpose of this
rule, boiler does not include CO Boilers.” We recommend exempting CO Boilers by including a
similar statement within the boiler definition for the UDAQ rule.

The Boiler Rules should include a definition of CO Boiler. South Coast Rule 1109.1 includes the
following definition, which could be copied into the Boiler Rules:

CO BOILER means a Unit that is fired with gaseous fuel with an integral waste heat
recovery system used to oxidize CO-rich waste gases generated by the FCCU.

Recommendation #4: Definitions of “construction”, “modification”, “reconstruction”, and
“certification” need to be added to the rule.

Recommendation #4.1: The definitions of “construction” and “modification” included in UDAQ
Rules may not support the intended purpose of the Boiler Rules and a new definition of
“construction” at least should be added to the Boiler Rules.

With no definition of “construction” or “modification” included in the Boiler Rules, th e next place to
look would be elsewhere within the UDAQ rules. UDAQ’s General rule includes definitions that
each rely on an increase in emissions.31 We do not believe these definitions support the intent
of the Boiler Rules.

We recommend incorporating a definition of “construction” into the Boiler Rules. One example
that could be copied into the rules is the definition from NSPS:

Construction means fabrication, erection, or installation of an affected facility.32

Recommendation #4.2: No definition has been provided for “r econstruction” and one should be
included in the Boiler Rules that incorporates key concepts in the “reconstruction” definitions of
NSPS and MACT rules.

Neither the draft Boiler Rules nor the UDAQ General Rule include a definition for “reconstruction”.
A definition should be included to prevent any misinterpretation. The definition provided in the
NSPS relies on the reconstruction project cost exceeding 50% of the capital cost to build an
entirely new facility and on technical and economic feasibility to meet the standards provided in
the applicable NSPS.33 Similarly, the definition provided in the MACT also relies on the 50% test
and on it being technically and economically feasible to meet the applicable standard.34

We recommend adding a definition of “reconstruction” to the Boiler Rules that incorporates these
key concepts of the NSPS and MACT definitions, namel y the 50% test and technical and
economic feasibility.

Report”. Report available at https://deq.utah.gov/air-quality/control-strategies-serious-area-pm2-5-sip
(accessed on October 11, 2022).
31 See R307-101-2.
32 Definition from 40 CFR Part 60 §60.2.
33 See 40 CFR Part 60 §60.15.
34 See 40 CFR Part 63 §63.2.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
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Recommendation #4.3. No definition for “certify” or “certification” has been provided and one
needs to be included.

A key concept of the Boiler Rules is certification of ULNBs to meet a NOx emission rate of 9
ppm.35 But the draft Boiler Rules include no definition or explanation of the meaning of
“certification” or “certify.” What would be entailed in a certification? Would a simple manufacturer
quote of expected NOx emissions be sufficient? W hat would be needed to turn the quote into a
“certification”? What if the quote of anticipated NOx emissions level was based on an example
fuel gas composition but the composition changes over time?

Recommendation #5: The number of burners replaced in the applicability threshold of the
Boiler Rules should be increased from a single burner to 50% of the burners in the boiler,
at least for the larger boilers with multiple burners.

The South Coast Rules 1109.1 and 1146.1 apply the new NOx limits when 50% of the burners
within a boiler are changed, not when changing a single burner as in the draft Boiler Rules.36 As
explained above, it may not be feasible to replace a single burner with an ULNB , especially in
large industrial boilers with multiple burners. UDAQ has not explained why it chose the lower
threshold for changing burners.

Given the engineering requirements posed by the safety, reliability, and operability issues, the
50% threshold would be more appropriate, a t least for larger industrial boilers where re-
engineering and re-design may be required. Setting the threshold at 50% of the burners in the
boiler would reduce unnecessary case-by-case analysis and numerous instances of associated
agency review for individual burner replacements and would reduce repetitive work that does not
add value to the overall goal of better air quality.

Recommendation #6: The 15-minute averaging time should be removed from the design
NOx level and the header should be changed to remove “emission limit”.

Based on our discussions with UDAQ staff on September 23, 2022, we understand the 9 ppm
NOx and 15-minute averaging time to be design average s but not an emissions limit or emissions
compliance period. Therefore, the 15 -minute averaging time should be removed from the design
NOx level and the title should be changed to remove the phrase “emission limit.” We recommend
replacing “Emission Limits and Requirements” in the title of R307 -315-4 and R307-315-4 of the
draft Boiler Rules with “Requirements”.

No basis or justification has been provided to substantiate the 15-minute averaging period for the
design basis. The 15 -minute period is not justified and is too short. South Coast Rule 1109.1,
which the draft Boiler Rules were patterned after, have significantly longer averaging times for
refinery boilers of 24-hour rolling average and interim limits based on 365-day rolling average.37

Moreover, ozone forms on a diurnal cycle and thus, averaging times in the Boiler Rules should
not be substantially shorter than a day . The shorter averaging time provides no benefit to the

35 See draft Boiler Rules R307-315-4(1) and (3) and R307-315-4(1) and (3).
36 See South Coast Rule 1109.1(f)(2)(B) and (C) and (f)(4)(A ) and South Coast Rule 1146.1(c)(6) and
(e)(3).
37 See Tables 1, 2, 3, and 5 of SC Rule 1109.1, adopted November 5, 2021.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 16 of 19

intended pollutant control . Our member companies operate complex and dynamic operations
that must accommodate changes in feedstock and operational changes and, in the case of
petroleum refineries, changes in fuel gas composition, which are inconsistent with a 15 -minute
averaging period for NOx emissions.

Thus, a 15-minute averaging period is unlikely to provide improved ozone control over a 24 -hour
averaging period. In fact, it is unlikely to provide improved ozone control over a 30-day averaging
period considering the very large number of boilers that will be subject to the Boiler Rules. We
therefore recommend either dropping the 15 -minute averaging or replacing it with something
substantially longer.

Recommendation #7: Considering the complexities and feasibility concerns for large
industrial boilers, we request an implementation timing of five years from date of the
applicability trigger.

Considering all the various factors including the need to replace a burner on an operating unit for
routine maintenance ; the design, operation, and safety concerns associated with replacement
burners; and length of time for major process equipment turnaround cycles (often three to five
years),38 we request that operators be given a minimum of five years to come into compliance
with the Boiler Rules once burner replacements trigger applicability.

Compliance with the Boiler Rules could require redesigning the entire firebox, requires a planned
turnaround, and could likely be the critical path for a turnaround. Our member companies need
to have the ability to replace burners in kind on the run and , if they replace more than 50% in a
period of time, only then should they trigger applicability. But they must be allowed sufficient time
to plan, engineer, procure, and construct the required modifications to meet the Boiler rules . They
need time to conduct a case -by-case feasibility analysis. In many cases, the extensive re-design
could result in the need to modify the air construction permit as well, requiring additional time .39

Allowing a five-year period to come into compliance is consistent with South Coast Rule 1109.1,
which allows a period of three years to come into compli ance after the agency issues the air
permit to construct.

Recommendation #8: We support the applicability of the rule to the full counties of the
NWF and recommend extending the rule applicability to Utah County.

The Associations agree that the rule should apply to boilers located in the entire counties of Salt
Lake, Davis, Weber, or Tooele Counties , even though the nonattainment area includes some
partial counties. This will ensure that the nearby emissions from the partial counties outside the
boundary of the NWF do not negatively impact the NWF and its ability to reach attainment.

We also recommend extending the rule applicability to Utah County, which comprises the
Southern Wasatch Front ozone nonattainment area (“SWF”). We understand that EPA ha s

38 Turnaround cycles may vary between three and five years depending on the process operation and
needs of the operation. Shorter turnaround cycles increase the amount of associated lost profit.
39 An example of the need to change the air permit would be if the facility uses the opportunity posed by
required burner replacement and boiler redesign to incorporate other new design features or increased
throughput, an opportunity that they should have the ability to pursue within the rule.
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
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approved the SWF as having attained the 2015 ozone National Ambient Air Quality Standard
(“NAAQS”) by its attainment date.40 However, the apparent year-to -date (“YTD”) design value
(“DV”) for 2022 for the SWF appears to be 73 ppb, above the level of the standard:41

We fully understand that an official design value must be based on three full calendar years of
data, after the data has been certified, and the data shown above for 2022 has not been certified
nor is it based on the full calendar year. However, certification is unlikely to cause significant
changes to the ozone measurements and considering that the fourth high for the full calendar
year cannot be lower than the fourth hi gh year-to -date, we consider the year-to-date design value
to be a good approximation of the lowest value possible or likely for the official design value for
2022, a value that will ultimately be determined in 2023.

Although EPA approved the SWF as having attained by the attainment date, EPA’s action does
not constitute a redesignation and clearly the SWF is teetering on nonattaining air quality. With
nonattaining air quality now, it may be difficult for UDAQ to develop the required maintenance
plan showing attainment for the required 10-year period without additional emission reductions.

Furthermore, considering the proximity of Utah County and the SWF to the NWF, we fully
anticipate that the photochemical model being developed by UDAQ may show an impact of Utah
County emissions on the NWF. If the model shows Utah County to be contributing to NWF
nonattainment, such a showing would support extending applicability of the Boiler Rules to Utah
County.

Recommendation #9: At this time, the Boiler Rules have not been demonstrated to support
the required ozone attainment demonstration. Considering this, we recommend that
UDAQ take the necessary time to adequately address the issues of concern and
recommendations outlined in this letter to ensure the final rules will be technically and
economically feasible in all cases.

The Associations understand the need to reduce ozone precursor emissions to improve air
quality. Nonetheless, as shown in Figure 1, over the past 15 years, reductions of NOx and VOC
of 30% to 40% have not reduced ozone.42

40 “Determinations of Attainment by the Attainment Date, Extensions of the Attainment Date, and
Reclassification of Areas Classified as Marginal for the 2015 Ozone National Ambient Air Quality
Standards” final rule; Federal Register, Volume 87, Number 194; October 7, 2022; p. 60897 (“DAAD”).
41 Fourth high values for 2020 and 2021 were obtained from EPA 2021 Design Value report for ozone,
Table 5, Site Status, spreadsheet report available at https://www.epa.gov/air-trends/air-quality-design-
values. Fourth high values for 2022 year-to-date were obtained by downloading daily data for ozone for
the two monitors in Utah County at EPA Outdoor Air Quality website, https://www.epa.gov/outdoor-air-
quality-data/download-daily-data, on October 10, 2022, which provided data through October 9, 2022.
42 Emissions obtained from UDAQ statewide emission inventories located at https://deq.utah.gov/air-
quality/statewide-emissions-inventories#section-2. As of this writing, 2017 is the latest year for which
both EPA and UDAQ have provid ed a statewide emission inventory with emissions for all sources.
Monitor Monitor Number 2020 2021 2022 YTD
Lindon 490494001 68 77 74 73
Spanis h Fork 490495010 70 76 66 70
4th High Values , ppb YTD DV,
ppb
Comments from Utah Petroleum Association and Utah Mining Association Regarding Advance Notice of Rulemaking
for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
Page 18 of 19

Figure 1. NWF Emissions Trend with Design Value Trends
In the absence of modeling sensitivity studies, we do not know if the NWF is in a VOC -limiting or
NOx-limiting regime and the extent to which NOx reductions will reduce ozone if at all.
Furthermore, over the period of implementation of these rules, new heavy-duty truck standards
and vehicle fleet turnover benefits from new light duty vehicle standards will provide considerable
NOx emission reductions. As shown in Figure 2, over 60% of local NWF ozone precursor
emissions come from mobile sources, and these mobile source vehicle standards will reduce this
largest piece of the pie.43

Figure 2. Distribution of Ozone Precursor Emissions (NOx + VOC) in NWF
We understand that UDAQ considers the Boiler Rules as important to achieve future required 3%
per year Reasonable Further Progress (“RFP”) at Serious nonattainment an d above. But if NOx

Design values obtained from EPA design value reports at https://www.epa.gov/air-trends/air-quality-
design-values.
43 Emissions based on full counties within the NWF and 2017 emission inventory, which as explained
above, is the latest data available as of this writing.
0
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90
2004
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Emissions, Thousand Tons
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for Natural Gas-Fired Boilers, Steam Generators, and Process Heaters; October 17, 2022
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reductions will not support the attainment demonstration, it might make more sense to focus future
RFP goals on VOC emission reductions for which the NWF must show a 15% reduction while at
Moderate nonattainment. Furthermore, the substantial NOx emission reductions obtained from
light duty motor vehicle and heavy-duty truck turnover can be counted towards the future RFP
goals.

Thus, in the absence of supporting technical information demonstrating that the Boiler Rules will
support the required attainment demonstration, it seems prudent to take the time needed to
develop rules that will be both technically and economically feasib le for all affected facilities.

Conclusion
Overall, the Associations support the Boiler Rules as long as the final rule s to be adopted
incorporate provisions for affected facilities to conduct case -by-case cost and technical feasibility
analyses, incorporate adequate implementation time upon triggering applicability especially
where a burner cannot simply be swapped out, and include appropriate definitions, clarifications,
and exemptions.

The topic of controlling boiler NOx emissions is complex yet is an important consideration in the
pursuit of attainment. But many industrial operations have constraints that affect the ability to use
ULNBs. Many other factors influence the feasibility and performance of ULNBs. Understanding
that our comments are sign ificant and, in some cases, heavily technical , we offer to meet with you
and others at UDAQ to discuss these comments, address any questions you may have, and
develop a dialogue about these important factors, all in the pursuit of developing Boiler Rules that
are effective as well as technically and economically feasible . If desired, please contact Rikki to
coordinate scheduling a meeting.

Sincerely,

Rikki Hrenko-Browning Brian Somers
President, Utah Petroleum Association President, Utah Mining Association

cc: Bryce Bird – [e-mail]
Becky Close – [e-mail]