HomeMy WebLinkAboutDAQ-2024-0081091/23/24, 11:48 AM State of Utah Mail - Hexcel 2015 8-hr Ozone RACT Analysis
https://mail.google.com/mail/u/0/?ik=539c285453&view=pt&search=all&permmsgid=msg-f:1787024201939913695&simpl=msg-f:1787024201939913…1/2
Ana Williams <anawilliams@utah.gov>
Hexcel 2015 8-hr Ozone RACT Analysis
Brian Mensinger <bmensinger@trinityconsultants.com>Tue, Jan 2, 2024 at 4:44 PM
To: Ana Williams <anawilliams@utah.gov>, "Jon Black (jlblack@utah.gov)" <jlblack@utah.gov>
Cc: "Hone, Tyson" <Tyson.Hone@hexcel.com>, "Fayol, David" <David.Fayol@hexcel.com>, Kristine Davies
<KDavies@trinityconsultants.com>
Ana and Jon,
Attached is Hexcel Corporation (Hexcel’s) West Valley City Plant updated Reasonably Available Control Technology (RACT)
analysis for the 2015 8-hour Ozone Standard and its precursors (NOx and VOCs). This submission is in response to the letter
sent by the Utah Division of Air Quality (UDAQ) on May 31, 2023, which this update is required to be submitted by January 2,
2024.
For the purposes of the updated RACT analysis, Hexcel has evaluated emissions in a manner consistent with approaches used
for its current approval order (DAQE-AN113860035-22), prior state implementation plan (SIP) conditions, and as they were
defined by the RACT analysis top-down process. Hexcel requests that UDAQ reach out to Tyson Hone (Hexcel), David Fayol
(Hexcel), or Brian Mensinger (Trinity Consultants), copied on this email, before making any recommendations or final decisions
on this RACT analysis to ensure its plans align with Hexcel’s long-term business plans.
If you have any questions, please feel free to reach out to us.
Regards,
Brian Mensinger
…………………………………………………………………………
Brian Mensinger
Managing Consultant
4525 Wasatch Blvd, Suite 200, Salt Lake City, Utah 84124
Email: bmensinger@trinityconsultants.com
Phone: 385-433-3384 Cell: (801) 946-7342
Connect with us: LinkedIn / Facebook / Twitter / YouTube / trinityconsultants.com
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1/23/24, 11:48 AM State of Utah Mail - Hexcel 2015 8-hr Ozone RACT Analysis
https://mail.google.com/mail/u/0/?ik=539c285453&view=pt&search=all&permmsgid=msg-f:1787024201939913695&simpl=msg-f:1787024201939913…2/2
Hexcel West Valley Ozone RACT Analysis 2024-0102 v2.0.pdf
1170K
OZONE SERIOUS NONATTAINMENT
RACT Analysis
Hexcel Corporation- West Valley City, Utah
Prepared By:
TRINITY CONSULTANTS
4525 Wasatch Boulevard
Suite 200
Salt Lake City, Utah 84104
(801) 272-3000
Submitted on Behalf of:
Hexcel Corporation
6800 West 5400 South
West Valley City, Utah 84118-0748
Project 234502.0060
January 2024
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TABLE OF CONTENTS
1. INTRODUCTION 1-1
2. FACILITY AND EMISSIONS INFORMATION 2-1
2.1 Description of the Facility ......................................................................................... 2-1
2.2 Emissions Profile ....................................................................................................... 2-1
2.3 Hexcel’s Efforts for Reduction in Emissions............................................................... 2-1
3. REASONABLY AVAILABLE CONTROL TECHNOLOGIES BACKGROUND 3-1
3.1 RACT Methodology .................................................................................................... 3-1
3.1.1 Step 1 – Identify All Reasonably Available Control Technologies................................... 3-2
3.1.2 Step 2 – Eliminate Technically Infeasible Options ....................................................... 3-2
3.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness ...................... 3-2
3.1.4 Step 4 – Evaluate Most Effective Controls and Document Results ................................. 3-2
3.1.5 Step 5 – Select RACT ............................................................................................... 3-3
4. RACT ANALYSIS FOR FIBER LINE EMISSIONS 4-1
4.1 RACT Analysis for NOX Emissions .............................................................................. 4-1
4.1.1 Step 1 – Identify All Reasonably Available Control Technologies................................... 4-2
4.1.2 Step 2 – Eliminate Technically Infeasible Options ....................................................... 4-5
4.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness ...................... 4-6
4.1.4 Step 4 – Evaluate Most Effective Controls and Document Results ................................. 4-6
4.1.5 Step 5 – Select RACT ............................................................................................... 4-7
4.2 RACT Analysis for VOC Emissions .............................................................................. 4-8
4.2.1 Step 1 - Identify All Reasonably Available Control Technologies ................................... 4-8
4.2.2 Step 2 – Eliminate Technically Infeasible Options ..................................................... 4-10
4.2.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness .................... 4-10
4.2.4 Step 4 – Evaluate Most Effective Controls and Document Results ............................... 4-10
4.2.5 Step 5 – Select RACT ............................................................................................. 4-10
4.3 RACT Analysis for Fiber Line Pilot Plant .................................................................. 4-11
5. RACT ANALYSIS FOR MATRIX 5-1
5.1.1 Step 4 – Evaluate Most Effective Controls and Document Results ................................. 5-1
5.1.2 Step 5 – Select RACT ............................................................................................... 5-1
6. BOILERS 6-1
6.1 RACT Analysis for NOX Emissions .............................................................................. 6-1
6.1.1 Step 1 – Identify All Reasonably Available Control Technologies................................... 6-1
6.1.2 Step 2 – Eliminate Technically Infeasible Options ....................................................... 6-1
6.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness ...................... 6-2
6.1.4 Step 4 – Evaluate Most Effective Controls and Document Results ................................. 6-3
6.1.5 Step 5 – Select RACT ............................................................................................... 6-3
6.2 RACT Analysis for VOC Emissions .............................................................................. 6-3
6.2.1 Steps 1-5 – Select RACT .......................................................................................... 6-3
7. EMERGENCY GENERATORS 7-1
7.1 RACT Analysis for NOX and VOC Emissions ................................................................ 7-1
7.1.1 Step 1 – Identify All Reasonably Available Control Technologies................................... 7-1
7.1.2 Step 2 – Eliminate Technically Infeasible Options ....................................................... 7-2
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7.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness ...................... 7-4
7.1.4 Step 4 – Evaluate Most Effective Controls and Document Results ................................. 7-4
7.1.5 Step 5 – Select RACT ............................................................................................... 7-5
8. OTHER SMALL NATURAL GAS FURNACES 8-1
8.1 RACT Analysis for NOX Emissions .............................................................................. 8-1
8.1.1 Step 1 – Identify All Reasonably Available Control Technologies................................... 8-1
8.1.2 Step 2 – Eliminate Technically Infeasible Options ....................................................... 8-1
8.1.3 Steps 3 – 5 ............................................................................................................. 8-1
8.2 RACT Analysis for VOC Emissions .............................................................................. 8-2
8.2.1 Steps 1 – 5 ............................................................................................................. 8-2
9. RACT ANALYSIS FOR LABORATORY AND R&T FACILITY 9-1
APPENDIX A. COST EFFECTIVENESS ANALYSIS A-1
APPENDIX B. SUPPORTING COST CALCULATIONS B-1
APPENDIX C. RBLC DATA C-1
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1. INTRODUCTION
On May 31, 2023, the Utah Division of Air Quality (UDAQ) sent a letter to Hexcel Corporation (Hexcel) which
identified the Hexcel plant in West Valley City, Utah (West Valley City Plant) as a major stationary source
within the Northern Wasatch Front (NWF) Ozone Nonattainment Area (NAA). This letter indicated that
UDAQ anticipates that the U.S. Environmental Protection Agency (EPA) will reclassify the NAA as serious by
February 2025. In order to prepare for the reclassification UDAQ has requested that a Reasonably Available
Control Technology (RACT) analysis be submitted by January 2, 2024. Section 110 of the Clean Air Act
(CAA) defines the requirements for the development of State Implementation Plans (SIPs), and Section
7511a specifies the requirements of a serious nonattainment SIP, which includes a Reasonably Available
Control Technology (RACT) analysis for all major sources.
The precursors to ozone are oxides of nitrogen (NOX) and volatile organic compounds (VOCs). As a result,
the enclosed RACT analysis focuses on the emission sources at the West Valley City Plant that emit these
pollutants. Hexcel has the potential to emit 50 tons per year (tpy) or more of NOX and VOCs classifying it as
a major source subject to SIP requirements.
Based on further information provided by UDAQ the following elements have been requested for each RACT
analysis:
► A list of each of the NOX and VOC emission units at the facility;
► A physical description of each emission unit, including its operating characteristics;
► Estimates of the potential and actual NOX and VOC emission rate from each affected source and
associated supporting documentation;
► The proposed NOX and/or VOC RACT requirement or emission limitation (as applicable); and
► Supporting documentation for the technical and economic consideration for each affected emission unit.1
Per UDAQ’s request, Hexcel is submitting this RACT analysis no later than January 2, 2024.
1 Ozone SIP Planning RACT Analysis forms provided by Ana Williams, Utah Department of Environmental Quality on January 9, 2023.
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2. FACILITY AND EMISSIONS INFORMATION
2.1 Description of the Facility
Hexcel Corporation (Hexcel) owns and operates a carbon fiber and fabric pre‐impregnation (pre‐preg)
manufacturing plant (West Valley City Plant) located at 6800 West 5400 South, West Valley City in Salt Lake
County, Utah. The West Valley City Plant currently operates under Utah Division of Air Quality’s (UDAQ)
Approval Order DAQE-AN113860035-22. The plant is an existing major source under federal Nonattainment
New Source Review (NNSR), Title V, and Maximum Achievable Control Technology (MACT) programs.
Hexcel is a listed source in subsection IX.H of the Utah State Implementation Plan (SIP). The plant is a
minor source for Prevention of Significant Deterioration (PSD) purposes.
All correspondence regarding this submission should be addressed to:
Mr. Tyson Hone
Site Environmental Manager
P.O. Box 18748
Salt Lake City, Utah 84118
Phone: (385) 831-3472
Email: Tyson.Hone@hexcel.com
2.2 Emissions Profile
Through recent permitting actions Hexcel has established the following PTE profile for NOX and VOC. A full
explanation of calculation methods and inputs can be found within the permitting files.
Table 2-1. Facility-wide Potential to Emit
NOX VOC
PTE (tpy) 197.62 174.10
Facility-wide actual emissions for NOX and VOC as recorded within UDAQ’s State and Local Emission
Inventory System (SLEIS) are included in Table 2-2.
Table 2-2. Facility-wide Actual Emissions
NOX VOC
2022 Actuals (tpy) 195.02 148.91
2.3 Hexcel’s Efforts for Reduction in Emissions
Hexcel has committed to reducing the environmental impact of its facility through SIP and New Source
Review (NSR) permitting requirements. This is evidenced through the following actions:
► Ultra-low NOX burners (ULNB) with flue gas recirculation (FGR) shall be installed on Fiber Lines 3, 4, and
7 to control NOX emissions no later than December 31, 2024.
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► De-NOX Water (De-NOX) Direct-Fired Thermal Oxidizers (DFTO) shall be installed on Fiber Lines 13, 14,
15, and 16 to control NOX emissions no later than December 31, 2024.
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3. REASONABLY AVAILABLE CONTROL TECHNOLOGIES BACKGROUND
Hexcel previously submitted a Best Available Control Measures (BACM) analysis in 2017 to support the PM2.5
Serious Nonattainment SIP. Hexcel has implemented the current SIP requirements with the exception of
those controls that are not required until December 31, 2024. The 2017 BACM analysis serves as a baseline
for the RACT analysis documented herein. A RACT analysis has been conducted for each source addressed
in Approval Order DAQE-AN113860035-22 in the following sections. Hexcel has organized the RACT analysis
in accordance with EPA’s “top-down” procedures per UDAQ guidance.2 The analysis is further organized by
emission unit group and addresses NOX and VOCs as ozone precursors.
3.1 RACT Methodology
EPA has defined RACT as follows:
The lowest emission limitation that a particular source is capable of meeting by the
application of control technology that is reasonably available considering
technological and economic feasibility.3
RACT for a particular source is determined on a case-by-case basis considering the
technological and economic circumstances of the individual source.4
In EPA’s State Implementation Plans; General Preamble for Proposed Rulemaking on Approval of Plan
Revisions for Nonattainment Areas – Supplement (on Control Techniques Guidelines), it provided a
recommendation to states which says:
…each [Control Technique Guideline] CTG contains recommendations to the States
of what EPA calls the “presumptive norm” for RACT, based on EPA’s current
evaluation of the capabilities and problems general to the industry. Where the States
finds the presumptive norm applicable to an individual source or group of sources,
EPA recommends that the State adopt requirements consistent with the presumptive
norm level in or to include RACT limitations in the SIP.5
Hexcel has referenced the published CTG’s as well as Utah Administrative Code (UAC) for Air Quality (R307),
and proposed rules which establish a current presumptive norm specific to the NWF NAA. The preamble
goes on to state:
…recommended controls are based on capabilities and problems which are general
to the industry; they do not take into account the unique circumstances of each
facility. In many cases appropriate controls would be more or less stringent. States
2 UDAQ Ozone SIP Planning RACT Analysis, obtained June 13, 2023, during an informational meeting. 3 EPA articulated its definition of RACT in a memorandum from Roger Strelow, Assistant Administrator for Air and Waste Management, to Regional Administrators, Regions I-X, on Guidance for Determining Acceptability of SIP Regulations in Non-Attainment Areas,” Section 1.a (December 9,1976). 4 Federal Register/Vol. 44. No. 181/Monday, September 17,1979/Proposed Rules – State Implementation Plan; General Preamble for Proposed Rulemaking on Approval of Plan Revisions for Nonattainment Areas – Supplement (on Control Techniques Guidelines). 5 IBID.
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are urged to judge the feasibility of imposing the recommended control on particular
sources, and adjust the controls accordingly.
Guidance provided by UDAQ for this RACT analysis states that this analysis is to be conducted using the
“top-down” method.6 In a memorandum dated December 1, 1987, the EPA detailed its preference for a
“top-down” analysis which contains five (5) steps.7 If it can be shown that the most stringent level of
control is technically, environmentally, or economically infeasible for the unit in question, then the next most
stringent level of control is determined and similarly evaluated. This process continues until the RACT level
under consideration cannot be eliminated by any substantial or unique technical, environmental, or
economic objections. Presented below are the five basic steps of a “top-down” RACT review as identified by
the EPA.
3.1.1 Step 1 – Identify All Reasonably Available Control Technologies
Available control technologies are identified for each emission unit in question. The following methods are
used to identify potential technologies: 1) researching the RACT/BACT/LAER Clearinghouse (RBLC)
database, 2) surveying regulatory agencies, 3) drawing from previous engineering experience, 4) surveying
air pollution control equipment vendors, and/or 5) surveying available literature. Additionally, current CTG’s
as well as UAC R307, and proposed rules were reviewed to establish a current presumptive norm specific to
the NWF NAA.
3.1.2 Step 2 – Eliminate Technically Infeasible Options
To ensure the presumptive norm established applies to the emission source in question a full review of
available control technologies is conducted in the second step of the RACT analysis. In this step each
technology is reviewed for technical feasibility and those that are clearly technically infeasible are
eliminated. EPA states the following with regard to technical feasibility:8
A demonstration of technical infeasibility should be clearly documented and should
show, based on physical, chemical, and engineering principles, that technical
difficulties would preclude the successful use of the control option on the emissions
unit under review.
3.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness
Once technically infeasible options are removed from consideration, the remaining options are ranked based
on their control effectiveness. If there is only one remaining option or if all the remaining technologies could
achieve equivalent control efficiencies, ranking based on control efficiency is not required.
3.1.4 Step 4 – Evaluate Most Effective Controls and Document Results
Beginning with the most effective control option in the ranking, detailed economic, energy, and
environmental impact evaluations are performed. If a control option is determined to be economically
6 UDAQ Ozone SIP Planning RACT Analysis, provided January 9, 2023. 7 U.S. EPA, Office of Air and Radiation. Memorandum from J.C. Potter to the Regional Administrators. Washington, D.C. December 1, 1987. 8 U.S. EPA, New Source Review Workshop Manual (Draft): Prevention of Significant Deterioration and Nonattainment Area Permitting, October 1990.
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feasible without adverse energy or environmental impacts, it is not necessary to evaluate the remaining
options with lower control effectiveness.
The economic evaluation centers on the cost effectiveness of the control option. Costs of installing and
operating control technologies are estimated and annualized following the methodologies outlined in the
EPA’s OAQPS Control Cost Manual (CCM) and other industry resources.9 Note that the purpose of this
analysis is not to determine whether controls are affordable for a particular company or industry, but
whether the expenditure effectively allows the source to meet pre-established presumptive norms.
3.1.5 Step 5 – Select RACT
In the final step the lowest emission limitation is proposed as RACT along with any necessary control
technologies or measures needed to achieve the cited emission limit. This proposal is made based on the
evaluations from the previous step.
9 Office of Air Quality Planning and Standards (OAQPS), EPA Air Pollution Control Cost Manual, Sixth Edition, EPA 452-02-001 (https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution), Daniel C. Mussatti & William M. Vatavuk, January 2002.
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4. RACT ANALYSIS FOR FIBER LINE EMISSIONS
An understanding of Hexcel’s Carbon Fiber process is important for understanding the technical and
economic feasibility of various control options. The first step in converting polyacrylonitrile (PAN) fiber into
carbon fiber is the stabilization of the PAN fibers in an air oxidation process. The intent of this step is to
prepare the PAN fibers for the high temperature carbonization process.
The oxidation process is completed with the operation of oxidation ovens set at specified temperatures to
achieve the required amount of oxidation during the fiber stabilization process. The ovens have the
capability to be either electric or natural gas fired. Fiber Lines 2, 3 and 4 have electric ovens, which do not
produce combustion emissions. Fiber Lines 5-7, 8, 10, 11 and 12 have natural gas-fired ovens. Fiber Lines
13-16 are hybrid ovens with the capability of using electricity or natural gas. NOX is the primary pollutant
that is emitted from these sources, but VOC emissions also results from the combustion of fuel.
The oxidation ovens for Fiber Lines 5-7 are indirect fired, so the combustion emissions are vented from a
separate stack than the process emissions. For Fiber Lines 8 and 10-16, the ovens are direct fired; thus, the
flue gas (combustion emissions) enters the oven and is combined with process emissions then vented
through a single stack. The ozone precursor emissions associated with the stabilization process occurring in
the oxidation ovens is VOC. Exhaust gases containing process emissions from the ovens are captured in
hoods at either end of each oven or within the oven structure itself.
The next downstream step in the manufacturing of carbon fiber is carbonization. This step can be split into
two different phases. The first phase is tar removal which occurs when the fiber continuously passes
through a low temperature furnace. The tar removal step takes place in an electric furnace at temperatures
ranging from 300 – 800 degrees Celsius (°C). Ozone precursor emissions generated from the tar removal
process are VOCs. The second phase of carbonization occurs at higher temperatures ranging from
1200-1450 °C. This high temperature treatment of the fiber occurs in another electric furnace, commonly
referred to as the high temperature (HT) furnace. Ozone precursor emissions generated from the
carbonization process are VOCs.
Hexcel is currently permitted to operate 14 Fiber Lines. Add-on control device options were evaluated for
each fiber line based on all stack flow directed to one control device per line. This control strategy optimizes
the balance between energy efficiency and capital intensity with the same environmental benefit as adding
smaller control devices to each emission unit or one large device receiving combined flow from all buildings.
4.1 RACT Analysis for NOX Emissions
As described previously, the oxidation process is completed with the operation of ovens set at specified
temperatures to achieve the required amount of oxidation for the fiber stabilization process. The NOX
emissions from combustion in the oxidation ovens, tar removal process furnaces, and carbonization furnaces
are included in the NOX RACT analysis for the Fiber Lines. Since RACT, at a minimum, must consider current
regulations as well as SIP and Approval Order conditions that apply to the emission units, the minimum NOX
RACT limitations are as follows:10
► 5.50 million standard cubic feet (MMscf) of natural gas consumed per day
► 0.061 million pounds of carbon fiber produced per day
10 Requirements included in Section IX. Part H of the PM2.5 SIP.
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► ULNB with FGR installed on Fiber Lines 3, 4, and 7 no later than December 31, 2024
► De-NOX DFTO installed on Fiber Lines 13, 14, 15, and 16 no later than December 31, 2024
► Emission limitations for NOX concentration:
• Fiber Line 3 – 9.0 parts per million (ppm)
• Fiber Line 4 – 9.0 ppm
• Fiber Line 7 – 9.0 ppm
► Fiber Lines 13-16 oxidation ovens
• Natural gas combustion with low NOX burners (LNB)
• Controlled with Direct-fired Thermal Oxidizers (DFTOs) equipped with LNB
• Controlled with dual chamber regenerative thermal oxidizers (RTOs) with LNB
4.1.1 Step 1 – Identify All Reasonably Available Control Technologies
Based on the review of the U.S. EPA’s RBLC database and similar operations, Hexcel has identified the
following control technologies available for controlling NOX emissions from the proposed gas streams:
1. Good Combustion Practices (GCP),
2. Use of Natural Gas Only as Fuel,
3. LNB,
4. ULNB,
5. FGR
6. De-NOX,
7. Selective Catalytic Reduction (SCR), and
8. Selective Non‐Catalytic Reduction (SNCR)
The search of the RBLC database produced two carbon fiber manufacturing facilities shown in Attachment
C. One facility installed LNB with FGR in combination with use of natural gas and GCP as NOX BACT for a
PSD permit. The other facility found SCR to not be cost effective but installed it voluntarily on four of its
eight carbon Fiber Lines as NOX control during a PSD permitting action. Additional searches of the database,
for similar combustion units fired with natural gas were also conducted. The results of these searches
presented in Attachment C produced the same list of control devices for NOX as shown above.
Low‐NOX Burners
LNB technology uses advanced burner design to reduce NOX formation through the restriction of oxygen,
flame temperature, and/or residence time. There are two general types of LNB: staged fuel and staged air
burners. In a stage fuel LNB, the combustion zone is separated into two regions. The first region is a lean
combustion region where a fraction of the fuel is supplied with the total quantity of combustion air.
Combustion in this zone takes place at substantially lower temperatures than a standard burner. In the
second combustion region, the remaining fuel is injected and combusted with left over oxygen from the first
region. A staged air burner begins with full fuel but only partial combustion air, and then adds the remaining
combustion air in the second combustion region. These techniques reduce the formation of thermal NOX.
Implementation of LNB technology has been shown to reduce NOX emissions by 50 percent compared with
standard burners.11
11 AP‐42 Table 1.4‐1 – Emission Factors for Nitrogen Oxides (NOX) and Carbon Monoxide (CO) from Natural Gas Combustion.
Comparison of uncontrolled emissions from a small boiler (100 lb/106 scf) to controlled Low‐NOX burner emissions from a
small boiler (50 lb/106 scf). [1‐50/100 = 50%]
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Ultra-Low NOX Burners
ULNB technology incorporates an LNB with an additional system such as FGR to further reduce NOX. ULNBs
provide a stable flame that has several different zones. ULNB technology commonly uses internal FGR which
involves recirculating the hot O2 depleted flue gas from the heater into the combustion zone using burner
design features and fuel staging to reduce NOX. There are several methods for reducing NOX that can
produce more than 80 percent destruction removal efficiency (DRE).12 NOX emission rates as low as 9 ppm
have been achieved in practice.13
Flue Gas Recirculation
As noted above, FGR is frequently used with both LNB and ULNB. FGR involves the recycling of
post-combustion air into the air-fuel mixture to reduce the available oxygen and help cool the burner flame.
External FGR requires the use of ductwork to route a portion of the flue gas in the stack back to the burner
windbox; FGR can be either forced draft (where hot side fans are used) or induced draft.
De-NOX Steam or Water System
The formation of NOX results from one of three mechanisms: thermal NOX, fuel NOX, and prompt NOX. The
De-NOX control system injects either steam or water into the combustion chamber to reduce the potential
formation of thermal NOX by providing a small reduction in temperature within the combustion chamber.
Water injection generally provides better control of NOX since it reduces the temperature in the combustion
chamber more than does steam.
Selective Catalytic Reduction
The SCR process is based on the chemical reduction of the NOX molecule. SCR employs a metal‐based
catalyst with activated sites to increase the rate of the reduction reaction. A nitrogen based reducing agent
(reagent), such as ammonia or urea, is injected into the post combustion flue gas. The reagent reacts
selectively with the flue gas NOX within a specific temperature range and in the presence of the catalyst and
oxygen to reduce the NOX into molecular nitrogen (N2) and water vapor (H2O).14
SCR has been applied to stationary source, fossil fuel-fired, combustion units for emission control since the
early 1970s. It has been applied to large, >250 million British thermal units per hour (MMBtu/hr), utility and
industrial boilers, process heaters, and combined cycle gas turbines. There has been limited application of
SCR to other combustion devices and processes such as simple cycle gas turbines, stationary reciprocating
internal combustion engines, nitric acid plants, and steel mill annealing furnaces. SCR can be applied as a
stand-alone NOX control or with other technologies such as combustion controls. The optimum operating
temperature is dependent on the type of catalyst and the flue gas composition. Generally, the optimum
12 EPA Technical Bulletin “Nitrogen Oxides (NOX) Why and How are They Controlled”, EPA 456/F‐99‐006R November 1999.
13 Internet search, including: https://ww2.arb.ca.gov/sites/default/files/classic/research/apr/past/94-354.pdf;
http://www.powerflame.com/index.php?option=com_content&view=article&id=110&Itemid=57;
https://www.pharmaceuticalonline.com/doc/ultra-low-nox-burner-has-widened-stability-li-0004
14 Ibid.
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temperature ranges from 480-800 degrees Fahrenheit (°F).15 In practice, SCR systems operate at
efficiencies in the range of 70-90 percent.16
SNCR
SNCR is currently being used for NOX emission control on industrial boilers, electric utility steam generators,
thermal incinerators, and municipal solid waste energy recovery facilities. Its use on utility boilers has
generally been limited to units with output of less than 3,100 MMBtu. SNCR can be applied as a stand‐alone
NOX control or with other technologies such as combustion controls. The SNCR system can be designed for
seasonal or year‐round operations. SNCR can achieve NOX reduction efficiencies of up to 75 percent in
short-term demonstrations. In typical field applications, however, it provides 30-50 percent NOX reduction.
Reductions of up to 65 percent have been reported for some field applications of SNCR in tandem with
combustion control equipment such as LNB.17
SNCR is based on the chemical reduction of the NOX molecule into N2 and H2O. A nitrogen based reducing
agent (reagent), such as ammonia or urea, is injected into the post combustion flue gas. The reagent can
react with a number of flue gas components. However, the NOX reduction reaction is favored over other
chemical reaction processes for a specific temperature range and in the presence of oxygen; therefore, it is
considered a selective chemical process.18 The technique requires thorough mixing of reagent into the
furnace chamber with at least 0.5 seconds of residence time at a temperature above 1600 °F and below
2100 °F. Optimally, the reagent is injected into the furnace at approximately 1900 ‐ 1950 °F, which is a
good tradeoff between the competing reaction of oxidation of ammonia to NOX and maximizing the
residence time at a temperature which is greater than the temperature at which SNCR yields published
removal efficiencies.19
The hardware associated with an SNCR installation is relatively simple and readily available. Consequently,
SNCR applications tend to have low capital costs compared to LNB and SCR. Installation of SNCR equipment
requires minimum downtime.
Good Combustion Practices
U.S. EPA’s RBLC database lists numerous operations where GCP are the accepted technology for minimizing
NOX emissions. GCP reduce NOX emissions by keeping the burners maintained properly so that the burners
continue to operate according to their design.
The use of GCP usually includes the following components: (1) proper fuel mixing in the combustion zone;
(2) high temperatures and low oxygen levels in primary zone; (3) overall excess oxygen levels high enough
to complete combustion while maximizing boiler efficiency, and (4) sufficient residence time to complete
15 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-
analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002
16 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001 (https://www.epa.gov/economic-and-cost-
analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002
17 Ibid.
18 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B‐02‐001 (https://www.epa.gov/economic-and-cost-
analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002
19 SNCR System – Design, Installation and Operating Experience, David L. Wojichowski, De‐NOX Technologies LLC
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combustion. GCP are accomplished through boiler design as it relates to time, temperature, and turbulence,
and boiler operation as it relates to excess oxygen levels.
Use of Natural Gas Only as Fuel
The U.S. EPA’s RBLC database indicates restricting fuel type to natural gas will limit NOX emissions, because
other fuels combusted may have higher NOX emission rates.
4.1.2 Step 2 – Eliminate Technically Infeasible Options
Selective Catalytic Reduction
There has been limited application of SCR to combustion devices and processes such as simple cycle gas
turbines, stationary reciprocating internal combustion engines, nitric acid plants, and steel mill annealing
furnaces. Results of the RBLC search for similar operations to Hexcel’s, shown in Appendix C support that
this type of control technology has not been used in applications similar to Hexcel’s operations.
Operation of an SCR requires installation of a baghouse to filter particulate from the exhaust prior to
entering the SCR to minimize catalyst plugging or poisoning. This would make the SCR an ineffective control
for the fiber line process. Currently, only Fiber Lines 13-16 are equipped with particulate control devices
(baghouse/filter box).
An SCR does not control emissions effectively at high temperatures, in excess of 1000 °F, as well as low
temperatures, below 700 °F. In order for the baghouse to operate properly, the air stream will need to be
cooled to a maximum of 450 °F. To operate the SCR after the baghouse, the air stream would be reheated
to above 700 °F. This would require significant operational expense and cause additional combustion related
emissions. Another drawback to the SCR system is additional ammonia emissions. Ammonia slip does not
remain constant as the SCR system operates but increases as the catalyst activity decreases. Ammonia is
considered as a precursor to the formation of PM2.5, for which the area is also nonattainment. For these
combined reasons, SCR technology is considered to be technically infeasible for controlling NOX emissions
from the Fiber Lines.
SNCR
Though simple in concept, it is challenging in practice to design an SNCR system that is reliable, economical,
simple to control, and meets other technical, environmental, and regulatory criteria. Practical application of
SNCR is limited by the system design and operating conditions.20 SNCR’s NOX control efficiency declines at
temperatures below 1600 °F. Proposed particulate capture for the system will be conducted through a
baghouse. In order for the baghouse to operate properly, the air stream will need to be cooled to a
maximum of 450 °F. To operate the SNCR after the baghouse, the air stream would be required to
be reheated to above 1600 °F. The Hexcel exhaust stream thus requires heating for effective NOX
destruction, which consequently increases combustion emissions and fuel cost.
Another drawback to the SNCR system is additional ammonia emissions associated with the ammonia
injection process. The normalized stoichiometric ratio defines the amount of reagent needed to achieve the
targeted NOX reduction in the SNCR system. Typical normalized stoichiometric ratio values require
significantly more reagent to be injected in practice than required by the theoretical stoichiometric ratio. In
20 SNCR System – Design, Installation and Operating Experience, David L. Wojichowski, De‐NOX Technologies LLC
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addition, the amount of NOX removed is generally much less than the amount of uncontrolled NOX. This
leaves a large portion of the injected reagent unreacted. Most of the excess reagent used in the process is
destroyed through other chemical reactions. However, a small portion remains in the flue gas as ammonia
slip.21 As noted in the previous section ammonia is considered as a precursor to the formation of PM2.5, for
which the area is also nonattainment.
Results of the RBLC search for similar operations, shown in Appendix C, further support that this type of
control technology has not been used in applications similar to Hexcel operations. For these reasons, SNCR
technology is considered to be technically infeasible.
Other Control Technologies
All other control technologies are considered technically feasible and will be carried through to Step 3 of the
analysis.
4.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness
Based on the information provided in the previous section, feasible technologies for control of NOX from the
Fiber Lines are the following, with most effective control first and least effective control last.
1. De-NOX,
2. ULNB,
3. LNB,
4. GCP, and
5. Use of Natural Gas Only as Fuel.
Emissions associated with implementation of the LNB technology were calculated assuming 50 percent
control efficiency.22 Emissions associated with implementation of the ULNB technology were calculated
assuming 68 percent control efficiency.23 De-NOX emission reduction can range from 60-80 percent.24 For
the purposes of calculating emission reductions from De-NOX was assumed to be 70 percent. No control
efficiency was estimated for either GCP or use of natural gas only as fuel.
4.1.4 Step 4 – Evaluate Most Effective Controls and Document Results
GCP and use of natural gas only as fuel are existing conditions for all fiber line combustion units. Therefore,
no additional analysis was completed for these two control technologies. In addition, Attachment A contains
information on which combustion units are already equipped with either LNB/De-NOX or ULNB technology.
21 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B‐02‐001 (https://www.epa.gov/economic-and-cost-
analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution); January 2002
22 AP‐42 Table 1.4‐1 – Emission Factors for Nitrogen Oxides (NOX) and Carbon Monoxide (CO) from Natural Gas Combustion.
Comparison of uncontrolled emissions from a small boiler (100 lb/106 scf) to controlled Low‐NOX burner emissions from a
small boiler (50 lb/106 scf). [1‐50/100 = 50%]
23 AP‐42 Table 1.4‐1 – Emission Factors for Nitrogen Oxides (NOX) and Carbon Monoxide (CO) from Natural Gas Combustion.
Comparison of uncontrolled emissions from a small boiler (100 lb/106 scf) to controlled Ultra‐Low‐NOX burner emissions from
a small boiler (32 lb/106 scf). [1‐32/100 = 68%]
24 EPA CAM Technical Guidance Document, Section B.17. Water or Steam Injection
(https://www3.epa.gov/ttnchie1/mkb/documents/B_17a.pdf), April 2002.
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For any combustion units that are already equipped with either of these technologies as an existing or
future required condition, no additional analysis has been completed.
Annualized costs associated with implementing the LNB, De-NOX, and ULNB technologies on Fiber Lines 2-7,
8, 10, 11 and 12 were calculated and are summarized in Attachment A for each of the Fiber Lines.
Supporting cost calculations are provided in Attachment B. The control costs range from $57,585 - $909,334
per ton of NOX removed, which is considered not cost effective.
It is also important to note that retrofit of burners on existing units in Fiber Lines 2, 5-8, 10, 11, and 12 to
incorporate NOX control technology would require many expensive operational adjustments to the ovens,
including:
► Demolition of existing operations;
► Redesign of hoods;
► Burner box (Ductwork, ID‐fan, and stack) redesign;
► Air flow adjustments;
► Gas line input retrofit; and
► Installation of pressure regulators.
A retrofit factor of 1.4 was included in the cost of installing the control based on documentation provided in
the OAQPS manual, however this likely does not represent the true additional costs associated with
retrofitting the older lines to incorporate newer burners.
Because proper oxidation is essential to the carbon stabilization process, redesign of the oven burner
operations would initiate a complete redesign of the Fiber Line process to achieve consistent production
levels. This redesign of the Fiber Lines would require significant loss in production for Hexcel. Costs
associated with lost production have been included in the total costs associated with the installation of LNB
for the older lines. However, they have conservatively not been included in the total costs associated with
the installation of other NOX controls for the older lines. For these reasons, this proposed technology is
considered to be cost prohibitive for controlling NOX emissions from Fiber Lines 2, 5-8, 10, 11, and 12.
4.1.5 Step 5 – Select RACT
Based on the RACT analysis detailed in Steps 1-4, GCP and use of natural gas as fuel is determined to be
NOX RACT for Fiber Lines 2, 5-8, 10, 11, and 12. As previously discussed, Fiber Lines 3, 4, and 7 are
required to implement ULNBs as BACT and Fiber Lines 13, 14, 15, and 16 are required to implement DeNOX
water as BACT in the PM2.5 Serious nonattainment SIP, so these lines are considered implementing RACT for
NOx. As a result, the following annual and short-term limits NOX limits are considered RACT for Fiber Lines
2, 5, 6, 8, and 10-12:25
► 69.05 tpy
► 15.77 lbs/hr
25 Includes Fiber Line Pilot Plant emissions based on the analysis in Section 4.3.
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4.2 RACT Analysis for VOC Emissions
4.2.1 Step 1 - Identify All Reasonably Available Control Technologies
Based on the review of U.S. EPA’s RBLC database and similar operations, Hexcel has identified the following
control technologies that could be applicable for controlling VOC emissions from the Fiber Lines:
1. GCP
2. Use of Natural Gas Only as Fuel
3. Open Flare
4. Incinerator/DFTO
5. RTO
The search of the RBLC database produced two carbon fiber manufacturing facilities. Results of this search
are presented in Attachment C. The permit for the first facility subject to SIP and operating permit
conditions required installation of a wet scrubber to control VOCs and acrylonitrile from Fiber Lines and
storage tanks. Note that the storage tanks for this facility were subject to NSPS Kb – Standards of
Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for
Which Construction, Reconstruction, or Modification Commenced After July 23, 1984. Hexcel does not use
any acrylonitrile in its fiber line process and does not have any tanks that trigger NSPS Kb. The permit for
the second facility subject to BACT for PSD did not have any control required for VOCs from the carbon fiber
process.
Additional searches of the database, for similar combustion units fired with natural gas were also conducted.
The results of these searches for VOC are also presented in Attachment C.
Good Combustion Practices
U.S. EPA’s RBLC database lists numerous operations where GCP are the accepted technology for minimizing
VOC emissions. GCP reduce VOC emissions by keeping the burners operating according to their design and
combust VOC as completely as possible while maintaining other emissions, such as NOX, to a minimum.
Use of Natural Gas Only as Fuel
Restricting fuel type to natural gas limits VOC emissions, because other fuel options, such as diesel or coal,
generate more VOC emissions per heat output. VOC emissions from natural gas combustion are lower than
emissions from any other readily available fuel.
Open Flare
Flaring is a volatile combustion control process for organic compound in which the VOCs are piped to a
remote, usually elevated, location and burned in an open flame in the open air using a specially designed
burner tip, auxiliary fuel, and steam or air to promote mixing for nearly complete (> 98 percent) VOC
destruction. Completeness of combustion in a flare is governed by flame temperature, residence time in the
combustion zone, turbulent mixing of the components to complete the oxidation reaction, and available
oxygen for free radical formation.26
26 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA 452‐02‐001, Daniel C. Mussatti & William M. Vatavuk,
January 2002. Section 3 VOC Controls, Section 3.2 VOC Destruction Controls, Chapter 1 Flares, p. 1‐3.
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Flares can be used to control almost any high concentration VOC stream, and can handle fluctuations in
VOC concentration, flow rate, heating value, and inert content. Flaring is appropriate for continuous, batch,
and variable flow vent stream applications.27
Incinerator/DFTO
Incineration and DFTO use similar technology and have similar requirements; therefore, they have been
combined and collectively referred to as “incineration” for the purposes of the RACT analysis.
A major advantage of incineration is that virtually any gaseous organic stream can be incinerated safely and
cleanly, provided proper engineering design is used. An incinerator system includes a combustion chamber
in which the VOC‐containing waste stream is burned. Since the inlet waste gas stream temperature is
generally much lower than that required for combustion, energy must be supplied to the incinerator to raise
the waste gas temperature. Seldom, however, is the energy released by the combustion of the total
organics (VOCs and others) in the waste gas stream sufficient to raise its own temperature to the desired
levels, so that auxiliary fuel (e.g., natural gas) must be added.
The heart of the thermal incinerator is a nozzle‐stabilized flame maintained by a combination of auxiliary
fuel, waste gas compounds, and supplemental air added when necessary. Upon passing through the flame,
the waste gas is heated from its inlet temperature to its ignition temperature. The ignition temperature
varies for different compounds and is usually determined empirically. It is the temperature at which the
combustion reaction rate (and consequently the energy production rate) exceeds the rate of heat losses,
thereby raising the temperature of the gases to some higher value. Thus, any organic/air mixture will ignite
if its temperature is raised to a sufficiently high level.
The organic‐containing mixture ignites at some temperature between the preheat temperature and the
reaction temperature. That is, ignition occurs at some point during the heating of a waste stream as it
passes through the nozzle‐stabilized flame regardless of its concentration. The mixture continues to react as
it flows through the combustion chamber.
The required level of VOC control of the waste gas that must be achieved within the time that it spends in
the thermal combustion chamber dictates the reactor temperature. The shorter the residence time, the
higher the reactor temperature must be. Once the unit is designed and built, the residence time is not easily
changed, so that the required reaction temperature becomes a function of the particular gaseous species
and the desired level of control.28
Regenerative Thermal Oxidizer
A flameless natural gas injection (NGI) dual chambered RTO system uses a bed of ceramic material to
absorb heat from the exhaust gas, and then uses the captured heat to preheat the incoming process gas
27 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA 452‐02‐001, Daniel C. Mussatti & William M. Vatavuk,
January 2002. Section 3 VOC Controls, Section 3.2 VOC Destruction Controls, Chapter 1 Flares, p. 1‐5.
28 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA 452‐02‐001, Daniel C. Mussatti & William M. Vatavuk,
January 2002. Section 3 VOC Controls, Section 3.2 VOC Destruction Controls, Chapter 2 Incinerators, p. 2‐6.
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stream. Emissions associated with implementation of the RTO technology were calculated assuming 98
percent control efficiency.29
RTOs are suited to applications with low VOC concentrations but high waste stream flow rates. This is due
to their high thermal energy recovery. The basic operation of an RTO consists of passing a hot gas stream
over a heat sink material in one direction and recovering that heat by passing a cold gas stream through
that same heat sink material in an alternate cycle. They are used to destroy air toxics and VOCs that are
discharged in industrial process exhausts. Once the proposed process is at steady state, the RTO is fueled
by both natural gas and other combustible gases (HCN, VOC) that off gas from the process.
4.2.2 Step 2 – Eliminate Technically Infeasible Options
None of the identified technologies are considered technically infeasible. However, since the Hexcel Facility
is near a populated area, a typical open flare system would not be a technology that should be implemented
due to the noise and open flame associated with such a system. For this reason, and the fact that there are
other VOC control technologies available, use of a flare will not be carried through to Step 3.
4.2.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness
Based on the information provided in the previous section, feasible technologies for control of VOC from the
Fiber Lines are the following, with most effective control first and least effective control last.
1. Incinerator/DFTO
2. RTO
3. GCP
4. Use of Natural Gas Only as Fue,l
4.2.4 Step 4 – Evaluate Most Effective Controls and Document Results
All of the Fiber Lines are currently equipped with either an incinerator or DFTO, so these controls will not be
discussed further in this analysis. In addition, GCP and use of natural gas only as fuel are existing conditions
for all of the Fiber Lines, so they will also not be discussed further in this analysis. In addition, Fiber Lines
13-16 are already equipped with an RTO.
Annualized costs associated with implementing the RTO on Fiber Lines 2, 5-7, 8, 10, 11, and 12 were
calculated and are summarized in Attachment A for each of the Fiber Lines. Supporting cost calculations are
provided in Attachment B. The control costs range from $54,696 - $2,323,628 per ton of VOC removed,
which is considered not cost effective.
4.2.5 Step 5 – Select RACT
Based on the RACT analysis detailed in Steps 1-4, GCP and use of natural gas as fuel is determined to be
VOC RACT for Fiber Lines 2-8 and 10-12. As Fiber Lines 13, 14, 15, and 16 have RTOs installed this is
considered BACT. As a result, this analysis includes the following annual and short term- VOC limits are
considered RACT for Fiber Lines 2, 5, 6, 8, and 10-12:30
29 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA 452‐02‐001, Daniel C. Mussatti & William M. Vatavuk,
January 2002. Section 3 VOC Controls, Section 3.2 VOC Destruction Controls, Chapter 2 Incinerators, p. 2‐7.
30 Includes Fiber Line Pilot Plant emissions based on analysis in Section 4.3.
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► 124.46 tpy
► 28.42 lbs/hr
4.3 RACT Analysis for Fiber Line Pilot Plant
In addition to the Fiber Line manufacturing operation, Hexcel also has a Fiber Line Pilot Plant, which is
essentially a small-scale research facility for the carbon fiber process.
The discussions of available controls and control feasibility (i.e., RACT Steps 1-3) provided for the main
Fiber Line operations also apply to the Pilot Plant operations. Attachment A presents the emissions
associated with the existing process operation, and the emissions once each control technology under
evaluation is applied. The supporting detailed calculations are provided in Attachment B.
Annualized costs associated with implementing proposed control technologies for the Pilot Plant are
summarized in Attachment A. Supporting cost calculations are provided in Attachment B. For NOX, the
annualized cost of LNB is $53,738 and ULNB is $39,514 which is not considered cost effective. In addition,
the potential emissions from this operation are very low, resulting in an emissions reduction of
approximately half a ton of NOX from either LNB or ULNB. In addition, the cost analysis is based on potential
emissions. Since the Pilot Plant is only a research facility, actual emissions are considerably lower than
potential emissions; therefore, the emissions reduction from adding NOX control would be negligible. Actual
emissions fluctuate, but 12-month total NOX emissions based on December 2022 data were 0.02 tpy, which
is less than 5 percent of potential emissions. Therefore, RACT for NOX is determined to be GCP and use of
only natural gas fuel.
The annualized cost of adding an RTO for VOC control is $2,506,691 per ton, which is not considered cost
effective. In addition, the amount of actual VOC emissions that would be controlled from this process is very
low. Therefore, RACT for VOC is determined to be GCP.
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5. RACT ANALYSIS FOR MATRIX
The Prepreg and Matrix operations consists of two distinct phases, the mixing of the solvated resin and the
application of the mixed resin to the woven graphite cloth/fabric. The production of the solvated resin
consists of mixing specified resins with measured amounts of methyl ethyl ketone (MEK) and/or acetone.
The MEK/acetone carrier allows the resin to distribute evenly over and into the fabric weave (impregnate).
The application of this resin into woven graphite fabric consists of a piece of machinery (solvent coater) with
a series of drive rollers, a dip bath, and a heated tower. The solvent coater assembly essentially
impregnates the woven graphite fabric with a specified amount of solvated resin.
Hexcel has recently upgraded the control technology associated with the Matrix Tower 1, Tower 3, and
Tower 4 incinerators. These upgrades include installation of a more efficient incinerator for Tower 1 and
RTOs for Towers 3 and 4 in place of the previously existing incinerators, all of which have combustion
related emissions. The incinerator associated with Tower 1 does not have a limit on NOX. The RTOs on
Towers 3 and 4 are equipped with LNB (maximum rating – 30 ppm NOX) on the main burners and duct
trim burners.
The discussion in Sections 1-3 regarding the available control technologies, technical feasibility of control
methods, and ranking of control methods for the Fiber Lines is also relevant to the Matrix operations.
Therefore, these Steps 1-3 will not be repeated here.
VOC emissions from resin handling and mixing and the pre-preg process as well as Towers 3 and 4 all
vent to RTO s which, based on previous steps in this analysis, is considered RACT. Therefore, these
operations are not included in the evaluation for VOC emissions from the Matrix operations. Therefore,
only VOC emissions from Tower 1 are included in the analysis.
5.1.1 Step 4 – Evaluate Most Effective Controls and Document Results
The emissions used in the cost evaluation includes both NOX and VOC from combustion. Annualized costs
associated with implementing proposed control technologies for the Matrix operation were calculated and
are summarized in Attachment A. Supporting cost calculations are provided in Attachment B.
For LNB, the cost analysis only includes NOX emissions from Tower 1, since Towers 3 and 4 are already
equipped with LNB. The control cost is $111,169 per ton of NOX removed, which is considered not cost
effective.
For ULNB, the cost analysis includes NOX emissions from all three towers. The control cost is $68,037 per
ton of NOX removed, which is not considered cost effective.
For the RTO, the cost analysis includes only VOC emissions from Tower 1 since Towers 3 and 4 are
already controlled by RTOs which is considered the highest level of control. The control cost is $120,602
per ton of VOC removed for Tower 1, which is considered not cost effective.
5.1.2 Step 5 – Select RACT
Based on the analysis in Steps 1-4, RACT for both NOX and VOC for the Matrix operation is determined to
be GCP and operation of all incinerators and burners with natural gas fuel, consistent with the Fiber Line
RACT determinations. In addition, the following annual and short term- limits for NOX and VOC from
Tower 1 is considered RACT:
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► NOX
• 6.15 tpy
• 1.40 lbs/hr
► VOC
• 4.00 tpy
• 0.91 lbs/hr
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6. BOILERS
Hexcel utilizes two natural gas boilers which have a maximum firing rate of 25 MMBtu/hr to support the
manufacturing process. These units have a maximum NOX emission rate of 9 ppm.
6.1 RACT Analysis for NOX Emissions
The NOX that will be formed during combustion is from two (2) major mechanisms: thermal NOX and fuel
NOX. Since natural gas is relatively free of fuel-bound nitrogen, the contribution of this second mechanism
to the formation of NOX emissions in natural gas-fired equipment is minimal, leaving thermal NOX as the
main source of NOX emissions. Thermal NOX formation is a function of residence time, oxygen level, and
flame temperature, and can be minimized by controlling these elements in the design of the combustion
equipment.
6.1.1 Step 1 – Identify All Reasonably Available Control Technologies
Hexcel reviewed a variety of sources including, but not limited to, the RBLC database, U.S. EPA fact sheets,
and proposed UDAQ rules to identify potentially applicable control technologies. The technologies identified
as possible NOX reduction are:
1. LNB,
2. ULNB,
3. FGR,
4. SCR, and
5. GCP.
The control efficiencies associated with the listed technologies, along with technical and economic feasibility,
are compared to the presumptive norm established in proposed UDAQ rule R307-316, NOX Emission
Controls for Natural-Gas Fired Boilers greater than 5 MMBtu/hr, which requires the following:
► NOX Emission Rate of 9 ppmv; and
► Operate and Maintain (O&M) in accordance with manufacturer's instruction.
6.1.2 Step 2 – Eliminate Technically Infeasible Options
To demonstrate a complete analysis, Hexcel has evaluated the following technologies including both
replacement burners and add-on controls.
Low NOX Burners
LNB technology uses advanced burner design to reduce NOX formation through the restriction of oxygen,
flame temperature, and/or residence time. There are two (2) general types of LNB: staged fuel and staged
air burners. In a stage fuel LNB, the combustion zone is separated into two (2) regions. The first region is a
lean combustion region where a fraction of the fuel is supplied with the total quantity of combustion air.
Combustion in this zone takes place at substantially lower temperatures than a standard burner. In the
second combustion region, the remaining fuel is injected and combusted with left over oxygen from the first
region. A staged air burner begins with full fuel but only partial combustion air, and then adds the remaining
combustion air in the second combustion region. These techniques reduce the formation of thermal NOX.
This technology is listed in the RBLC search as a technically feasible control technology.
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Ultra-Low NOX Burners
ULNB technology uses internal FGR which involves recirculating the hot O2 depleted flue gas from the heater
into the combustion zone using burner design features and fuel staging to reduce NOX. An ULNB is most
commonly using an internal induced draft to reach the desired emission limitations. This technology is listed
in the RBLC search as a technically feasible control technology. An ULNB can achieve an emission rate of
approximately 9 ppm or 0.011 pounds per million British thermal units (lb/MMBtu) when used in conjunction
with FGR.
Flue Gas Recirculation
FGR is frequently used with both LNB and ULNB burners. FGR involves the recycling of post-combustion air
into the air-fuel mixture to reduce the available oxygen and help cool the burner flame. External FGR
requires the use of ductwork to route a portion of the flue gas in the stack back to the burner windbox; FGR
can be either forced draft (where hot side fans are used) or induced draft. This technology is listed in the
RBLC search as technically feasible and is paired with LNB for the BACT determined control technology.
Selective Catalytic Reduction
SCR has been applied to stationary source, fossil fuel-fired, combustion units for emission control since the
early 1970s. It has been applied to utility and industrial boilers, process heaters, and combined cycle gas
turbines. SCR can be applied as a stand-alone NOX control or with other technologies such as combustion
controls. The reagent reacts selectively with the flue gas NOX within a specific temperature range and in the
presence of the catalyst and oxygen to reduce the NOX into molecular nitrogen (N2) and water vapor
(H2O).31 The optimum operating temperature is dependent on the type of catalyst and the flue gas
composition. Generally, the optimum temperature ranges from 480°F to 800°F.32 In practice, SCR systems
operate at efficiencies in the range of 70 to 90 percent.33 SCR is listed in the RBLC search as technically
feasible. In some cases, this control technology is listed in combination with LNB and FGR.
Good Combustion Practices
The use of GCP usually includes the following components: (1) proper fuel mixing in the combustion zone;
(2) high temperatures and low oxygen levels in primary zone; (3) Overall excess oxygen levels high enough
to complete combustion while maximizing boiler efficiency, and (4) sufficient residence time to complete
combustion. GCP are accomplished through boiler design as it relates to time, temperature, and turbulence,
and boiler operation as it relates to excess oxygen levels.
6.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness
Based on an RBLC search the following technologies are currently being used for boilers between 0
MMBtu/hr and 25 MMBtu/hr. These are ranked based on which technology can achieve the lowest emission
rate.
31 Ibid.
32 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001
(http://www.epa.gov/ttn/catc/dir1/c_allchs.pdf); January 2002
33 OAQPS, EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/424/B-02-001
(http://www.epa.gov/ttn/catc/dir1/c_allchs.pdf); January 2002
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1. LNB + SCR = 5 ppm or less
2. ULNB = 9 ppm or 0.011 lb/MMBtu
3. LNB = 30 ppm or 0.036 lb/MMBtu
4. FGR = 42 ppm or 0.05 lb/MMBtu
6.1.4 Step 4 – Evaluate Most Effective Controls and Document Results
An SCR may be installed on each boiler to further lower the emission rate. Hexcel conducted a cost analysis
following the method described in U.S. EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic
Reduction Costs. Key to this analysis is the reduction removal efficiency and interest rate. For this analysis,
Hexcel has used a reduction rate equivalent to a decreased emission rate of 5 ppm NOX.34
Since the actual nominal interest rate for a project of this type is not readily available to Hexcel, additional
resources were reviewed to determine appropriate nominal interest rates for this industry sector and project
type. One such resource was the Office of Management and Budget (OMB). For economic evaluations of the
impact of federal regulations, the OMB uses an interest rate of 7 percent.35 A nominal interest rate of 7
percent has been referenced in U.S. EPA’s Cost Manual and has been commonly relied upon for control
technology analyses for several decades as a representative average over time.
Based on a 5 ppm NOX emission rate and 7 percent interest rate the cost per ton removed is $239,731.
Calculations are shown in Appendix A and are based on U.S. EPA Cost Control Manual Section 4 Chapter 2
Selective Catalytic Reduction Costs and Section 1 Chapter 2 Cost Estimation: Concepts and Methodology.
The cost per ton of NOX removed is beyond acceptable cost control effectiveness levels and therefore,
Hexcel has determined that this technology is not cost effective for these units.
6.1.5 Step 5 – Select RACT
The presumptive norm for the units in question is 9 ppm and O&M in accordance with manufacturer’s
instructions. Hexcel meets the 9 ppm emission rate and completes O&M in accordance with manufacturer
recommendations; however, the addition of SCR is not cost effective. As a result, Hexcel proposes that an
emission rate of 9 ppm and appropriate O&M meet RACT.
6.2 RACT Analysis for VOC Emissions
6.2.1 Steps 1-5 – Select RACT
Hexcel reviewed a variety of sources including, but not limited to, the RBLC database, U.S. EPA fact sheets,
and proposed UDAQ rules to identify potentially applicable control technologies. The only control method
identified was GCP.
GCP for VOCs includes adequate fuel residence times, proper fuel-air mixing, and temperature control. As it
is imperative for process controls, Hexcel will maintain combustion optimal to its process.
Since all control methods identified are in use, Hexcel proposes RACT for the boilers is GCP and the use of
clean burning fuel.
34 This emissions rate is representative of LAER. 35 OMB Circular A-4, https://obamawhitehouse.archives.gov/omb/circulars_a004_a-4/
Hexcel / Ozone RACT Analysis
Trinity Consultants 7-1
7. EMERGENCY GENERATORS
Diesel-fired engines are classified as compression ignition (CI) internal combustion engines (ICE). The
primary pollutants in the exhaust gases include NOX and VOC. The diesel-fired engines installed at the
Hexcel West Valley City Plant are for emergency use only (except for readiness testing and maintenance)
and will use diesel fuel meeting the requirements of 40 CFR 1090.305 for non-road diesel fuel (i.e., a
maximum sulfur content of 15 ppm and either a minimum cetane index of 40 or a maximum aromatic
content of 35 percent by volume).
Hexcel has multiple diesel-fired emergency generators permitted in Approval Order DAQE-AN113860035-22.
► Hexcel has small diesel-fired emergency generator engines that are each rated less than 600 HP and
having a combined total capacity of up to 2,806 HP.
► Hexcel also has large diesel-fired emergency generator engines that are each rated greater than 600 HP
and have a combined total capacity of up to 12,732 HP.
U.S. EPA’s RBLC was queried to identify controls for other similar-sized emergency generator engines. The
RBLC shows that most diesel-fired emergency generator engines have RACT emission limits or permitted
emission limits under other regulatory programs at the promulgated 40 CFR Part 60 Subpart IIII Standards
of Performance for Stationary Compression Ignition Internal Combustion Engines (NSPS Subpart IIII)
emissions standards. The purpose and use of the engine are important considerations if an engine goes
beyond NSPS Subpart IIII standards. Presented below are the five steps of the top-down RACT review for
diesel-fired emergency generator engines.
7.1 RACT Analysis for NOX and VOC Emissions
7.1.1 Step 1 – Identify All Reasonably Available Control Technologies
The least stringent emission rate allowable for RACT is any applicable limit under either NSPS – Part 60 or
National Emission Standards for Hazardous Air Pollutants (NESHAP – Part 63). Emission limits for diesel-fired
engines are limited by U.S. EPA’s Tier program established in 40 CFR 1039 and are referenced by NSPS
Subpart IIII.36 Under these regulations U.S. EPA requires manufacturers to reduce the emissions from
engines produced after certain dates in a tiered fashion, based on the size and model year. In general, the
higher the tier rating, the lower the emissions produced.
The engines evaluated under this RACT analysis are rated for emergency use only. Per NSPS Subpart IIII
section 60.4202, U.S. EPA only requires emergency use engines to meet Tier 2 or Tier 3 standards based on
the size of the unit.37 U.S. EPA established Tier 3 standards for all units rated between 50 BHP and 750 BHP
and Tier 2 standards for all units rated above 750 BHP.
It is the manufacturer’s responsibility to ensure that these units meet the established emission limitations or
Tier rating. In order to ensure these emission limitations are met, manufacturers often incorporate design
elements, such as turbochargers, aftercoolers, positive crankcase ventilation, and high-pressure fuel
36 Non-Emergency regulated per 40 CFR 60.4201, Emergency regulated by 40 CFR 60.4202, and General Requirements
regulated per 40 CFR 60.4203.
37 Emergency engines are regulated in 40 CFR 60.4202 which sites only 40 CFR 1039.104, 1039.105, and 1039.15. Tier 4 final
and Tier 4 interiem standards are given in 40 CFR 1039.101 and 1039.102, respectively, which are not referenced.
Hexcel / Ozone RACT Analysis
Trinity Consultants 7-2
injection. The incorporation of these design elements allows the units to meet minimum RACT standards
and are therefore not further considered in this analysis.
In order to identify additional control technologies applied to emergency use engines the following sources
were reviewed:
► U.S. EPA’s RBLC Database for Diesel Generators (process types 17.110 Large Internal Combustion
Engines [>500 HP] burning Fuel Oil and 17.210 Small Internal Combustion Engines [<500 HP] burning
Fuel Oil);38
► U.S. EPA’s Air Pollution Control Technology Fact Sheets;
► South Coast Air Quality Management District Example Permits;
► Texas Commission of Environmental Quality’s BACT Combustion Workbook; and
► Bay Area Air Quality Management District Nonroad BACT Assessments.39
The following control methods have been identified as potentially feasible for control of emissions from
emergency generator engines:
► Limited Hours of Operation;
► GCP;
► Exhaust Gas Recirculation (EGR);
► Diesel Oxidation Catalyst (DOC); and
► SCR.
7.1.2 Step 2 – Eliminate Technically Infeasible Options
Limited Hours of Operation
One of the options to control the emissions of all pollutants released from emergency generator engines is
to limit the hours of operation for the equipment. Due to the designation of this equipment as emergency
equipment, only 100 hours of operation for maintenance and testing are permitted per NSPS Subpart IIII.40
Therefore, limiting hours of operation is considered technically feasible.
Good Combustion Practices
GCP refers to the operation of engines at high combustion efficiency, which reduces the products of
incomplete combustion, such as VOC and CO. Emergency generator engines are designed to achieve high
combustion efficiency when maintained and operated according to the manufacturer’s written instructions.
GCP are considered technically feasible.
Exhaust Gas Recirculation
38 Database accessed January 20, 2023.
39 BAAQMD presumes Tier 4 retrofit or Tier 4 compliant to meet BACT, which is defined as “The most stringent levels of
control” and does not meet the presumptive norm established as RACT.
https://www.baaqmd.gov/~/media/files/engineering/backup-diesel-generators/bact-webinar-presentation-
pdf.pdf?la=en&rev=b12528d5cc11499c8e7e4a4aaa19b2eb
40 40 CFR 60.4211(f)(2)
Hexcel / Ozone RACT Analysis
Trinity Consultants 7-3
NOX reduction can be achieved through recirculating exhaust into the engine. EPA tests have demonstrated
NOX reduction up to 50 percent if the engine timing is retarded, but test results are accompanied by an
increase in particulates.41 Computer based control schemes can assist in NOX reduction with associated
timing retardation, but EGR can also result in heat rejection, reduced power density, and lower fuel
economy. Exhaust gas recirculation is considered technically infeasible.
Diesel Oxidation Catalyst
A DOC utilizes a catalyst such as platinum or palladium to oxidize VOC emissions in the engine’s exhaust to
carbon dioxide (CO2) and water. Use of a DOC can result in approximately 90 percent reduction in VOC
emissions.42 In addition to controlling VOC, a DOC also has the potential to reduce PM emissions by 30
percent (based on the concentration of soluble organics).43 However, the full reduction potential requires a
minimum operating temperature of 150 ºC (300 ºF).44 Similarly U.S. EPA recommends if an engine emits
extremely high levels of PM and/or idles for long periods of time, an exhaust backpressure monitoring and
operator notification system may be installed to notify the operator when maintenance is needed.45 For this
reason, DOC control efficiencies are expected to be relatively low during the first 20 - 30 minutes after
engine start up, in fact U.S. EPA considered this method of aftertreatment to be generally unsuitable for
backup use.46 Since operation of emergency engines typically only includes short duration runs and Hexcel
does not require the engine to be brought to full load for monthly maintenance and testing, The engines are
brought to full load during annual testing. DOC is considered technically ineffective for maintenance and
testing.47
DOC is typically installed by manufacturers on prime engines and thus is considered technically infeasible for
emergency operation.
Selective Catalytic Reduction
SCR systems introduce a liquid reducing agent such as ammonia or urea into an engine’s flue-gas stream
prior to a catalyst. The catalyst reduces the temperature needed to initiate the reaction between the
reducing agent and NOX to form nitrogen and water. Additional variations including non-selective catalytic
reduction (NSCR) and selective non-catalytic reduction (SNCR) may be used but are not considered standard
industry practice and are not listed in the RBLC, thus SCR remains the focus of this technical analysis.
41 U.S. EPA Control of Heavy-Duty Diesel NOx Emissions by Exhaust gas recirculation, Office of Mobile Source Air Pollution
Emissions Control Technology Division, August 1985
42 U.S. EPA, Alternative Control Techniques Document: Stationary Diesel Engines, March 5, 2010, p. 41.
(https://www.epa.gov/sites/production/files/2014-02/documents/3_2010_diesel_eng_alternativecontrol.pdf)
43 Response to Public Comments on Notice of Reconsideration of National Emission Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines and New Source Performance Standards for Stationary Internal
Combustion Engines, EPA Docket EPA-HQ-OAR-2008-0708, June 16, 2014
44 U.S. EPA’s Technical Bulletin for Diesel Oxidation Catalyst Installation, Operation, and Maintenance, EPA-420-F-10-030
published in May 2010.
45 Ibid.
46 Response to Public Comments on Notice of Reconsideration of Nation,al Emission Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines and New Source Performance Standards for Stationary Internal
Combustion Engines, EPA Docket EPA-HQ-OAR-2008-0708, Page 85, June 16, 2014 47 Annual testing requires the engines being brought to full load, but this is a small percentage of the overall maintenance and testing operation time.
Hexcel / Ozone RACT Analysis
Trinity Consultants 7-4
For SCR systems to function effectively, exhaust temperatures must be high enough (480 °F to 800 °F) to
enable catalyst activation, which will be accounted for in operation.48 For this reason, SCR control
efficiencies are expected to be relatively low during the first 20 - 30 minutes after engine start up. Since
operation of emergency engines typically only includes short duration runs for maintenance and testing, SCR
is considered technically ineffective for maintenance and testing on a small engine. Furthermore, for
emergency engines under 600 HP, the use of an SCR is generally considered experimental. Due to the low
emission reduction potential on an emergency unit of this size these controls are not standard practice for
manufacturers.49 This leads to compromised equipment design and high potential for failure.
Based on the technical considerations presented above a SCR is considered technically feasible for
emergency operation of units with a power rating greater than 600 HP.
7.1.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness
Effective control technologies for diesel engines are listed in the following table:
Table 7-1. Ranked Emergency Engine Controls
Control
Technically
Feasible under
600 HP?
(Yes/No)
Technically
Feasible above
600 HP?
(Yes/No)
Limited Hours of Operation Yes Yes
GCP Yes Yes
EGR No No
DOC No No
SCR No Yes
All emergency engines installed after 2006 at Hexcel meet the NSPS standards. For generators that were
installed prior to 2006, they met the EPA tier rating required at the time of installation. Additionally, all units
proposed will operate for limited hours, using good combustion practices, and fueled by ultra-low sulfur
diesel. The table below presents a summary of the proposed power rating and proposed technologies for
each generator addressed in application.
7.1.4 Step 4 – Evaluate Most Effective Controls and Document Results
As SCR control technology is technically feasible for emergency operation of units over 600 HP, Hexcel has
conducted a cost analysis using the similar size generators (rated at 728 HP) as a baseline. Because of the
negligible difference in engine size, the cost analysis is expected to be representative of all engines over 600
HP.
SCR
This cost analysis focused on NOX as the reduction potential for this pollutant is greater than all other
criteria pollutants. Based on correspondence with a reputable manufacturer the approximate cost of add-on
48 EPA Air Pollution Control Technology Fact Sheet for Selective Catalytic Reduction (SCR), EPA-452/F-03-032
49 Call conducted with engine manufacturer on April 13, 2022
Hexcel / Ozone RACT Analysis
Trinity Consultants 7-5
SCR controls is $159,500. After considering economic factors and other annual costs the calculated cost per
ton removed is $72,070 per ton removed. Hexcel believes that this is not cost effective and was not further
considered. A full cost analysis is included in Appendix C.
7.1.5 Step 5 – Select RACT
Hexcel is proposing to install all technically and economically feasible controls which generally include
engine design consistent with NSPS IIII, limited hours of operation, GCP and use of ULSD. Emission rates
reflecting this RACT are included in the calculations contained in Appendix A.
Hexcel / Ozone RACT Analysis
Trinity Consultants 8-1
8. OTHER SMALL NATURAL GAS FURNACES
There are several small muffle, rooftop, and other furnaces utilized to maintain appropriate temperatures
within manufacturing spaces. As these units are < 5 MMBtu/hr and are direct fired add on controls are not
technically feasible and have not been considered.
8.1 RACT Analysis for NOX Emissions
8.1.1 Step 1 – Identify All Reasonably Available Control Technologies
Hexcel reviewed a variety of sources including, but not limited to, the RBLC database, U.S. EPA fact sheets,
and proposed UDAQ rules to identify potentially applicable control technologies. The technologies identified
as possible NOX reduction are:
1. LNB,
2. ULNB, and
3. GCP.
No presumptive norm has been previously established for these units.
8.1.2 Step 2 – Eliminate Technically Infeasible Options
To demonstrate a complete analysis, Hexcel has evaluated the following technologies.
Low NOX Burners
LNB technology uses advanced burner design to reduce NOX formation through the restriction of oxygen,
flame temperature, and/or residence time. These techniques reduce the formation of thermal NOX. This
technology is listed in some of the reviewed resources as a BACT limit.
Ultra-low NOX Burners
ULNB technology uses internal FGR which involves recirculating the hot O2 depleted flue gas from the heater
into the combustion zone using burner design features and fuel staging to reduce NOX. This technology is
listed in some of the reviewed resources as a BACT limit.
Good Combustion Practices
GCP are accomplished through furnace design as it relates to time, temperature, oxygen levels, and
turbulence. Operation and maintenance in accordance with manufacturer recommendations is also
considered a good combustion practice.
8.1.3 Steps 3 – 5
Based on an RBLC and other resources reviewed, the only commonly utilized control method for units
similar to those installed at Hexcel is GCP and using natural gas. As a result, Hexcel proposes the
implementation of GCP as RACT. If installed after 2006, all natural gas combustion sources are required to
be low NOx burners in accordance with R307-401-4(3). Due to the size of most these units (<5 MMBtu), low
emissions rates, and retrofit requirements, replacing burners with a ULNB is not cost effective. In addition,
consideration needs to be given that installing a ULNB is not a typical configuration or design for HVAC units
Hexcel / Ozone RACT Analysis
Trinity Consultants 8-2
and would be very difficult to retrofit. For the larger units (>5 MMBtu) a cost analysis is included in
Attachment A with supporting documentation included in Appendix B. The cost per ton removed for an SCR
is $137,580 and for ULNB is $138,743 for the largest HVAC units. The cost per ton of NOX removed
increases as the HVAC unit size decreases. As a result, additional controls for smaller HVAC units are
considered not cost effective.
8.2 RACT Analysis for VOC Emissions
8.2.1 Steps 1 – 5
Hexcel reviewed a variety of sources including, but not limited to, the RBLC database, U.S. EPA fact sheets,
and proposed UDAQ rules to identify potentially applicable control technologies. The only control method
identified was GCP.
GCP for VOCs include adequate fuel residence times, proper fuel-air mixing, and temperature control. As it
is imperative for process controls, Hexcel will maintain combustion optimal to its process.
Since all control methods identified are in use, Hexcel proposes RACT for the small gas furnaces is GCP and
the use of clean burning fuel.
Hexcel / Ozone RACT Analysis
Trinity Consultants 9-1
9. RACT ANALYSIS FOR LABORATORY AND R&T FACILITY
In 2023 Hexcel finished construction and put into operation a new laboratory and Research &Technology
(R&T) facility at the West Valley City Plant. As a part of the Approval Order that was issued in October 2022,
Hexcel submitted a BACT analysis with its Notice of Intent (NOI) air permit application. None of the control
technologies or cost estimates have changed substantially since the time of application submittal. Therefore,
Hexcel is not submitting a RACT analysis for the new R&T Facility at this time.
Hexcel / Ozone RACT Analysis
Trinity Consultants A-1
APPENDIX A. COST EFFECTIVENESS ANALYSIS
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 2
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
LNB Existing
Incineration/ Flares
ULNB with FGR Thermal Oxidization
SCR
SNCR
NOX VOC
0.50 0.13
0.50 0.13
0.50 0.13
0.25 0.13
0.16 2.63E-03
NA1
NA1
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
$227,333.4 -$
0.250
909,334$ -$
NOX VOC
227,333$ 299,218$
0.340 0.13
668,628$ 2,323,628$
1 -Not technically feasible
Table A-1. Ozone RACT Summary - Fiber Line 2
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Controlled Emissions Table (tpy):
Emission Reduction (tpy)
Annualized Cost ($)
Cost Effectiveness ($/ton)
Emission Reduction (tpy)
Annualized Cost ($)
RACT option 3
RACT option 2
RACT option 1
Existing Allowable Emissions
RACT option 6
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tpy)
Option 2 Cost/Benefit Analysis Summary
RACT Option Analysis
Option 1 Cost/Benefit Analysis Summary
RACT option 6
RACT option 5
RACT option 4
RACT option 5
RACT option 4
RACT option 3
RACT option 2
RACT option 1
Cost Effectiveness ($/ton)
Emission Reduction (tpy)
Annualized Cost ($)
Cost Effectiveness ($/ton)
Hexcel | West Valley City Plant Page 1 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 3
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
SCR Existing
Incineration/ Flares
SNCR Thermal Oxidization
NOX VOC
NA 4.68
NA1 4.68
NA2 4.68
NA3 4.68
NA3 0.09
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ 665,091$
4.58
-$ 145,080$
1 -Considered technically feasible and cost effective
2 -Lower control efficiency than existing or future requirement
3 -Not technically feasible
Table A-2. Ozone RACT Summary - Fiber Line 3
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 4
RACT option 3
RACT option 2
RACT option 1
Annualized Cost ($)
Existing Allowable Emissions
Option 2 Cost/Benefit Analysis Summary
RACT option 4
RACT option 3
RACT option 2
RACT option 1
Option 1 Cost/Benefit Analysis Summary
Cost Effectiveness ($/ton)
Emission Reduction (tpy)
Annualized Cost ($)
Cost Effectiveness ($/ton)
Emission Reduction (tpy)
Annualized Cost ($)
Cost Effectiveness ($/ton)
Cost Effectiveness ($/ton)
Emission Reduction (tpy)
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Emission Reduction (tpy)
Annualized Cost ($)
Hexcel | West Valley City Plant Page 2 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 4
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
SCR Existing
Incineration/ Flares
SNCR Thermal Oxidization
NOX VOC
NA 6.90
NA1 6.90
NA2 6.90
NA3 6.90
NA3 0.14
NOX VOC
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ 709,563$
6.76
-$ 105,007$
1 -Considered technically feasible and cost effective
2 -Lower control efficiency than existing or future requirement
3 -Not technically feasible
Table A-3. Ozone RACT Summary - Fiber Line 4
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 2
RACT option 3
RACT option 4
Existing Allowable Emissions
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tons)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Cost Effectiveness ($/ton)
RACT option 1
RACT option 2
RACT option 3
RACT option 4
Option 1 Cost/Benefit Analysis Summary
Option 2 Cost/Benefit Analysis Summary
Annualized Cost ($)
Emission Reduction (tpy)
Hexcel | West Valley City Plant Page 3 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 5
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
LNB Existing
Incineration/ Flares
ULNB with FGR Thermal Oxidization
SCR
SNCR
NOX VOC
21.21 5.34
NA1 5.34
NA1 5.34
10.61 5.34
6.79 0.11
NA2
NA2
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
$830,713.6 -$
10.61
78,316$ -$
NOX VOC
830,714$ 774,563$
14.43 5.23
57,585$ 148,081$
1 -Considered technically feasible and cost effective
2 -Not technically feasible
Table A-4. Ozone RACT Summary - Fiber Line 5
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 2
RACT option 3
RACT option 4
RACT option 5
RACT option 6
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Option 2 Cost/Benefit Analysis Summary
Existing Allowable Emissions
RACT option 1
RACT option 2
RACT option 3
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
RACT option 4
RACT option 5
RACT option 6
Annualized Cost ($)
Option 1 Cost/Benefit Analysis Summary
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Hexcel | West Valley City Plant Page 4 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 6
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
LNB Existing
Incineration/ Flares
ULNB with FGR Thermal Oxidization
SCR
SNCR
NOX VOC
14.10 12.09
NA1 12.09
NA1 12.09
7.05 12.09
4.51 0.24
NA2
NA2
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
1,278,364$ -$
7.05
181,391$ -$
NOX VOC
1,278,364$ 666,053$
9.58 11.85
133,376$ 56,215$
1 -Considered technically feasible and cost effective
2 -Not technically feasible
Table A-5. Ozone RACT Summary - Fiber Line 6
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 2
RACT option 3
RACT option 4
RACT option 5
RACT option 6
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Option 2 Cost/Benefit Analysis Summary
Existing Allowable Emissions
RACT option 1
RACT option 2
RACT option 3
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
RACT option 4
RACT option 5
RACT option 6
Annualized Cost ($)
Option 1 Cost/Benefit Analysis Summary
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Hexcel | West Valley City Plant Page 5 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 7
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
SCR Existing
Incineration/ Flares
SNCR Thermal Oxidization
NOX VOC
NA 6.01
NA1 6.01
NA2 6.01
NA3 6.01
NA3 0.12
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ 843,724$
5.89
-$ 143,344$
1 -Considered technically feasible and cost effective
2 -Lower control efficiency than existing or future requirement
3 -Not technically feasible
Table A-6. Ozone RACT Summary - Fiber Line 7
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 2
RACT option 3
RACT option 4
Existing Allowable Emissions
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Cost Effectiveness ($/ton)
RACT option 1
RACT option 2
RACT option 3
RACT option 4
Option 1 Cost/Benefit Analysis Summary
Option 2 Cost/Benefit Analysis Summary
Annualized Cost ($)
Emission Reduction (tpy)
Hexcel | West Valley City Plant Page 6 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 8
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
LNB Existing
Incineration/ Flares
ULNB with FGR Thermal Oxidization
SCR
SNCR
NOX VOC
8.10 24.73
NA1 24.73
NA1 24.73
4.05 24.73
2.59 0.49
NA2
NA2
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
$1,396,720.1 -$
4.05
344,909$ -$
NOX VOC
1,396,720$ 1,455,122$
5.51 24.23
253,610$ 60,050$
1 -Considered technically feasible and cost effective
2 -Not technically feasible
Table A-7. Ozone RACT Summary - Fiber Line 8
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 2
RACT option 3
RACT option 4
RACT option 5
RACT option 5
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Option 2 Cost/Benefit Analysis Summary
Existing Allowable Emissions
RACT option 1
RACT option 2
RACT option 3
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
RACT option 4
RACT option 5
RACT option 6
Annualized Cost ($)
Option 1 Cost/Benefit Analysis Summary
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Hexcel | West Valley City Plant Page 7 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fibler Line 10
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
LNB Existing
Incineration/ Flares
ULNB with FGR Thermal Oxidization
SCR
SNCR
NOX VOC
8.10 24.44
NA1 24.44
NA1 24.44
4.05 24.44
2.59 0.49
NA2
NA2
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
$2,626,585.1 -$
4.05
648,615$ -$
NOX VOC
2,626,585$ 1,455,122$
5.51 23.95
476,923$ 60,764$
1 -Considered technically feasible and cost effective
2 -Not technically feasible
Table A-8. Ozone RACT Summary - Fiber Line 10
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 4
RACT option 3
RACT option 2
Emission Reduction (tpy)
Annualized Cost ($)
Option 2 Cost/Benefit Analysis Summary
Cost Effectiveness ($/ton)
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Emission Reduction (tpy)
Annualized Cost ($)
Cost Effectiveness ($/ton)
Cost Effectiveness ($/ton)
Emission Reduction (tpy)
Annualized Cost ($)
Cost Effectiveness ($/ton)
RACT option 5
RACT option 5
RACT option 4
RACT option 3
RACT option 2
RACT option 1
Existing Allowable Emissions
Option 1 Cost/Benefit Analysis Summary
RACT option 6
RACT option 5
Emission Reduction (tpy)
Annualized Cost ($)
Hexcel | West Valley City Plant Page 8 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 11
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
LNB Existing
Incineration/ Flares
ULNB with FGR Thermal Oxidization
SCR
SNCR
NOX VOC
8.10 24.92
NA1 24.92
NA1 24.92
4.05 24.92
2.59 0.50
NA2
NA2
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
2,626,819$ -$
4.05
648,673$ -$
NOX VOC
2,626,819$ 1,335,525$
5.51 24.42
476,965$ 54,696$
1 -Considered technically feasible and cost effective
2 -Not technically feasible
Table A-9. Ozone RACT Summary - Fiber Line 11
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 2
RACT option 3
RACT option 4
RACT option 5
RACT option 5
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Option 2 Cost/Benefit Analysis Summary
Existing Allowable Emissions
RACT option 1
RACT option 2
RACT option 3
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
RACT option 4
RACT option 5
RACT option 6
Annualized Cost ($)
Option 1 Cost/Benefit Analysis Summary
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Hexcel | West Valley City Plant Page 9 of 23 Trinity Consultants
Hexcel - Cost Analysis for Fiber Lines
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Fiber Line 12
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
LNB Existing
Incineration/ Flares
ULNB with FGR Thermal Oxidization
SCR
SNCR
NOX VOC
8.10 24.50
NA1 24.50
NA1 24.50
4.05 24.50
2.59 0.49
NA2
NA2
NOX VOC
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
2,626,819$ -$
4.05
648,673$ -$
NOX VOC
2,626,819$ 1,335,525$
5.51 24.01
476,965$ 55,613$
1 -Considered technically feasible and cost effective
2 -Not technically feasible
RACT option 5
RACT option 5
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
RACT option 5
Existing Allowable Emissions
RACT option 1
RACT option 6
Table A-10. Ozone RACT Summary - Fiber Line 12
Option 1 Cost/Benefit Analysis Summary
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 2
RACT option 3
RACT option 4
RACT option 2
RACT option 3
RACT option 4
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Option 2 Cost/Benefit Analysis Summary
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Annualized Cost ($)
Emission Reduction (tpy)
Cost Effectiveness ($/ton)
Hexcel | West Valley City Plant Page 10 of 23 Trinity Consultants
Hexcel - Cost Analysis for Pilot Fiber Line
Site Name:
Hexcel Corporation
Salt Lake City
Operations
Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Site Location:Pilot Fiber Line
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
Low NOx Burner Existing
Incineration/ Flares
Ultra Low NOx
Burner with Flue Gas
Recirculation
Thermal Oxidization
Selective Catalytic
Reduction
Selective Non-
Catalytic Reduction
NOX VOC
0.85 0.20
0.85 0.20
0.85 0.20
0.42 0.20
0.27 4.04E-03
NA1
NA1
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
$22,751.6 -$
0.42
53,738$ -$
NOX VOC
$22,751.6 $495,619
0.58 0.20
39,514$ 2,506,691$
1 -Not technically feasible
Table A-11. Ozone RACT Summary - Pilot Fiber Line
RACT Option Analysis
Controlled Emissions Table (tpy):
RACT option 1
RACT option 2
RACT option 3
RACT option 4
RACT option 5
RACT option 5
Emission Reduction (tons)
Cost Effectiveness ($/ton)
Option 2 Cost/Benefit Analysis Summary
Existing Allowable Emissions
RACT option 1
RACT option 2
RACT option 3
Annualized Cost ($)
Emission Reduction (tons)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Annualized Cost ($)
Emission Reduction (tons)
Cost Effectiveness ($/ton)
RACT option 4
RACT option 5
RACT option 6
Annualized Cost ($)
Option 1 Cost/Benefit Analysis Summary
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Emission Reduction (tons)
Cost Effectiveness ($/ton)
Hexcel | West Valley City Plant Page 11 of 23 Trinity Consultants
Hexcel - Cost Analysis for Matrix Operations
Site Name:Hexcel Corporation Salt
Lake City Operations Site Location:West Valley City, UT
Owner Name:Hexcel Corporation Component
Description:Matrix Operations
NOX VOC
Good Combustion
Practices
Good Combustion
Practices
Natural Gas Natural Gas
Low NOx Burner Existing Incineration/
Flares
Ultra Low NOx Burner
with Flue Gas
Recirculation
Thermal Oxidization
Selective Catalytic
Reduction
Selective Non-Catalytic
Reduction
NOX VOC
6.15 4.00
6.15 4.00
6.15 4.00
1.36 4.00
3.94 0.08
NA1
NA1
NOX VOC
-$ -$
-$ -$
NOX VOC
-$ -$
-$ -$
NOX VOC
150,634$ -$
1.36
111,169$ -$
NOX VOC
150,634$ 472,758$
2.21 3.92
68,037$ 120,602$
1 -Not technically feasible
2 -Only includes emissions from Tower 1, since Towers 3
and 4 already have LNB
3 -Includes emissions from Towers 1, 3, and 4
Table A-12. Ozone RACT Summary - Matrix Operations
Option 1 Cost/Benefit Analysis Summary
RACT option 1
RACT option 2
RACT option 4
RACT option 5
RACT option 5
Existing Allowable Emissions
RACT Option Analysis
RACT option 1
RACT option 2
Option 2 Cost/Benefit Analysis Summary
Option 3 Cost/Benefit Analysis Summary
Option 4 Cost/Benefit Analysis Summary
Emission Reduction (tons)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tons)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tons)
Cost Effectiveness ($/ton)
Annualized Cost ($)
Emission Reduction (tons)
Cost Effectiveness ($/ton)
Controlled Emissions Table (tpy):
RACT option 32
RACT option 43
RACT option 5
RACT option 6
Annualized Cost ($)
RACT option 3
Hexcel | West Valley City Plant Page 12 of 23 Trinity Consultants
Hexcel - Cost Analysis for Boilers
Table A-13. RACT Control Cost Evaluation for SCR Addition to Boiler - General Information
Parameter Value Notes
Heat Input 25.0 MMBTU/hr per unit
Current Emission Rate 1.20 TPY, per unit
Estimated Removal Efficiency 0.44 Assumes the estimated removal efficiency is based on a 9 ppm to 5 ppm reductions in emissions.
Estimated Emission Rate 0.67
Estimated Ammonia Usage 0.22 lb/hr, Calculated using EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs
equation 2.35
Cost of Ammonia Reagent 0.27 $/lb, quote from Thatcher ($1.38/gallon for 19% ammonia)
Cost of Catalyst 227.00
$/ft3, U.S. Environmental Protection Agency (EPA). Documentation for EPA’s Power Sector Modeling
Platform v6 Using the Integrated Planning Model. Office of Air and Radiation. May 2018. Available at:
https://www.epa.gov/airmarkets/documentation-epas-power-sector-modeling-platform-v6.
Operator ($/hour)$28.50
Utah Department of Workforce Services, Occupational Wages by Region, Median Annual Wage for
Installation/Maintenance/Repair, Machinery cited $59,300. Assumed a standard working year contains
2,080 hours.
Equipment Life Expectancy
(Years)25 EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs average life
expectancy for industrial boilers
Interest Rate (%)7.00%OMB Circular A-4, https://obamawhitehouse.archives.gov/omb/circulars_a004_a-4/
Process Information
Labor Costs
Economic Factors
Hexcel | West Valley City Plant Page 13 of 23 Trinity Consultants
Hexcel - Cost Analysis for Boilers
Table A-14. RACT Control Cost Evaluation for SCR Addition to Boiler - Capital Investment
Parameter Value Notes
Total Increase in Capital
Investment ($)$468,000 Cost estimate based on communication with CECO Environmental December 2023, several sizes and
costs were provided and a linear interpolation was applied.
Direct Installation Costs $140,400 U.S. EPA's Alternative Control Techniques Document -- NOx Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.1.2 Direct Installation Costs
Indirect Installation Costs $154,440 U.S. EPA's Alternative Control Techniques Document -- NOx Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.1.3 Indirect Installation Costs
Contingency $117,000 This cost was added as the total equipment cost was obtained anonymously and a minimum equipment
cost was provided.
Freight $23,400 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Sales Tax $14,040 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Instrumentation $46,800 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Capital Recovery Factor (CRF)0.0858 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Equation
2.8a
Capital Recovery Cost (CRC)$40,159 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Equation
2.8
Hexcel | West Valley City Plant Page 14 of 23 Trinity Consultants
Hexcel - Cost Analysis for Boilers
Table A-15. RACT Control Cost Evaluation for SCR Addition to Boiler - Annual Operating, Insurance, Tax, and Other Costs
Parameter Value Notes
Operating Labor $35,369
EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs estimates 4 hours per
day of Operating and Supervisory Labor. The estimate presented utilizes Section 1, Chapter 2's
assumption tat 15% of operating labor is supervisory labor
Supervisory Labor $6,242 Assumed to be 15% of operating Labor, EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation:
Concepts and Methodology, Section 2.6.5.2
Maintenance Labor and Materials $2,340 EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs estimates
maintenance costs to be 0.5 percent of the total capital investment.
Annual Reagent Costs $118 EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs equation 2.58,
assumed 2,000 hours of operation consistent with the reduced heat load
Annual Electricity Costs $0
EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs does not provide an
equation for industrial, natural gas fired units. Estimated to be negligible for units of this size fired on
natural gas.
Annual Catalyst Costs $6,810 Catalyst size calculated based on information provided in EPA's Air Pollution Control Technology Fact
Sheet for SCR (EPA-452/F-03-032). Assumed Catalyst life of 5 years.
Total Direct Operating Costs $50,878 Sum of Direct Operating Costs on an Annual Basis
Overhead $26,370 Assumed to be 60% of the total Direct Operating Costs, U.S. EPA Cost Control Manual Section 1,
Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.7
Property Tax $4,680 Assumed to be 1% of the Total Capital Investment, U.S. EPA Cost Control Manual Section 1, Chapter 2
Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Increase in Insurance $4,680 Assumed to be 1% of the Total Capital Investment, U.S. EPA Cost Control Manual Section 1, Chapter 2
Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Administrative Charges $1,089 EPA Cost Control Manual Section 4, Chapter 2, Equation 2.69.
Total Insurance, Tax, and Other
Annual Costs $36,819 Sum of Insurance, Tax, and Other Annual Costs
Table 16. RACT Control Cost Evaluation for SCR Addition to Boiler - Total Annual Cost & Cost per Ton Removed
Parameter Value Notes
Total Annual Cost $127,857 Sum of Capital Recovery Cost, Total Direct Operating Costs, Insurance, Tax and Other Annual Costs.
NOX Removed (tpy)0.53
Cost per Ton of NOX Removed
($/ton)$239,731
NOX Cost Per Ton Removed
Direct Operating Costs
Insurance, Tax, and Other Annual Costs
Hexcel | West Valley City Plant Page 15 of 23 Trinity Consultants
Hexcel - Cost Analysis for Diesel Engines
Table A-17. Control Cost Evaluation for SCR on an Emergency Use Diesel Engine - General Information
Parameter Value Notes
Duty (kW)1751 Mid-range generator size for units over 600hp
Duty (bhp)2348 Approximate conversation from kW to hp is 1.341 hp/kW
Tier II Emission NOx Rate
(g/kW-hr)6.4
U.S. EPA Office of Transportation and Air Quality (U.S. EPA-420-B-16-022) published March 2016,
Emission rate for NMHC+NOx was the published form, NMHC is anticipated to be a minor component of
the emission factor.
Tier II Emissions NOX (tpy)1.24 Total emission rate based on a maximum of 100 hr per year.
Tier IV Emission NOx Rate
(g/kW-hr)4.00
U.S. EPA Office of Transportation and Air Quality (U.S. EPA-420-B-16-022) published March 2016, Interim
Standard used as it is in the same form as the Tier II published standard, NMHC is anticipated to be a
minor component of the emission factor.
Tier IV Final Emissions NOX (tpy)0.77 Controlled emissions provided by Tier IV Final Nonroad Compression-Ignition Engines: Exhaust Emission
Standards for NOX.
Equipment Life Expectancy (Years)15 Exemption to replacement engine provisions codified in 40 CFR 60.4210(i)
Interest Rate (%)7.00%OMB Circular A-4, https://obamawhitehouse.archives.gov/omb/circulars_a004_a-4/
Table A-18. Control Cost Evaluation for SCR on an Emergency Use Diesel Engine - Capital Investment
Parameter Value Notes
Total Capital Investment ($)$159,500 Cost estimate based on estimates from several vendors, sizes, and costs were provided and a linear
interpolation was applied. Cost in 2023 dollars.
Capital Recovery Factor (CRF)0.1098 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Equation
2.8a
Capital Recovery Cost (CRC)$17,512 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Equation
2.8
Process Information
Economic Factors
Hexcel | West Valley City Plant Page 16 of 23 Trinity Consultants
Hexcel - Cost Analysis for Diesel Engines
Table A-19. Control Cost Evaluation for SCR on an Emergency Use Diesel Engine - Annual Operating Costs
Parameter Value Notes
Operating Labor, Maintenance,
Brake Specific Fuel Consumption,
and Catalyst Maintenance
$4
$/hp, U.S. EPA Alternative Control Techniques Document: Stationary Diesel Engines (U.S. EPA Contract
No. EP-D-07-019) Published March 5, 2010, Cost values are cited to be from 2005 and have been lowered
to match a run time of 100 hours.
Inflation Factor 1.69 Based on U.S. Bureau of Labor Statistics CPI Inflation Calculator from January of 2003 to October of
2023. https://www.bls.gov/data/inflation_calculator.htm
Total Direct Operating Costs $15,873
Table A-20. BACT Control Cost Evaluation for SCR on an Emergency Use Diesel Engine - Annual Operating, Insurance, Tax, and Other Costs
Parameter Value Notes
Total Annual Cost $33,386 Sum of Capital Recovery Cost, Total Direct Operating Costs, Insurance, Tax and Other Annual Costs.
NOX Removed (tpy)0.46
Cost per Ton of NOX Removed
($/ton)$72,070
Direct Operating Costs
NOX Cost Per Ton Removed
Hexcel | West Valley City Plant Page 17 of 23 Trinity Consultants
Hexcel - Cost Analysis for HVAC Units
Table A-21. RACT Control Cost Evaluation for SCR Addition to HVAC Unit - General Information
Parameter Value Notes
Heat Input 2.3 MMBTU/hr per unit, based on the largest HVAC unit
Current Emission Rate 1.00 TPY, per unit
Estimated Removal Efficiency 0.89 Assumes the estimated removal efficiency is based on a 80 ppm to 9 ppm reductions in
emissions.
Estimated Emission Rate 0.11
Estimated Ammonia Usage 0.04 lb/hr, Calculated using EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic
Reduction Costs equation 2.35
Cost of Ammonia Reagent 0.27 $/lb, quote from Thatcher ($1.38/gallon for 19% ammonia)
Cost of Catalyst 227.00
$/ft3, U.S. Environmental Protection Agency (EPA). Documentation for EPA’s Power Sector
Modeling Platform v6 Using the Integrated Planning Model. Office of Air and Radiation. May
2018. Available at: https://www.epa.gov/airmarkets/documentation-epas-power-sector-
modeling-platform-v6.
Operator ($/hour)$28.50
Utah Department of Workforce Services, Occupational Wages by Region, Median Annual Wage
for Installation/Maintenance/Repair, Machinery cited $59,300. Assumed a standard working
year contains 2,080 hours.
Equipment Life Expectancy (Year 25 EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs (Indirect
annual costs, page 79) average life expectancy for industrial process units
Interest Rate (%)7.00%U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology
Process Information
Labor Costs
Economic Factors
Hexcel | West Valley City Plant Page 18 of 23 Trinity Consultants
Hexcel - Cost Analysis for HVAC Units
Table A-22. RACT Control Cost Evaluation for SCR Addition to HVAC Unit - Capital Investment
Parameter Value Notes
Total Increase in Capital
Investment ($)418,312$ Cost estimate based on communication with CECO Environmental December 2023, several sizes
and costs were provided and a linear interpolation was applied.
Direct Installation Costs $125,494 U.S. EPA's Alternative Control Techniques Document -- NOx Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.1.2 Direct Installation Costs
Indirect Installation Costs $138,043 U.S. EPA's Alternative Control Techniques Document -- NOx Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.1.3 Indirect Installation Costs
Contingency $104,578 This cost was added as the total equipment cost was obtained anonymously and a minimum
equipment cost was provided.
Freight $20,916 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology, Table 2.4
Sales Tax $12,549 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology, Table 2.4
Instrumentation $41,831 U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and
Methodology, Table 2.4
Capital Recovery Factor (CRF)0.0858 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology,
Equation 2.8a
Capital Recovery Cost (CRC)$35,896 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology,
Equation 2.8
Hexcel | West Valley City Plant Page 19 of 23 Trinity Consultants
Hexcel - Cost Analysis for HVAC Units
Table A-23. RACT Control Cost Evaluation for SCR Addition to HVAC Unit - Annual Operating, Insurance, Tax, and Other Costs
Parameter Value Notes
Operating Labor $35,369
EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs estimates 4
hours per day of Operating and Supervisory Labor. The estimate presented utilizes Section 1,
Chapter 2's assumption tat 15% of operating labor is supervisory labor
Supervisory Labor $6,242 Assumed to be 15% of operating Labor, EPA Cost Control Manual Section 1, Chapter 2 Cost
Estimation: Concepts and Methodology, Section 2.6.5.2
Maintenance Labor and Materials $2,092 EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs estimates
maintenance costs to be 0.5 percent of the total capital investment.
Annual Reagent Costs $22 EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs equation 2.58,
assumed 2,000 hours of operation consistent with the reduced heat load
Annual Electricity Costs $0
EPA Cost Control Manual Section 4 Chapter 2 Selective Catalytic Reduction Costs does not
provide an equation for industrial, natural gas fired units. Estimated to be negligible for units of
this size fired on natural gas.
Annual Catalyst Costs $6,810 Catalyst size calculated based on information provided in EPA's Air Pollution Control Technology
Fact Sheet for SCR (EPA-452/F-03-032). Assumed Catalyst life of 5 years.
Total Direct Operating Costs $50,534 Sum of Direct Operating Costs on an Annual Basis
Overhead $26,221 Assumed to be 60% of the total Direct Operating Costs, U.S. EPA Cost Control Manual Section
1, Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.7
Property Tax $4,183 Assumed to be 1% of the Total Capital Investment, U.S. EPA Cost Control Manual Section 1,
Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Increase in Insurance $4,183 Assumed to be 1% of the Total Capital Investment, U.S. EPA Cost Control Manual Section 1,
Chapter 2 Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Administrative Charges $1,086 EPA Cost Control Manual Section 4, Chapter 2, Equation 2.69.
Total Insurance, Tax, and Other
Annual Costs $35,673 Sum of Insurance, Tax, and Other Annual Costs
Table A-24. RACT Control Cost Evaluation for SCR Addition to HVAC Unit - Total Annual Cost & Cost per Ton Removed
Parameter Value Notes
Total Annual Cost $122,103 Sum of Capital Recovery Cost, Total Direct Operating Costs, Insurance, Tax and Other Annual
Costs.
NOX Removed (tpy)0.89
Cost per Ton of NOX Removed
($/ton)$137,580
NOX Cost Per Ton Removed
Direct Operating Costs
Insurance, Tax, and Other Annual Costs
Hexcel | West Valley City Plant Page 20 of 23 Trinity Consultants
Hexcel - Cost Analysis for HVAC Units
Table A-25. RACT Control Cost Evaluation for HVAC LNB Replacement - General Information
Parameter Value Notes
Heat Input 2.3 MMBTU/hr per unit, based on the largest HVAC unit
Current Emission Rate 1.00 TPY, per unit, Using lb/MMBtu
Reduction Efficiency 75%Estimated using the EPA's Technical Bulletin, Nitrogen Oxides, Why and How They are Controlled
(EPA456/F-99-006R).
Estimated Emission Rate 0.25 TPY, per unit
Operator ($/hour)$28.50
Utah Department of Workforce Services, Occupational Wages by Region, Median Annual Wage for
Installation/Maintenance/Repair, Machinery cited $59,300. Assumed a standard working year
contains 2,080 hours.
Maintenance ($/hour)$28.50
Utah Department of Workforce Services, Occupational Wages by Region, Median Annual Wage for
Installation/Maintenance/Repair, Machinery cited $59,300. Assumed a standard working year
contains 2,080 hours.
Equipment Life Expectancy
(Years)10 Alternative Control Techniques Document -- NOX Emissions from Industrial/Commercial/Institutional
(ICI) Boilers, Section 6.1.3 Total Annualized Cost and Cost Effectiveness
Interest Rate (%)7.00%U.S. EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology
Process Information
Labor Costs
Economic Factors
Hexcel | West Valley City Plant Page 21 of 23 Trinity Consultants
Hexcel - Cost Analysis for HVAC Units
Table A-26. RACT Control Cost Evaluation for HVAC LNB Replacement - Capital Investment
Parameter Value Notes
Total Equipment Cost $66,000 Cost estimate based on communication with Holbrook Servco December 2023, several sizes and
costs were provided and a linear interpolation was applied.
Direct Installation Costs $68,400 Cost estimate based on communication with Holbrook Servco December 2023, several sizes and
costs were provided and a linear interpolation was applied.
Contingency $13,680
This cost was added as the total equipment cost was obtained anonymously and based on a linear
correlation between equipment sizes. 20% of the direct and indirect capital costs was
recommended by U.S. EPA's Alternative Control Techniques Document -- NOX Emissions from
Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.1.4 Contingencies.
Freight $3,300 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Sales Tax $1,980 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Instrumentation $6,600 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, Table
2.4
Total Increase in Capital
Investment ($)$159,960 Sum of total equipment, direct installation, indirect installation, contingency, freight, sales tax, and
instrumentation costs.
Capital Recovery Factor (CRF)0.1424 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology,
Equation 2.8a
Capital Recovery Cost (CRC)$22,775 EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology,
Equation 2.8
Hexcel | West Valley City Plant Page 22 of 23 Trinity Consultants
Hexcel - Cost Analysis for HVAC Units
Table A-27. RACT Control Cost Evaluation for HVAC LNB Replacement - Annual Operating, Insurance, Tax, and Other Costs
Parameter Value Notes
Operating Labor $15,604 Assumed 0.5 hours per 8-hour shift
Supervisory Labor $2,341 Assumed to be 15% of operating Labor, EPA Cost Control Manual Section 1, Chapter 2 Cost
Estimation: Concepts and Methodology, Section 2.6.5.2
Maintenance Labor $15,604 Assumed 0.5 hours per 8-hour shift
Maintenance Materials $15,604 Assumed the same as Maintenance Labor per EPA Cost Control Manual Section 1, Chapter 2 Cost
Estimation: Concepts and Methodology, Section 2.6.5.3
Total Direct Operating Costs $49,152 Sum of Direct Operating Costs on an Annual Basis
Overhead $29,491 Assumed to be 60% of the total Direct Operating Costs, EPA Cost Control Manual Section 1, Chapter
2 Cost Estimation: Concepts and Methodology, Section 2.6.5.7
Administrative Charges $1,320 Assumed to be 2% of the Total Capital Investment, EPA Cost Control Manual Section 1, Chapter 2
Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Property Tax $660 Assumed to be 1% of the Total Capital Investment, EPA Cost Control Manual Section 1, Chapter 2
Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Increase in Insurance $660 Assumed to be 1% of the Total Capital Investment, EPA Cost Control Manual Section 1, Chapter 2
Cost Estimation: Concepts and Methodology, Section 2.6.5.8
Total Insurance, Tax, and Other
Annual Costs $32,131 Sum of Insurance, Tax, and Other Annual Costs
Table A-28. RACT Control Cost Evaluation for HVAC LNB Replacement - Annual Operating, Insurance, Tax, and Other Costs
Parameter Value Notes
Total Annual Cost $104,058 Sum of Capital Recovery Cost, Total Direct Operating Costs, Insurance, Tax and Other Annual
Costs.
NOX Removed (tpy)0.75
Cost per Ton of NOX Removed
($/ton)$138,743
1. While this cost analysis sites the EPA Cost Control Manual Section 1, Chapter 2 Cost Estimation: Concepts and Methodology, the cost estimates used for a retrofit are
consistent in Alternative Control Techniques Document -- NOx Emissions from Industrial/Commercial/Institutional (ICI) Boilers, Section 6.1.2 Annual Operations and
Maintenance (O&M) Costs
Direct Operating Costs
Insurance, Tax, and Other Annual Costs1
NOX Cost Per Ton Removed
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Hexcel / Ozone RACT Analysis
Trinity Consultants B-1
APPENDIX B. SUPPORTING COST CALCULATIONS
LNB Annualized Cost Estimate for NOX Control
Table B-1. Vendor Estimated Low NOX Burner Costs Table B-2. Hexcel Burner Countb
Capacity Basic Equipment Costb Total Installed
Costa $/MMBtu Hexcel Line
No.
Equipment
<=750,000
BTU/hr
Equipment
> 0.75
MMBtu/hr
and <=2.7
MMBtu/hr
Equipment
> 2.7
MMBTU and
<=13
MMBtu/hr
750,000 BTU/hr $33,374 $87,270 $116,360 2 1 0 0
2.7 MMBtu/hr $40,552 $95,644 $35,424 5 0 9 0
13 MMBtu/hr $71,112 $132,596 $10,200 6 1 8 0
8 1 8 0
10 1 8 0
11 1 8 0
12 1 8 0
PILOT 1 0 0
Matrix 0 0 1
bFiber Lines 3, 4, and 7 will have ULNB installed by December 31, 2014
and Fiber Lines 13-16 are designed with both LNB and a DeNOx water
system, which provides the lowest emission rate available for all lines.
Therefore these Fiber Lines are not part of this assessment.
a Cost estimate based on communication with Holbrook Servco December 2023, several sizes and costs were provided and a linear
interpolation was applied.
Hexcel | West Valley City Plant Page 1 of 7 Trinity Consultants
LNB Annualized Cost Estimate for NOX Control
Table B-3. Annualized LNB Cost Per Hexcel Line
2 5 6 8 10 11 12
Direct Costs
Purchased equipment costs
Total Purchased Equipment Cost (Burners)PECd $2,187,301 $33,374 $364,969 $357,791 $357,791 $357,791 $357,791 $357,791 $33,374 $280,086
Installation Costs
Total Direct Installation Cost DICd $3,022,883 $53,896 $495,828 $494,632 $494,632 $494,632 $494,632 $494,632 $53,896 $292,241
Total Direct Costs (TDC)PEC + DIC $5,210,184 $87,270 $860,798 $852,423 $852,423 $852,423 $852,423 $852,423 $87,270 $572,326
Indirect Installation Costs
Engineering 0.10 PEC $218,730 $3,337 $36,497 $35,779 $35,779 $35,779 $35,779 $35,779 $3,337 $28,009
Construction & field expenses 0.10 PEC $218,730 $3,337 $36,497 $35,779 $35,779 $35,779 $35,779 $35,779 $3,337 $28,009
Contractor fees 0.10 PEC $218,730 $3,337 $36,497 $35,779 $35,779 $35,779 $35,779 $35,779 $3,337 $28,009
Start-up 0.01 PEC $21,873 $334 $3,650 $3,578 $3,578 $3,578 $3,578 $3,578 $334 $2,801
Performance test 0.01 PEC $21,873 $334 $3,650 $3,578 $3,578 $3,578 $3,578 $3,578 $334 $2,801
Contingencies 0.03 PEC $65,619 $1,001 $10,949 $10,734 $10,734 $10,734 $10,734 $10,734 $1,001 $8,403
Total Indirect Costs, IC 0.35 PEC $765,555 $11,681 $127,739 $125,227 $125,227 $125,227 $125,227 $125,227 $11,681 $98,030
TOTAL CAPITAL INVESTMENTe (DC + IC) * 1.4 (retrofit
factor)$8,366,035 $138,531 $1,383,952 $1,368,710 $1,368,710 $1,368,710 $1,368,710 $1,368,710 $138,531 $938,499
Annual Cost Summary
Total Direct Annual Cost
Operation/Maintenance Costf DAC $101,382 $1,843 $16,590 $16,590 $16,590 $16,590 $16,590 $16,590 $1,843 $1,843
Profit Loss
Revenue Lost per 24-hour down timeh $/24 hours NA $9,700 $28,690 $50,075 $55,900 $114,465 $114,465 $114,465 NA NA
Days Required for Retrofith days lost 21 21 21 21 21 21 21
Total Profit Lost PL = $/hr*hours lost NA $203,700 $602,490 $1,051,575 $1,173,900 $2,403,765 $2,403,765 $2,403,765 NA NA
Indirect Annual Costs
Labor Ratiog 0.9136 0.4060 0.4916 0.0928 0.0928 0.1163 0.1163 0.1163 0.1163
Overhead 60% of sum of operating
and maintenance labor $14,107 $1,010 $4,041 $4,893 $924 $924 $1,157 $1,157 $129 $129
Administrative charges 2% of TCI $167,321 $2,771 $27,679 $27,374 $27,374 $27,374 $27,374 $27,374 $2,771 $18,770
Property tax 1% of TCI $83,660 $1,385 $13,840 $13,687 $13,687 $13,687 $13,687 $13,687 $1,385 $9,385
Insurance 1% of TCI $83,660 $1,385 $13,840 $13,687 $13,687 $13,687 $13,687 $13,687 $1,385 $9,385
Capital recovery factor 15 Years, 7% Interest 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11
Capital Recoveryi CRF*TCI $920,264 $15,238 $152,235 $150,558 $150,558 $150,558 $150,558 $150,558 $15,238 $103,235
Total Indirect Annual Costs Total $1,269,012 $21,790 $211,634 $210,200 $206,230 $206,230 $206,464 $206,464 $20,908 $140,903
TOTAL ANNUAL COST $11,613,354 $227,333 $830,714 $1,278,364 $1,396,720 $2,626,585 $2,626,819 $2,626,819 $22,752 $142,747
Maximum estimated 1993 Capital Cost ($/MMBtu)$8,300
Maximum estimated 1993 Operational Cost ($/MMBtu)$1,500
Estimated 2011 Operational Cost ($/MMBtu)$1,843 = $11,538/$8,300 * $2,085 (mid-range (for 13 MMBtu/hr burner) estimated 2011 $/MMBtu was used for the calculation)
g Ratio of operation and Maintenance labor costs to total operation and maintenance costs from scrubber operations
h Lost Revenue and days required for retrofit estimated by Hexcel 12/19/11.
i Office of Air Quality Planning and Standards (OAQPS), EPA Air Pollution Control Cost Manual, Sixth Edition, Sec 6, Chpt 2, Table 2.9, EPA 452-B-02-001 (http://www.epa.gov/ttn/catc/products.html#cccinfo), Mussatti and Hemmer, July 2002.
f. EPA Technical Bulletin, Nitrogen Oxides (NOx) Why and How They Are Controlled, EPA/456/F-99-006R (http://epa.gov/ttn/catc/dir1/fnoxdoc.pdf), November 1999. Operational costs obtained from Table 14 - Costs of NOx Controls,
multiplied by a ratio of 2011 capital costs to 1993 capital costs, to estimate 2011 operational costs.
d. Email correspondence between Chris Paul (Western Combustion Engineering) and John Falcetti (Trinity) on November 28, 2011.
e Retrofit factors are not mentioned for Low NOX burners in the OAQPS Manual. Thus, the retrofit factor for a venturi scrubber is applied. Retrofit factor based on average of 1.3 - 1.5, provided in OAQPS Manual, Section 6, Chapter 2, Page 2-49.
c Unless otherwise noted, equations are taken from U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. EPA/452/B-02-001, January 2002.
PILOT MatrixHexcel Line No.Parameter Equationc Total Value
Hexcel | West Valley City Plant Page 2 of 7 Trinity Consultants
ULNB Annualized Cost Estimate for NOX Control
Table B-4. Vendor Estimated ULNB Costs Table B-5. Hexcel Burner Countb
Capacity Basic Equipment Costb Total Installed
Costa $/MMBtu Hexcel Line
No.
Equipment
<=750,000
BTU/hr
Equipment
> 0.75
MMBtu/hr
and <=2.7
MMBtu/hr
Equipment
> 2.7
MMBTU and
<=13
MMBtu/hr
750,000 BTU/hr $33,374 $87,270 $116,360 2 1 0 0
2.7 MMBtu/hr $40,552 $95,644 $35,424 5 0 9 0
13 MMBtu/hr $71,112 $132,596 $10,200 6 1 8 0
8 1 8 0
10 1 8 0
11 1 8 0
12 1 8 0
PILOT 1 0 0
Matrix 2 0 3
b Fiber Lines 3, 4, and 7 will have ULNB installed by December 31, 2014
and Fiber Lines 13-16 are designed with both LNB and a DeNOx water
system, which provides the lowest emission rate available for all lines.
Therefore these Fiber Lines are not part of this assessment.
a Cost estimate based on communication with Holbrook Servco December 2023, several sizes and costs were provided and a linear
interpolation was applied.
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ULNB Annualized Cost Estimate for NOX Control
Table B-6. Annualized ULNB Cost Per Hexcel Line
2 5 6 8 10 11 12
Direct Costs
Purchased equipment costs
Total Purchased Equipment Cost (Burners)PECd $2,187,301 $33,374 $364,969 $357,791 $357,791 $357,791 $357,791 $357,791 $33,374 $280,086
Installation Costs
Total Direct Installation Cost DICd $3,022,883 $53,896 $495,828 $494,632 $494,632 $494,632 $494,632 $494,632 $53,896 $292,241
Total Direct Costs (TDC)PEC + DIC $5,210,184 $87,270 $860,798 $852,423 $852,423 $852,423 $852,423 $852,423 $87,270 $572,326
Indirect Installation Costs
Engineering 0.10 PEC $218,730 $3,337 $36,497 $35,779 $35,779 $35,779 $35,779 $35,779 $3,337 $28,009
Construction & field expenses 0.10 PEC $218,730 $3,337 $36,497 $35,779 $35,779 $35,779 $35,779 $35,779 $3,337 $28,009
Contractor fees 0.10 PEC $218,730 $3,337 $36,497 $35,779 $35,779 $35,779 $35,779 $35,779 $3,337 $28,009
Start-up 0.01 PEC $21,873 $334 $3,650 $3,578 $3,578 $3,578 $3,578 $3,578 $334 $2,801
Performance test 0.01 PEC $21,873 $334 $3,650 $3,578 $3,578 $3,578 $3,578 $3,578 $334 $2,801
Contingencies 0.03 PEC $65,619 $1,001 $10,949 $10,734 $10,734 $10,734 $10,734 $10,734 $1,001 $8,403
Total Indirect Costs, IC 0.35 PEC $765,555 $11,681 $127,739 $125,227 $125,227 $125,227 $125,227 $125,227 $11,681 $98,030
TOTAL CAPITAL INVESTMENTe (DC + IC) * 1.4 (retrofit
factor)$8,366,035 $138,531 $1,383,952 $1,368,710 $1,368,710 $1,368,710 $1,368,710 $1,368,710 $138,531 $938,499
Annual Cost Summary
Total Direct Annual Cost
Operation/Maintenance Costf DAC $101,382 $1,843 $16,590 $16,590 $16,590 $16,590 $16,590 $16,590 $1,843 $9,217
Profit Loss
Revenue Lost per 24-hour down timeh $/24 hours NA $9,700 $28,690 $50,075 $55,900 $114,465 $114,465 $114,465 NA NA
Days Required for Retrofith days lost 21 21 21 21 21 21 21
Total Profit Lost PL = $/hr*hours lost NA $203,700 $602,490 $1,051,575 $1,173,900 $2,403,765 $2,403,765 $2,403,765 NA NA
Indirect Annual Costs
Labor Ratiog 0.9136 0.4060 0.4916 0.0928 0.0928 0.1163 0.1163 0.1163 0.1163
Overhead 60% of sum of operating
and maintenance labor $14,107 $1,010 $4,041 $4,893 $924 $924 $1,157 $1,157 $129 $643
Administrative charges 2% of TCI $167,321 $2,771 $27,679 $27,374 $27,374 $27,374 $27,374 $27,374 $2,771 $18,770
Property tax 1% of TCI $83,660 $1,385 $13,840 $13,687 $13,687 $13,687 $13,687 $13,687 $1,385 $9,385
Insurance 1% of TCI $83,660 $1,385 $13,840 $13,687 $13,687 $13,687 $13,687 $13,687 $1,385 $9,385
Capital recovery factor 15 Years, 7% Interest 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11
Capital Recoveryi CRF*TCI $920,264 $15,238 $152,235 $150,558 $150,558 $150,558 $150,558 $150,558 $15,238 $103,235
Total Indirect Annual Costs Total $1,269,012 $21,790 $211,634 $210,200 $206,230 $206,230 $206,464 $206,464 $20,908 $141,418
TOTAL ANNUAL COST $11,613,354 $227,333 $830,714 $1,278,364 $1,396,720 $2,626,585 $2,626,819 $2,626,819 $22,752 $150,634
Maximum estimated 1993 Capital Cost ($/MMBtu)$8,300
Maximum estimated 1993 Operational Cost ($/MMBtu)$1,500
Estimated 2011 Operational Cost ($/MMBtu)$1,843 = $11,538/$8,300 * $2,085 (mid-range (for 13 MMBtu/hr burner) estimated 2011 $/MMBtu was used for the calculation)
g Ratio of operation and Maintenance labor costs to total operation and maintenance costs from scrubber operations
h Lost Revenue and days required for retrofit estimated by Hexcel 12/19/11.
i Office of Air Quality Planning and Standards (OAQPS), EPA Air Pollution Control Cost Manual, Sixth Edition, Sec 6, Chpt 2, Table 2.9, EPA 452-B-02-001 (http://www.epa.gov/ttn/catc/products.html#cccinfo), Mussatti and Hemmer, July 2002.
f. EPA Technical Bulletin, Nitrogen Oxides (NOx) Why and How They Are Controlled, EPA/456/F-99-006R (http://epa.gov/ttn/catc/dir1/fnoxdoc.pdf), November 1999. Operational costs obtained from Table 14 - Costs of NOx Controls, multiplied by a
ratio of 2011 capital costs to 1993 capital costs, to estimate 2011 operational costs.
c Unless otherwise noted, equations are taken from U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. EPA/452/B-02-001, January 2002.
d. Email correspondence between Chris Paul (Western Combustion Engineering) and John Falcetti (Trinity) on November 28, 2011.
e Retrofit factors are not mentioned for Low NOX burners in the OAQPS Manual. Thus, the retrofit factor for a venturi scrubber is applied. Retrofit factor based on average of 1.3 - 1.5, provided in OAQPS Manual, Section 6, Chapter 2, Page 2-49.
PILOT MatrixHexcel Line No.Parameter Equationc Total Value
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Regenerative Thermal Oxidizer (RTO) Annualized Cost Estimate
Table B-7. Vendor Estimated Regenerative Thermal Oxidizer Cost Table B-8. Hexcel Exhaust Flow Rate
Flow Rate (scfm)Basic Equipment Costa Hexcel Line
No.
Averageb
Flow Rate
(scfm)
Averageb
Flow Rate
(acfm)
VOC
Emission
Rate (lb/hr)
50,000 $1,191,950 2 254 750 0.01
40,000 $1,018,025 3 16,321 23,000 0.91
30,000 $944,100 4 18,866 21,200 0.80
20,000 $709,013 5 23,980 35,350 0.67
10,000 $580,000 6 19,790 28,100 0.91
7 30,557 9,900 1.82
8 53,724 85,800 7.18
10 53,724 85,800 7.18
11 47,678 72,750 8.83
12 47,678 72,750 8.83
PILOT 6,776 8,150 0.05
Matrix 2,589 10,000 0.07
b The average flow rate shown is the sum of flow rates per Hexcel line for point
sources with non-negligible VOC emission rates. Point sources with negligible
VOC emission rates were considered not technically feasible to control with an
RTO.
a The installed cost of an RTO is based on a cost estimate from Catalytic Products in December
2023.
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Regenerative Thermal Oxidizer (RTO) Annualized Cost Estimate
Table B-9. Annualized Regenerative Thermal Oxidizer Cost Per Hexcel Line
2 3 4 5 6 7 8 10 11 12
Direct Costs
Purchased equipment costs
Basic Equipment, RTO, BE Interpolated from Table 1 $432,634 $678,933 $717,936 $796,341 $732,109 $897,150 $1,252,279 $1,252,279 $1,159,611 $1,159,611 $532,614 $468,437
Ductworkd $300/linear ft x 450 ft, vendor estimate
for 25,000 acfm not estimated not estimated not estimated not estimated not estimated not estimated $135,000 $135,000 $135,000 $135,000 $135,000 $135,000
Instrumentation 0.10 BE $43,263 $67,893 $71,794 $79,634 $73,211 $89,715 $125,228 $125,228 $115,961 $115,961 $53,261 $46,844
Sales taxes 0.03 BE $12,979 $20,368 $21,538 $23,890 $21,963 $26,914 $37,568 $37,568 $34,788 $34,788 $15,978 $14,053
Freight 0.05 BE $21,632 $33,947 $35,897 $39,817 $36,605 $44,857 $62,614 $62,614 $57,981 $57,981 $26,631 $23,422
Purchased Equipment Cost, PEC PEC = 1.18 BE $510,508 $801,141 $847,165 $939,683 $863,889 $1,058,637 $1,612,689 $1,612,689 $1,503,341 $1,503,341 $763,484 $687,755
b
Direct Installation Costs, DIC 0.3 PEC $153,152.30 $240,342.30 $254,149.42 $281,904.85 $259,166.60 $317,591.05 $483,806.84 $483,806.84 $451,002.25 $451,002.25 $229,045.28 $206,326.65
Total Direct Costs, DC PEC + DIC $663,659.99 $1,041,483.31 $1,101,314.16 $1,221,587.70 $1,123,055.28 $1,376,227.89 $2,096,496.31 $2,096,496.31 $1,954,343.08 $1,954,343.08 $992,529.56 $894,082.13
Indirect Installation Costs
Engineering 0.10 PEC $51,051 $80,114 $84,716 $93,968 $86,389 $105,864 $161,269 $161,269 $150,334 $150,334 $76,348 $68,776
Construction & field expenses 0.05 PEC $25,525 $40,057 $42,358 $46,984 $43,194 $52,932 $80,634 $80,634 $75,167 $75,167 $38,174 $34,388
Contractor fees 0.10 PEC $51,051 $80,114 $84,716 $93,968 $86,389 $105,864 $161,269 $161,269 $150,334 $150,334 $76,348 $68,776
Start-up 0.02 PEC $10,210 $16,023 $16,943 $18,794 $17,278 $21,173 $32,254 $32,254 $30,067 $30,067 $15,270 $13,755
Performance test 0.01 PEC $5,105 $8,011 $8,472 $9,397 $8,639 $10,586 $16,127 $16,127 $15,033 $15,033 $7,635 $6,878
Contingencies 0.03 PEC $15,315 $24,034 $25,415 $28,190 $25,917 $31,759 $48,381 $48,381 $45,100 $45,100 $22,905 $20,633
Total Indirect Costs, IC 0.31 PEC $158,257 $248,354 $262,621 $291,302 $267,805 $328,177 $499,934 $499,934 $466,036 $466,036 $236,680 $213,204
TOTAL CAPITAL INVESTMENTe (DC + IC) * 1.25 retrofit factor $1,027,397 $1,612,296 $1,704,919 $1,891,112 $1,738,576 $2,130,507 $3,245,538 $3,245,538 $3,025,473 $3,025,473 $1,536,512 $1,384,108
Direct Annual Costs
Operating Labor
Operator 2hr/shift* 3 shift/day*360 days/yr *
$23.50/hr $50,760 $50,760 $50,760 $50,760 $50,760 $50,760 $50,760 $50,760 $50,760 $50,760 $50,760 $50,760
Supervisor 15% of operator $7,614 $7,614 $7,614 $7,614 $7,614 $7,614 $7,614 $7,614 $7,614 $7,614 $7,614 $7,614
Maintenance
Labor 1hr/shift* 3 shift/day*360 days/yr *
$29.00/hr $31,320 $31,320 $31,320 $31,320 $31,320 $31,320 $31,320 $31,320 $31,320 $31,320 $31,320 $31,320
Operating Materials
Natural Gasf RTO Natural Gas Consumption
Calculations $1,598 $279,736 $310,314 $347,386 $261,756 $380,638 $824,781 $824,781 $738,193 $738,193 $121,631 $121,631
Electricity
Fan Assume no combustion air needed NA NA NA NA NA NA NA NA NA NA NA NA
Total Direct Annual Cost Total $91,292 $369,430 $400,008 $437,080 $351,450 $470,332 $914,475 $914,475 $827,887 $827,887 $211,325 $211,325
Indirect Annual Costs
Overhead 60% of sum of operating and
maintenance labor $53,816 $53,816 $53,816 $53,816 $53,816 $53,816 $53,816 $53,816 $53,816 $53,816 $53,816 $53,816
Administrative charges 2% of TCI $20,548 $32,246 $34,098 $37,822 $34,772 $42,610 $64,911 $64,911 $60,509 $60,509 $30,730 $27,682
Property tax 1% of TCI $10,274 $16,123 $17,049 $18,911 $17,386 $21,305 $32,455 $32,455 $30,255 $30,255 $15,365 $13,841
Insurance 1% of TCI $10,274 $16,123 $17,049 $18,911 $17,386 $21,305 $32,455 $32,455 $30,255 $30,255 $15,365 $13,841
Capital recovery factor 15 Years, 7% Interest 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11 0.11
Capital Recoveryf CRF*TCI $113,014 $177,353 $187,541 $208,022 $191,243 $234,356 $357,009 $357,009 $332,802 $332,802 $169,016 $152,252
Total Indirect Annual Costs Total $207,926 $295,661 $309,554 $337,483 $314,603 $373,393 $540,647 $540,647 $507,638 $507,638 $284,293 $261,433
TOTAL ANNUAL COST $299,218 $665,091 $709,563 $774,563 $666,053 $843,724 $1,455,122 $1,455,122 $1,335,525 $1,335,525 $495,619 $472,758
f Office of Air Quality Planning and Standards (OAQPS), EPA Air Pollution Control Cost Manual, Sixth Edition, Sec 6, Chpt 2, Table 2.9, EPA 452-B-02-001 (http://www.epa.gov/ttn/catc/products.html#cccinfo), Mussatti and Hemmer, July 2002.
e Retrofit factors are not mentioned for RTOs in the OAQPS Manual. Thus, the retrofit factor for a venturi scrubber is applied. Retrofit factor based on average of 1.3 - 1.5, provided in OAQPS Manual, Section 6, Chapter 2, Page 2-49.
c Unless otherwise noted, equations were taken from U.S. Environmental Protection Agency, EPA Air Pollution Control Cost manual, Sixth Edition. EPA/452/B-02-001, January 2002.
d The ductwork cost including supports was e-mailed from Southern Environmental, Inc. to L. Mintzer (Trinity) on 11/7/11 for a 25,000 acfm collector. The ductwork cost estimate of$300/linear foot x 450 feet = $135,000 was conservatively added to the basic equipment cost only for flows greater
than 20,000 scfm.
PILOT MatrixEquationcParameterHexcel Line No.
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RTO Natural Gas Consumption and Emission Reductions
Table B-10. Natural Gas Usage Parameters
2 3 4 5 6 7 8 10 11 12
Waste Gas, Qwi, scfm 254 16,321 18,866 23,980 19,790 30,557 53,724 53,724 47,678 47,678 6,776 2,589
VOC (as propane) Emission
Concentration a, volume fraction 6.89E-06 8.16E-06 6.21E-06 4.06E-06 6.72E-06 8.67E-06 1.95E-05 1.95E-05 2.70E-05 2.70E-05 9.90E-07 4.21E-06
VOC Concentration in Waste Gas,
ppm VOC 6.9 8.2 6.2 4.1 6.7 8.7 19.5 19.5 27.0 27.0 1.0 4.2
This line shows negligible
contribution of VOC to
heating value
CO Emission Concentration,
volume fraction
CO Emission Concentration, ppm
Process Gas Exhaust Temperature,
F 1100 239 294 450 550 611 381 381 371 371 175 700
Auxiliary Fuel Requirement, Qaf,
scf/yr 157,299 27,533,092 30,542,739 34,191,526 25,763,393 37,464,336 81,179,248 81,179,248 72,656,796 72,656,796 11,971,604 2,889,369 Assumed negligible heat
contribution from VOC
Fuel Costc, $/yr $1,598 $279,736 $310,314 $347,386 $261,756 $380,638 $824,781 $824,781 $738,193 $738,193 $121,631 $29,356
VOC Process Emissions, tpy 0.05 4.01 3.53 2.93 4.00 7.96 31.47 31.47 38.67 38.67 0.20 0.33
VOC Emissions from Auxiliary Fuel
Combustion, tpy 0.00 0.08 0.08 0.09 0.07 0.10 0.22 0.22 0.20 0.20 0.03 0.01 AP-42 Table 1.4-2
VOC Emissions Reduction d, tpy 0.05 3.85 3.37 2.78 3.85 7.70 30.61 30.61 37.70 37.70 0.16 0.31
Calculated as heater
emissions minus
emissions from auxiliary
fuel combustion.
b
c It is assumed that oxygen in the exhaust is sufficient for combusting VOC, and an additional air blower, and subsequent electricity cost is not required.
d Emission reduction = Process Emissions x 98% destruction efficiency - VOC emissions from Auxiliary Fuel Combustion. 98% destruction efficiency is provided on page 2-7 of OAQPS Section 3.2 for an incinerator operating at 1600 deg F.
e According to vendor's information, RTO provides 90% CO destruction efficiency or 10 ppmv CO outlet concentration, whichever is less stringent (per McGill AirClean 04/29/05). This calculation is based on 90% control efficiency.
Comments
a
Hexcel Line No.Parameter PILOT Matrix
Hexcel | West Valley City Plant Page 7 of 7 Trinity Consultants
Hexcel / Ozone RACT Analysis
Trinity Consultants C-1
APPENDIX C. RBLC DATA
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
LA-0377 TOKAI ADDIS FACILITY LA 05/27/2020 ACT 1-19 Burner 1 12 MW Low NOx Burners and good combustion practices.0.08 LB/MMBTU NA BACT-PSD
AR-0140 BIG RIVER STEEL LLC AR
09/18/2013 ACT BOILERS SN-26 AND 27, GALVANIZING LINE 24.5
MMBTU/H
LOW NOX BURNERS
COMBUSTION OF CLEAN FUEL
GOOD COMBUSTION PRACTICES
0.035 LB/MMBTU NA BACT-PSD
MI-0425 GRAYLING PARTICLEBOARD MI 05/09/2017 ACT EUFLTOS1 in FGTOH 10.2 MMBTU/H Good design and combustion practices, low NOx burners.0.05 LB/MMBTU TEST PROTOCOL SHALL SPECIFY BACT-PSD
MI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH
STREET MI 12/05/2016 ACT EUFUELHTR (Fuel pre-heater)3.7 MMBTU/H Good combustion practices.0.55 LB/H TEST PROTOCOL WILL SPECIFY AVG TIME.BACT-PSD
MI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 07/16/2018 ACT EUFUELHTR2: Natural gas fired fuel heater 3.8 MMBTU/H Low NOx burner 0.14 LB/H HOURLY BACT-PSD
MI-0420 DTE GAS COMPANY--MILFORD COMPRESSOR
STATION MI 06/03/2016 ACT FGAUXBOILERS 6 MMBTU/H Ultra low NOx burners and good combustion practices.14 PPMVOL AT 15%O2; TEST PROTOCOL BACT-PSD
MI-0426 DTE GAS COMPANY - MILFORD COMPRESSOR
STATION MI
03/24/2017 ACT
FGAUXBOILERS (6 auxiliary boilers
EUAUXBOIL2A, EUAUXBOIL3A,
EUAUXBOIL2B, EUAUXBOIL3B,
EUAUXBOIL2C, EUAUXBOIL3C)3
MMBTU/H Ultra-low NOx burners and good combustion practices.20 PPM AT 3% O EACH 3 MMBTU/H BOILER BACT-PSD
MI-0440 MICHIGAN STATE UNIVERSITY MI 05/22/2019 ACT FGFUELHEATERS 25 MMBTU/H Low NOx burners and good combustion practices.0.05 LB/MMBTU HOURLY; EACH HEATER BACT-PSD
MI-0442 THOMAS TOWNSHIP ENERGY, LLC MI 08/21/2019 ACT FGPREHEAT 7 MMBTU/H Good combustion practices and low NOx burners 0.036 LB/MMBTU HOURLY; EACH UNIT BACT-PSD
MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH
STREET MI 12/04/2013 ACT Fuel pre-heater (EUFUELHTR)3.7 MMBTU/H Good combustion practices.0.55 LB/H TEST PROTOCOL BACT-PSD
AR-0140 BIG RIVER STEEL LLC AR
09/18/2013 ACT
FURNACES SN-40 AND SN-42,
DECARBURIZING LINE 22
MMBTU/H
LOW NOX BURNERS
SCR
COMBUSTION OF CLEAN FUEL
GOOD COMBUSTION PRACTICES
0.1 LB/MMBTU NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY
04/19/2021 ACT
Galvanizing Line #2 Alkali Cleaning Section
Heater (EP 21-07B)23
MMBtu/hr
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan. This unit is also required to
be equipped with low-NOx burners (0.07 lb/MMBtu).
50 LB/MMSCF NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY
04/19/2021 ACT
Galvanizing Line #2 Annealing Furnaces (15)
(EP 21-15)4.8
MMBtu/hr,
each
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan. This unit is equipped with
low-NOx burners.
50 LB/MMSCF NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY
04/19/2021 ACT
Galvanizing Line #2 Zinc Pot Preheater (EP
21-09)3
MMBtu/hr
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan. This unit is equipped with a
low-NOx burner.
70 LB/MMSCF NA BACT-PSD
TX-0680 SONORA GAS PLANT TX 06/14/2013 ACT Heater 10 MMBTU/H low-NOx burners 0.01 LB/MMBTU NA BACT-PSD
TX-0656 GAS TO GASOLINE PLANT TX 05/16/2014 ACT heaters (5)24.3 MMBTU/H ultra low NOx burners 0.036 LB/MMBTU NA BACT-PSD
OK-0153 ROSE VALLEY PLANT OK 03/01/2013 ACT HOT OIL HEATER 17.4 MMBTUH LOW-NOx BURNERS.0.045 LB/MMBTU 3-HR BACT-PSD
WI-0291 GRAYMONT WESTERN LIME-EDEN WI 01/28/2019 ACT P05 Natural Gas Fired Line Heater 1.5 mmBTU/hr Good Combustion Practices 0.1 LB/MMBTU NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY
04/19/2021 ACT
Pickle Line #2 – Boiler #1 & #2 (EP 21-
04 & EP 21-05)18
MMBtu/hr,
each
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan. Equipped with low-NOx
burners.
50 LB/MMSCF EACH BACT-PSD
OK-0156 NORTHSTAR AGRI IND ENID OK 07/31/2013 ACT Refinery Boiler 5 MMBTUH Good Combustion 0.0075 LB/MMBTU 3-HOUR AVG N/A
OK-0153 ROSE VALLEY PLANT OK 03/01/2013 ACT REGENERATION HEATERS 5.61 MMBTUH LOW-NOx BURNERS 0.045 LB/MMBTU 3-HR BACT-PSD
AR-0171 NUCOR STEEL ARKANSAS AR 02/14/2019 ACT SN-233 Galvanizing Line Boilers 15
MMBTU/hr
each Low Nox Burners 0.1 LB/MMBTU 3-HR BACT-PSD
MI-0448 GRAYLING PARTICLEBOARD MI 12/18/2020 ACT
Thermal oil system for thermally fused
lamination lines (EUFLTOS1 in FGTOH)10.2 MMBTU/H Good design and combustion practices, low NOx burners 0.05 LB/MMBTU HOURLY BACT-PSD
FL-0356 OKEECHOBEE CLEAN ENERGY CENTER FL 03/09/2016 ACT Two natural gas heaters 10 MMBtu/hr Must have NOx emission design value less than 0.1 lb/MMBtu 0.1 LB/MMBTU NA BACT-PSD
FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 ACT Two natural gas heaters 9.9 MMBtu/hr Manufacturer certification 0.1 LB/MMBTU DESIGN VALUE BACT-PSD
Throughput Emission Limit
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
WI-0291 GRAYMONT WESTERN LIME-EDEN WI 01/28/2019 ACT P05 Natural Gas Fired Line Heater 1.5 mmBTU/hr Good Combustion Practices 0.1 LB/MMBTU NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY
04/19/2021 ACT
Galvanizing Line #2 Zinc Pot Preheater (EP
21-09)3
MMBtu/hr
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan. This unit is equipped with a
low-NOx burner.
70 LB/MMSCF NA BACT-PSD
OK-0156 NORTHSTAR AGRI IND ENID OK 07/31/2013 ACT Refinery Boiler 5 MMBTUH Good Combustion 0.0075 LB/MMBTU 3-HOUR AVG N/A
MI-0442 THOMAS TOWNSHIP ENERGY, LLC MI 08/21/2019 ACT FGPREHEAT 7 MMBTU/H Good combustion practices and low NOx burners 0.036 LB/MMBTU HOURLY; EACH UNIT BACT-PSD
FL-0363 DANIA BEACH ENERGY CENTER FL 12/04/2017 ACT Two natural gas heaters 9.9 MMBtu/hr Manufacturer certification 0.1 LB/MMBTU DESIGN VALUE BACT-PSD
TX-0680 SONORA GAS PLANT TX 06/14/2013 ACT Heater 10 MMBTU/H low-NOx burners 0.01 LB/MMBTU NA BACT-PSD
LA-0377 TOKAI ADDIS FACILITY LA 05/27/2020 ACT 1-19 Burner 1 12 MW Low NOx Burners and good combustion practices.0.08 LB/MMBTU NA BACT-PSD
WI-0306 WPL- RIVERSIDE ENERGY CENTER WI
02/28/2020 ACT Temporary Boiler (B98A)14.67
MMBTU/H
Low NOx burners, flue gas recirculation, shall be operated for
no more than 500 hours, and shall combust only pipeline
quality natural gas.
0.04 LB/MMBTU AVG. OVER ANY CONSECUTIVE 3-HR PERIOD BACT-PSD
AR-0171 NUCOR STEEL ARKANSAS AR 02/14/2019 ACT SN-233 Galvanizing Line Boilers 15
MMBTU/hr
each Low Nox Burners 0.1 LB/MMBTU 3-HR BACT-PSD
KY-0110 NUCOR STEEL BRANDENBURG KY
07/23/2020 ACT
EP 03-05 - Steckel Mill Coiling Furnaces #1
& #2 17.5
MMBtu/hr,
each
Low-Nox Burner (Designed to maintain 0.08 lb/MMBtu); and a
Good Combustion and Operating Practices (GCOP) Plan.81.6 LB/MMSCF NA BACT-PSD
MI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 07/16/2018 ACT EUFUELHTR1: Natural gas fired fuel heater 20.8 MMBTU/H Low NOx burner 0.75 LB/H HOURLY BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY
04/19/2021 ACT
Galvanizing Line #2 Alkali Cleaning Section
Heater (EP 21-07B)23
MMBtu/hr
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan. This unit is also required to
be equipped with low-NOx burners (0.07 lb/MMBtu).
50 LB/MMSCF NA BACT-PSD
TX-0656 GAS TO GASOLINE PLANT TX 05/16/2014 ACT heaters (5)24.3 MMBTU/H ultra low NOx burners 0.036 LB/MMBTU NA BACT-PSD
MI-0440 MICHIGAN STATE UNIVERSITY MI 05/22/2019 ACT FGFUELHEATERS 25 MMBTU/H Low NOx burners and good combustion practices.0.05 LB/MMBTU HOURLY; EACH HEATER BACT-PSD
-SJVAPCD CA 11/30/2022 Boiler ≥20 MMBtu/hr Assumed SCR 0.003 LB/MMBTU NA BACT
-BAAQMD CA 8/4/2010 Boiler < 33.5 MMBtu/Hr Ultra Low NOx Burners & FGR NA BACT
-SCAQMD CA 9/2/2022 Boiler 8.4 MMBtu/hr Low NOx Burner 7 PPMV 15 min BACT
Throughput Emission Limit
NA
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
SC-0179 CAROLINA PARTICLEBOARD SC 03/18/2015 ACT THERMAL OIL HEATER #2 1.83 MMBTU/H NATURAL GAS USAGE AND GOOD COMBUSTION PRACTICES.0.01 LB/H NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY 04/19/2021 ACT
Galvanizing Line #2 Zinc Pot Preheater (EP
21-09)3 MMBtu/hr The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan 5.5 LB/MMSCF NA BACT-PSD
OK-0156 NORTHSTAR AGRI IND ENID OK 07/31/2013 ACT Refinery Boiler 5 MMBTUH Good Combustion 0.0054 LB/MMBTU 3-HOUR AVG N/A
MI-0442 THOMAS TOWNSHIP ENERGY, LLC MI 08/21/2019 ACT FGPREHEAT 7 MMBTU/H Good combustion practices 0.025 LB/MMBTU HOURLY; EACH UNIT BACT-PSD
*LA-0315 G2G PLANT LA 05/23/2014 ACT Reactor Charge Heater - 53B001 10.1 MMBTU/HR Combustion controls (proper burner design and operation
using natural gas)0.05 LB/H HOURLY MAXIMUM BACT-PSD
TX-0772 PORT OF BEAUMONT PETROLEUM TRANSLOAD
TERMINAL (PBPTT)TX 11/06/2015 ACT
Commercial/Institutional-Size
Boilers/Furnaces 13.2 MMBTU/H Good combustion practice to ensure complete combustion.0.3 T/YR NA BACT-PSD
SC-0193 MERCEDES BENZ VANS, LLC SC 04/15/2016 ACT Energy Center Boilers 14.27 MMBTU/hr Annual tune ups per 40 CFR 63.7540(a)(10) are required.5.5 LB/MMSCF 3 HOUR BLOCK AVERAGE BACT-PSD
AR-0171 NUCOR STEEL ARKANSAS AR 02/14/2019 ACT SN-233 Galvanizing Line Boilers 15
MMBTU/hr
each Good combustion practices 0.0055 LB/MMBTU NA BACT-PSD
LA-0349 DRIFTWOOD LNG FACILITY LA 07/10/2018 ACT Hot Oil Heaters (5)16.13 mm btu/hr Good Combustion Practices and Use of low sulfur facility fuel
gas 0.0054 LB/MM BTU NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY 04/19/2021 ACT
Pickle Line #2 – Boiler #1 & #2 (EP 21-
04 & EP 21-05)18
MMBtu/hr,
each
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan 5.5 LB/MMSCF EACH BACT-PSD
WI-0292 GREEN BAY PACKAGING INC. –MILL DIVISION WI 04/01/2019 ACT P44 Space Heaters 20 mmBTU/hr Good Combustion Practices, the Use of Low-NOx Burners 0.0055 LB/MMBTU NA BACT-PSD
AR-0140 BIG RIVER STEEL LLC AR 09/18/2013 ACT
FURNACES SN-40 AND SN-42,
DECARBURIZING LINE 22 MMBTU/H COMBUSTION OF NATURAL GAS AND GOOD COMBUSTION
PRACTICE 0.0054 LB/MMBTU NA BACT-PSD
MI-0440 MICHIGAN STATE UNIVERSITY MI 05/22/2019 ACT FGFUELHEATERS 25 MMBTU/H Good combustion practices 0.005 LB/MMBTU HOURLY; EACH UNIT BACT-PSD
-SJVAPCD CA 11/30/2022 Boiler ≥20 MMBtu/hr PUC quality natural gas or propane with LPG backup NA NA BACT
Throughput Emission Limit
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
AL-0307 ALLOYS PLANT AL 10/09/2015 ACT 2 CALP LINE BOILERS 24.59 MMBTU/H GCP 0.006 LB/MMBTU NA BACT-PSD
*OH-0387 INTEL OHIO SITE OH 09/20/2022 ACT
29.4 MMBtu/hr Natural Gas-Fired Boilers:
B001 through B028 29.4 MMBTU/H Good combustion practices and the use of natural gas 4.86 T/YR PER ROLLING 12 MONTH PERIOD B001 TO B0 BACT-PSD
WY-0075 CHEYENNE PRAIRIE GENERATING STATION WY 07/16/2014 ACT Auxiliary Boiler 25.06 MMBtu/h good combustion practices 0.0017 LB/MMBTU 3 HOUR AVERAGE BACT-PSD
OH-0375 LONG RIDGE ENERGY GENERATION LLC - HANNIBAL
POWER OH 11/07/2017 ACT Auxiliary Boiler (B001)26.8 MMBTU/H Good combustion controls 0.13 LB/H NA BACT-PSD
WI-0283 AFE, INC. –LCM PLANT WI 04/24/2018 ACT B01-B12, Boilers 28 mmBTU/hr Ultra-low NOx Burners, Flue Gas Recirculation and Good
Combustion Practices 0.0036 LB/MMBTU NA BACT-PSD
WI-0284 SIO INTERNATIONAL WISCONSIN, INC. -ENERGY
PLANT WI 04/24/2018 ACT
B13-B24 & B25-B36 Natural Gas-Fired
Boilers 28 mmBTU Ultra-Low NOx Burners, Flue Gas Recirculation, and Good
Combustion Practices.0.0036 LB/MMBTU NA BACT-PSD
AR-0140 BIG RIVER STEEL LLC AR 09/18/2013 ACT BOILERS SN-26 AND 27, GALVANIZING LINE 24.5 MMBTU/H COMBUSTION OF NATURAL GAS AND GOOD COMBUSTION
PRACTICE 0.0054 LB/MMBTU NA BACT-PSD
TX-0772 PORT OF BEAUMONT PETROLEUM TRANSLOAD
TERMINAL (PBPTT)TX 11/06/2015 ACT
Commercial/Institutional-Size
Boilers/Furnaces 13.2 MMBTU/H Good combustion practice to ensure complete combustion.0.3 T/YR NA BACT-PSD
SC-0193 MERCEDES BENZ VANS, LLC SC 04/15/2016 ACT Energy Center Boilers 14.27 MMBTU/hr Annual tune ups per 40 CFR 63.7540(a)(10) are required.5.5 LB/MMSCF 3 HOUR BLOCK AVERAGE BACT-PSD
KY-0110 NUCOR STEEL BRANDENBURG KY 07/23/2020 ACT
EP 03-05 - Steckel Mill Coiling Furnaces #1
& #2 17.5
MMBtu/hr,
each
This EP is required to have a Good Combustion and Operating
Practices (GCOP) Plan.5.5 LB/MMSCF NA BACT-PSD
KY-0110 NUCOR STEEL BRANDENBURG KY 07/23/2020 ACT
EP 05-01 - Group 1 Car Bottom Furnaces #1 -
#3 28
MMBtu/hr,
each
This EP is required to have a Good Combustion and Operating
Practices (GCOP) Plan.5.5 LB/MMSCF NA BACT-PSD
MI-0425 GRAYLING PARTICLEBOARD MI 05/09/2017 ACT EUFLTOS1 in FGTOH 10.2 MMBTU/H Good design and operating/combustion practices.0.0054 LB/MMBTU TEST PROTOCOL SHALL SPECIFY BACT-PSD
MI-0424 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH
STREET MI 12/05/2016 ACT EUFUELHTR (Fuel pre-heater)3.7 MMBTU/H Good combustion practices.0.03 LB/H TEST PROTOCOL WILL SPECIFY AVG TIME BACT-PSD
MI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 07/16/2018 ACT EUFUELHTR1: Natural gas fired fuel heater 20.8 MMBTU/H Good combustion controls 0.17 LB/H HOURLY BACT-PSD
MI-0435 BELLE RIVER COMBINED CYCLE POWER PLANT MI 07/16/2018 ACT EUFUELHTR2: Natural gas fired fuel heater 3.8 MMBTU/H Good combustion controls.0.03 LB/H HOURLY BACT-PSD
MI-0440 MICHIGAN STATE UNIVERSITY MI 05/22/2019 ACT FGFUELHEATERS 25 MMBTU/H Good combustion practices 0.005 LB/MMBTU HOURLY; EACH UNIT BACT-PSD
*MI-0445 INDECK NILES, LLC MI 11/26/2019 ACT FGFUELHTR (2 fuel pre-heaters)27 MMBTU/H Good combustion practices 0.07 LB/H HOURLY; EACH FUEL HEATER BACT-PSD
MI-0423 INDECK NILES, LLC MI
01/04/2017 ACT
FGFUELHTR (Two fuel pre-heaters identified
as EUFUELHTR1 & EUFUELHTR2)27
MMBTU/H Good combustion practices.0.15 LB/H HOURLY; EACH FUEL HEATER BACT-PSD
MI-0442 THOMAS TOWNSHIP ENERGY, LLC MI 08/21/2019 ACT FGPREHEAT 7 MMBTU/H Good combustion practices 0.025 LB/MMBTU HOURLY; EACH UNIT BACT-PSD
OH-0374 GUERNSEY POWER STATION LLC OH 10/23/2017 ACT
Fuel Gas Heaters (2 identical, P007 and
P008)15 MMBTU/H Combustion control 0.075 LB/H NA BACT-PSD
MI-0412 HOLLAND BOARD OF PUBLIC WORKS - EAST 5TH
STREET MI 12/04/2013 ACT Fuel pre-heater (EUFUELHTR)3.7 MMBTU/H Good combustion practices 0.03 LB/H TEST PROTOCOL BACT-PSD
AR-0140 BIG RIVER STEEL LLC AR 09/18/2013 ACT
FURNACES SN-40 AND SN-42,
DECARBURIZING LINE 22 MMBTU/H COMBUSTION OF NATURAL GAS AND GOOD COMBUSTION
PRACTICE 0.0054 LB/MMBTU NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY 04/19/2021 ACT
Galvanizing Line #2 Alkali Cleaning Section
Heater (EP 21-07B)23 MMBtu/hr The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan 5.5 LB/MMSCF NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY 04/19/2021 ACT
Galvanizing Line #2 Annealing Furnaces (15)
(EP 21-15)4.8
MMBtu/hr,
each
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan 5.5 LB/MMSCF NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY 04/19/2021 ACT
Galvanizing Line #2 Zinc Pot Preheater (EP
21-09)3 MMBtu/hr The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan 5.5 LB/MMSCF NA BACT-PSD
TX-0656 GAS TO GASOLINE PLANT TX 05/16/2014 ACT heaters (5)24.3 MMBTU/H clean fuel and good combustion practices 2.44 T/YR NA BACT-PSD
LA-0349 DRIFTWOOD LNG FACILITY LA 07/10/2018 ACT Hot Oil Heaters (5)16.13 mm btu/hr Good Combustion Practices and Use of low sulfur facility fuel
gas 0.0054 LB/MM BTU NA BACT-PSD
WI-0292 GREEN BAY PACKAGING INC. –MILL DIVISION WI 04/01/2019 ACT P44 Space Heaters 20 mmBTU/hr Good Combustion Practices, the Use of Low-NOx Burners 0.0055 LB/MMBTU NA BACT-PSD
AL-0307 ALLOYS PLANT AL 10/09/2015 ACT PACKAGE BOILER 17.5 MMBTU/H GCP 0.006 LB/MMBTU NA BACT-PSD
KY-0115 NUCOR STEEL GALLATIN, LLC KY 04/19/2021 ACT
Pickle Line #2 – Boiler #1 & #2 (EP 21-
04 & EP 21-05)18
MMBtu/hr,
each
The permittee must develop a Good Combustion and
Operating Practices (GCOP) Plan 5.5 LB/MMSCF EACH BACT-PSD
*LA-0315 G2G PLANT LA 05/23/2014 ACT Reactor Charge Heater - 53B001 10.1 MMBTU/HR Combustion controls (proper burner design and operation
using natural gas)0.05 LB/H HOURLY MAXIMUM BACT-PSD
AR-0171 NUCOR STEEL ARKANSAS AR 02/14/2019 ACT SN-233 Galvanizing Line Boilers 15
MMBTU/hr
each Good combustion practices 0.0055 LB/MMBTU NA BACT-PSD
SC-0179 CAROLINA PARTICLEBOARD SC 03/18/2015 ACT THERMAL OIL HEATER #2 1.83 MMBTU/H NATURAL GAS USAGE AND GOOD COMBUSTION PRACTICES.0.01 LB/H NA BACT-PSD
MI-0448 GRAYLING PARTICLEBOARD MI 12/18/2020 ACT
Thermal oil system for thermally fused
lamination lines (EUFLTOS1 in FGTOH)10.2 MMBTU/H Good Design and Operating/Combustion Practices 0.0054 LB/MMBTU HOURLY BACT-PSD
Throughput Emission Limit
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
KY-0110 NUCOR STEEL BRANDENBURG KY 07/23/2020 ACT
EP 10-07 - Air Separation Plant Emergency
Generator 700 HP This EP is required to have a Good Combustion and Operating
Practices (GCOP) Plan.4.77 G/HP-HR NMHC + NOX BACT-PSD
KY-0110 NUCOR STEEL BRANDENBURG KY 07/23/2020 ACT EP 10-04 - Emergency Fire Water Pump 920 HP This EP is required to have a Good Combustion and Operating
Practices (GCOP) Plan.4.77 G/HP-HR NMHC + NOX BACT-PSD
MI-0406 RENAISSANCE POWER LLC MI
11/01/2013 ACT
FG-EMGEN7-8; Two (2) 1,000kW diesel-
fueled emergency reciprocating internal
combustion engines 1000
kW Good combustion practices 4.8 G/B-HP-H TEST PROTOCOL; EACH UNIT BACT-PSD
MI-0433 MEC NORTH, LLC AND MEC SOUTH LLC MI 06/29/2018 ACT
EUEMENGINE (North Plant): Emergency
Engine 1341 HP Good combustion practices and meeting NSPS Subpart IIII
requirements.6.4 G/KW-H HOURLY BACT-PSD
WI-0300 NEMADJI TRAIL ENERGY CENTER WI
09/01/2020 ACT Emergency Diesel Generator (P07)1490
HP Operation limited to 500 hours/year and operate and maintain
according to the manufacturer’s recommendations.4.8 G/HP-H NA BACT-PSD
MI-0441 LBWL--ERICKSON STATION MI 12/21/2018 ACT
EUEMGD1--A 1500 HP diesel fueled
emergency engine 1500 HP Good combustion practices and will be NSPS compliant.6.4 G/KW-H HOURLY BACT-PSD
OH-0377 HARRISON POWER OH 04/19/2018 ACT Emergency Diesel Generator (P003)1860 HP Good combustion practices (ULSD) and compliance with 40
CFR Part 60, Subpart IIII 19.68 LB/H NMHC+NOX. SEE NOTES.BACT-PSD
OH-0375 LONG RIDGE ENERGY GENERATION LLC - HANNIBAL
POWER OH 11/07/2017 ACT Emergency Diesel Generator Engine (P001)2206 HP Good combustion design 24.71 LB/H NMHC+NOX. SEE NOTES.BACT-PSD
MD-0042 WILDCAT POINT GENERATION FACILITY MD 04/08/2014 ACT EMERGENCY GENERATOR 1 2250 KW LIMITED OPERATING HOURS, USE OF ULTRA- LOW SULFUR
FUEL AND GOOD COMBUSTION PRACTICES 4.8 G/HP-H NA LAER
OH-0366 CLEAN ENERGY FUTURE - LORDSTOWN, LLC OH 08/25/2015 ACT Emergency generator (P003)2346 HP State-of-the-art combustion design 21.6 LB/H NA BACT-PSD
-SCAQMD CA 12/10/2015 Emergency generator 2220 BHP Diesel particulate filter installed 4.8 g/bhp-hr NA BACT
-SCAQMD CA 12/10/2015 Emergency generator 755 BHP Diesel particulate filter installed 4.8 g/bhp-hr NA BACT
-SJVAPCD CA 4/29/2022 Emergency generator >750 bhp EPA Tier 4 Final certification level or equivalent for applicable
horsepower range 0.5 g/bhp-hr NA BACT
Throughput Emission Limit
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
OK-0156 NORTHSTAR AGRI IND ENID OK 07/31/2013 ACT Fire Pump Engine 550 hp Good Combustion 0.35 LB/MMBTU 3-HOUR AVG BACT-PSD
OH-0375 LONG RIDGE ENERGY GENERATION LLC - HANNIBAL
POWER OH 11/07/2017 ACT Emergency Diesel Fire Pump Engine (P002)700 HP Good combustion design 4.97 LB/H NMHC+NOX. SEE NOTES.BACT-PSD
OH-0360 CARROLL COUNTY ENERGY OH 11/05/2013 ACT Emergency generator (P003)1112 KW Purchased certified to the standards in NSPS Subpart IIII 1.93 LB/H NA BACT-PSD
*MI-0452 MEC SOUTH, LLC MI 06/23/2022 ACT
EUEMENGINE (South Plant): Emergency
engine 1341 HP Good combustion practices.0.86 LB/H HOURLY BACT-PSD
SC-0193 MERCEDES BENZ VANS, LLC SC 04/15/2016 ACT Emergency Generators and Fire Pump 1500 hp Must meet the standards of 40 CFR 60, Subpart IIII 100 HR/YR 12 MONTH ROLLING SUM BACT-PSD
OH-0370 TRUMBULL ENERGY CENTER OH 09/07/2017 ACT Emergency generator (P003)1529 HP State-of-the-art combustion design 2 LB/H NA BACT-PSD
OH-0377 HARRISON POWER OH 04/19/2018 ACT Emergency Diesel Generator (P003)1860 HP Good combustion practices (ULSD) and compliance with 40
CFR Part 60, Subpart IIII 19.68 LB/H NMHC+NOX. SEE NOTES.BACT-PSD
OH-0375 LONG RIDGE ENERGY GENERATION LLC - HANNIBAL
POWER OH 11/07/2017 ACT Emergency Diesel Generator Engine (P001)2206 HP Good combustion design 24.71 LB/H NMHC+NOX. SEE NOTES.BACT-PSD
-SCAQMD CA 12/10/2015 Emergency Generator 2220 BHP Diesel particulate filter installed NA NA BACT
-SCAQMD CA 12/10/2015 Emergency Generator 755 BHP Diesel particulate filter installed NA NA BACT
-SJVAPCD CA 4/29/2022 Emergency Generator >750 bhp EPA Tier 4 Final certification level or equivalent for applicable
horsepower range 0.14 g/bhp-hr NA BACT
Throughput Emission Limit
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
KY-0110 NUCOR STEEL BRANDENBURG KY 07/23/2020 ACT
EP 11-05 - Radio Tower Emergency
Generator 61 HP This EP is required to have a Good Combustion and Operating
Practices (GCOP) Plan.3.5 G/HP-HR NMHC + NOX BACT-PSD
NJ-0084 PSEG FOSSIL LLC SEWAREN GENERATING STATION NJ 03/10/2016 ACT Emergency Diesel Fire Pump 100 H/YR use of ULSD a clean burning fuel, and limited hours of
operation 1.7 LB/H NA LAER
OH-0379 PETMIN USA INCORPORATED OH
02/06/2019 ACT Black Start Generator (P007)158
HP Tier IV engine
Tier IV NSPS standards certified by engine manufacturer.0.104 LB/H NA BACT-PSD
LA-0379 SHINTECH PLAQUEMINES PLANT 1 LA 05/04/2021 ACT VCM Unit Emergency Cooling Water Pumps 180 hp Good combustion practices/gaseous fuel burning.2.98 G/KW-HR NA BACT-PSD
MI-0434 FLAT ROCK ASSEMBLY PLANT MI 03/22/2018 ACT
EUFIREPUMPENGS (2 emergency fire pump
engines)250 BHP Good combustion practices.3 G/B-HP-H HOURLY; EACH ENGINE (NMHC+NOX)BACT-PSD
LA-0328 PLAQUEMINES PLANT 1 LA 05/02/2018 ACT Emergency Diesel Engine Pump P-39B 300 HP Good combustion practices and NSPS Subpart IIII 4 G/KW-H NA BACT-PSD
MD-0045 MATTAWOMAN ENERGY CENTER MD 11/13/2015 ACT
EMERGENCY DIESEL ENGINE FOR FIRE
WATER PUMP 305 HP EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND GOOD
COMBUSTION PRACTICES 4 G/KW-H NA LAER
MD-0043 PERRYMAN GENERATING STATION MD 07/01/2014 ACT
EMERGENCY DIESEL ENGINE FOR FIRE
WATER PUMP 350 HP GOOD COMBUSTION PRACTICES, LIMITED HOURS OF
OPERATION, AND EXCLUSIVE USE OF ULSD 3 G/HP-H NA LAER
OH-0378 PTTGCA PETROCHEMICAL COMPLEX OH
12/21/2018 ACT Firewater Pumps (P005 and P006)402
HP
Certified to the meet the emissions standards in Table 4 of 40
CFR Part 60, Subpart IIII and employ good combustion
practices per the manufacturer’s operating manual
2.64 LB/H NA BACT-PSD
-SCAQMD CA 12/10/2015 Emergency Generator 374 BHP Diesel particulate filter installed 3 g/bhp-hr NA BACT
-SJVAPCD CA 4/29/2022 Emergency Generator <750 bhp EPA Tier 4 Final certification level or equivalent for applicable
horsepower range 0.3 g/bhp-hr NA BACT
Throughput Emission Limit
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
NJ-0084 PSEG FOSSIL LLC SEWAREN GENERATING STATION NJ 03/10/2016 ACT Emergency Diesel Fire Pump 100 H/YR use of ULSD a clean burning fuel, and limited hours of
operation 0.1 LB/H NA LAER
OH-0366 CLEAN ENERGY FUTURE - LORDSTOWN, LLC OH 08/25/2015 ACT Emergency fire pump engine (P004)140 HP State-of-the-art combustion design 0.11 LB/H NA BACT-PSD
*WI-0261 ENBRIDGE ENERGY - SUPERIOR TERMINAL WI
06/12/2014 ACT
EG7 - Diesel Emergency Electric Generator
w/ tank 197
BHP
NSPS engine [Tier 3 emergency engine]. EG7
Storage tank, conventional fuel oil storage tank, good
operating practices; limiting leakage, spills. (FT01). Engine
limited to 200 hours / year (total) and NSPS requirements.
3.75 GRAM / HP-H NOX + NMHC HOURLY AVG., FOR EG7 BACT-PSD
TX-0846 MOTOR VEHICLE ASSEMBLY PLANT TX 09/23/2018 ACT FIRE PUMP DIESEL ENGINE 214 kW Meets EPA Tier 4 requirements 0.19 G/KW HR BACT-PSD
*OH-0387 INTEL OHIO SITE OH 09/20/2022 ACT
275 hp (205 kW) Diesel-Fired Emergency
Fire Pump Engine 275 HP Certified to meet the standards in Table 4 of 40 CFR Part 60,
Subpart IIII and good combustion practices 0.7 LB/H NA BACT-PSD
LA-0328 PLAQUEMINES PLANT 1 LA 05/02/2018 ACT Emergency Diesel Engine Pump P-39B 300 HP Good combustion practices and NSPS Subpart IIII 4 G/KW-H NA BACT-PSD
OH-0377 HARRISON POWER OH 04/19/2018 ACT Emergency Fire Pump (P004)320 HP Good combustion practices (ULSD) and compliance with 40
CFR Part 60, Subpart IIII 2.12 LB/H NMHC+NOX. SEE NOTES.BACT-PSD
MD-0044 COVE POINT LNG TERMINAL MD 06/09/2014 ACT 5 EMERGENCY FIRE WATER PUMP ENGINES 350 HP USE ONLY ULSD, GOOD COMBUSTION PRACTICES, AND
DESIGNED TO ACHIEVE EMISSION LIMIT 3 G/HP-H NOX + NMHC LAER
LA-0328 PLAQUEMINES PLANT 1 LA 05/02/2018 ACT Emergency Diesel Engine Pump P-39A 375 HP Good combustion practices and NSPS Subpart IIII 4 G/KW-H NA BACT-PSD
OH-0378 PTTGCA PETROCHEMICAL COMPLEX OH
12/21/2018 ACT Firewater Pumps (P005 and P006)402
HP
Certified to the meet the emissions standards in Table 4 of 40
CFR Part 60, Subpart IIII and employ good combustion
practices per the manufacturer’s operating manual
2.64 LB/H NA BACT-PSD
-SJVAPCD CA 4/29/2022 Emergency Generator <750 bhp EPA Tier 4 Final certification level or equivalent for applicable
horsepower range 0.14 g/bhp-hr NA BACT
Throughput Emission Limit
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
AL-0226 TORAY CARBON FIBER AMERICA, INC. (CFA)AL 12/20/2007 ACT BOILERS 66.6
MMBTU/H
each LOW NOX BURNERS PLUS FLUE GAS RECIRCULATION (FGR)0.024 LB/MMBTU NA BACT-PSD
*WA-0350 SGL AUTOMOTIVE CARBON FIBERS WA
04/13/2015 ACT
Carbon Fiber Production (Normal Operation)
Lines 3-6 1760
tons of
carbon fiber
per year
SCR for Lines 3 - 6. No SCR on lines 7-10 8.5 LB LB/HR OTHER CASE-BY-CASE
Throughput Emission Limit
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
AL-0226 TORAY CARBON FIBER AMERICA, INC. (CFA)AL 12/20/2007 ACT
132,086 GALLON SOLVENT DELIVERY
STORAGE TANK VENTED TO SCRUBBER SCRUBBER TA2-2 95 % REDUCTION NA N/A
AL-0226 TORAY CARBON FIBER AMERICA, INC. (CFA)AL
12/20/2007 ACT
211,338 GALLON ACRYLONITRILE DELIVERY
STORAGE TANK VENTED TO SCRUBBER TA2-2
SCRUBBER TA2-2 95 % REDUCTION NA N/A
*WA-0350 SGL AUTOMOTIVE CARBON FIBERS WA
04/13/2015 ACT
Carbon Fiber Production (Normal Operation)
Lines 7-10 1760
tons of
carbon fiber
per year
NA 1.7 LB HR BACT-PSD
*WA-0350 SGL AUTOMOTIVE CARBON FIBERS WA
04/13/2015 ACT
Carbon Fiber Production (Normal Operation)
Lines 3-6 1760
tons of
carbon fiber
per year
NA NA BACT-PSD
Throughput Emission Limit
NA
NA
NA
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
TX-0662 BEAUMONT PLANT TX 07/22/2014 ACT Methanol Plant Dry low NOx burners and SCR 0.015 LB/MMBTU 24-HOUR BACT-PSD
*WA-0350 SGL AUTOMOTIVE CARBON FIBERS WA 04/13/2015 ACT
Carbon Fiber Production (Shutdown Mode)
Lines 3-6 SCR 8.5 LB HR OTHER CASE-BY-CASE
*WA-0350 SGL AUTOMOTIVE CARBON FIBERS WA
04/13/2015 ACT
Carbon Fiber Production (Normal Operation)
Lines 3-6 1760
tons of
carbon fiber
per year
SCR for Lines 3 - 6. No SCR on lines 7-10 8.5 LB LB/HR OTHER CASE-BY-CASE
Throughput Emission Limit
NA
NA
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
IN-0251 RES POLYFLOW, LLC IN 08/03/2016 ACT PLASTICS TO FUEL CONVERSION 51.74 MMBTU/H
PROCESS FUEL GAS COMBUSTION TO GENERATE HEAT
REQUIRED FOR PROCESSING 98 % OVERALL
CONTROL EF NA OTHER CASE-BY-CASE
IN-0253 RES POLYFLOW, LLC IN 08/03/2016 ACT PLASTICS TO FUEL CONVERSION 51.74 MMBTU/H
PROCESS FUEL GAS COMBUSTION TO GENERATE HEAT
REQUIRED FOR PROCESSING 98 % OVERALL
CONTROL EF NA OTHER CASE-BY-CASE
LA-0295 WESTLAKE FACILITY LA 07/12/2016 ACT Bulk Storage Vents (RLP 5, 9, 10, & 11)1200 ACFM Good design and operating practices 0.01 LB/H HOURLY MAXIMUM BACT-PSD
*LA-0315 G2G PLANT LA 05/23/2014 ACT Methanol Degassing Water Scrubber 11.2 LB/H HOURLY MAXIMUM BACT-PSD
TX-0681 OLEFINS PLANT TX 08/08/2014 ACT Caustic tank Carbon adsorption system (CAS)166 PPMW NA BACT-PSD
TX-0888 ORANGE POLYETHYLENE PLANT TX
04/23/2020 ACT
Ethylene Treater Regeneration Vents –
Process Vents
Emissions associated with this activity will be routed either back
into the process or to flares.
Any uncontrolled venting to the atmosphere will be limited to
20 ppmv of VOC.
20 PPMV UNCONTROLLED BACT-PSD
TX-0888 ORANGE POLYETHYLENE PLANT TX
04/23/2020 ACT
Polyethylene Product Residual Filters, Pellet
Dewatering Dryers, and Pellet Loading –
Process Vents
Limiting amount of VOC per million pounds of pellets.
Extruder vent emissions will be controlled using two thermal
oxidizers.
80 LB/MMLB HOURLY BACT-PSD
NA
Throughput Emission Limit
NA
NA
NA
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
AL-0226 TORAY CARBON FIBER AMERICA, INC. (CFA)AL 12/20/2007 ACT BOILERS 66.6
MMBTU/H
each LOW NOX BURNERS PLUS FLUE GAS RECIRCULATION (FGR)0.024 LB/MMBTU NA BACT-PSD
AL-0226 TORAY CARBON FIBER AMERICA, INC. (CFA)AL
12/20/2007 ACT
CARBON FIBER MANUFACTURING PROCESS
(CFA-3) WITH THERMAL OXIDIZER
LOW NOX BURNERS AND GOOD OPERATING PRACTICES 57.6 LB/H NA BACT-PSD
TX-0242 AMERICAN ACRYL L.P.TX
04/21/1999 ACT SUPPORT PROCESS UNITS
USE NATURAL GAS IN BOILER, EMISSIONS FROM TANKS
ROUTED TO SCRUBBER (99.9% RECOVERY), 28 LAER
LDAR, BOILER EQUIPPED WITH LOW NOX BURNERS, O2
POOR AIR USED
NA LAER
Throughput Emission Limit
NA
NA
NA
RBLCID Facility/Agency Name State Permit/Document Issued Process Name Control Method Averaging Time Case-by-Case
AL-0226 TORAY CARBON FIBER AMERICA, INC. (CFA)AL 12/20/2007 ACT
132,086 GALLON SOLVENT DELIVERY
STORAGE TANK VENTED TO SCRUBBER SCRUBBER TA2-2 95 % REDUCTION NA N/A
AL-0226 TORAY CARBON FIBER AMERICA, INC. (CFA)AL
12/20/2007 ACT
211,338 GALLON ACRYLONITRILE DELIVERY
STORAGE TANK VENTED TO SCRUBBER TA2-2
SCRUBBER TA2-2 95 % REDUCTION NA N/A
SC-0116 CYTEC CARBON FIBERS, LLC SC
04/30/2008 ACT AN STORAGE AND RECOVERY
EXISTING WASTE HEAT RECOVERY BOILER OR PROCESS
HEATER/AFTERBURNER WITH CARBON BED ADSORBERS AS
BACK UP.
0.4 LB/H NA BACT-PSD
SC-0116 CYTEC CARBON FIBERS, LLC SC
04/30/2008 ACT POLYMER PRODUCTION
EXISTING WASTE HEAT RECOVERY BOILER OR PROCESS
HEATER/AFTERBURNER WITH CARBON BED ADSORBERS AS
BACK UP.
0.4 LB/H NA BACT-PSD
SC-0116 CYTEC CARBON FIBERS, LLC SC 04/30/2008 ACT OXIDATION AND CARBONIZATION NATURAL GAS FIRED TWO-STAGE THERMAL OXIDIZER 20 PPMW TOC NA BACT-PSD
SC-0122 CYTEC CARBON FIBERS, LLC SC
04/30/2008 ACT POLYMER PRODUCTION
EXISTING WASTE HEAT RECOVERY BOILER OR PROCESS
HEATER/AFTERBURNER WITH CARBON BED ADSORBERS AS
BACK UP.
0.4 LB/H NA BACT-PSD
SC-0122 CYTEC CARBON FIBERS, LLC SC 04/30/2008 ACT OXIDATION AND CARBONIZATION NATURAL GAS FIRED TWO-STAGE THERMAL OXIDIZER 20 PPMV TOC NA BACT-PSD
TX-0242 AMERICAN ACRYL L.P.TX 04/21/1999 ACT SUPPORT PROCESS UNITS
28 LAER LDAR, MONITORING, EMISSIONS FROM TANKS
ROUTED TO THE SCRUBBER (99.9% RECOVERY)NA LAER
NA
Throughput Emission Limit
NA
NA
NA
NA
NA
NA
NA NA