DAQ-2024-008123

1/23/24, 11:53 AM State of Utah Mail - Reasonably Available Control Technology Analysis for PacifiCorp Gadsby Power Plant
https://mail.google.com/mail/u/0/?ik=539c285453&view=pt&search=all&permmsgid=msg-f:1787662978057528516&simpl=msg-f:1787662978057528…1/1
Ana Williams <[e-mail]>
Reasonably Available Control Technology Analysis for PacifiCorp Gadsby Power Plant
Sewell, Joshua (PacifiCorp) <[e-mail]>Tue, Jan 9, 2024 at 5:57 PM
To: Ana Williams <[e-mail]>
Cc: "Tiberius, Leah (PacifiCorp)" <[e-mail]>, "Shakespear, Brett (PacifiCorp)" <[e-mail]>,
"Lewis, Scarlet (PacifiCorp)" <[e-mail]>, "Wiscomb, Thomas (PacifiCorp)" <[e-mail]>,
"[e-mail]" <[e-mail]>
Ana,

On May 31, 2023, PacifiCorp Received a letter from The Utah Department of Environmental Quality – Division of
Air Quality (DAQ) identifying the Gadsby Power Plant as a major source in the Northern Wasatch Front Ozone
Nonattainment Area. The letter requested that PacifiCorp submit a Reasonably Achievable Control Technology
(RACT) analysis by January 2, 2024, for the Gadsby Power Plant. DAQ later provided the plant an extension of the
submission deadline to January 9, 2024. PacifiCorp has followed the top down RACT analysis process for each
NOX and VOC emission source at the plant. Plant emissions from 2017 were utilized to prepare cost effectiveness
analyses for add-on controls; these analyses demonstrate that no additional controls are cost effective at this time.
Attached is the RACT analysis supporting this conclusion.

Please reach out with any questions regarding the RACT analysis.

Best,

Josh Sewell
Environmental Engineer
[phone]

2024-01-09 Gadsby RACT Analysis_Final.pdf
3433K

January 9, 2024

Mr. Bryce Bird, Director
Utah Division of Air Quality
195 North 1950 West
P.O. Box 144820
Salt Lake City, UT 84114-4820

ATTN: Ana Williams

Subject: Reasonably Available Control Technology Review for PacifiCorp Gadsby Power Plant

Dear Ms. Williams,

On August 3, 2018, the Environmental Protection Agency classified the Northern Wasatch Front
as a marginal non-attainment area for the 2015 National Ambient Air Quality Standard
(NAAQS) for ozone. The Northern Wasatch Front was required to attain the ozone standard by
August 3, 2021, for marginal classification. However, the Northern Wasatch Front Ozone
Nonattainment Area (NAA) did not attain the ozone standard by the attainment date and was
reclassified to moderate status on November 7, 2022.

The Northern Wasatch Front NAA is required to attain the ozone standard by August 3, 2024, for
moderate classification based on data from 2021, 2022, and 2023. Recent monitoring data
indicates the Northern Wasatch Front NAA will not attain the standard and will be reclassified to
serious status in February of 2025.

On May 31, 2023, PacifiCorp Received a letter from The Utah Department of Environmental
Quality – Division of Air Quality (DAQ) identifying the Gadsby Power Plant as a major source
in the Northern Wasatch Front Ozone NAA. The letter requested that PacifiCorp submit a
Reasonably Achievable Control Technology (RACT) analysis by January 2, 2024, for the
Gadsby Power Plant. DAQ later provided the plant an extension of the submission deadline to
January 9, 2024. PacifiCorp has followed the top down RACT analysis process for each NOX
and VOC emission source at the plant. Plant emissions from 2017 were utilized to prepare cost
effectiveness analyses for add-on controls; these analyses demonstrate that no additional controls
are cost effective at this time. Attached is the RACT analysis supporting this conclusion.

Please contact Josh Sewell at [phone] or me at [phone] if there are any questions
regarding the contents of the RACT analysis attached herewith.

Sincerely,
Brett Shakespear
Director, Environmental Compliance and Remediation

cc: Bill Kennick
Josh Sewell
Leah Tiberius
Tom Wiscomb

Reasonable Available Control
Technology Review for
PacifiCorp Gadsby Power
Plant
December 2023

Reasonable Available Control Technology
Review for Gadsby Power Plant
AECOM
Executive Summary
On August 3, 2018, the Environmental Protection Agency (EPA) classified the Northern Wasatch Front as
a marginal non-attainment area for the 2015 National Ambient Air Quality Standard (NAAQS) for ozone.
The Northern Wasatch Front was required to attain the ozone standard by August 3, 2021, for marginal
classification. However, the Northern Wasatch Front Ozone Nonattainment Area (NAA) did not attain the
ozone standard by the attainment date and was reclassified to moderate status on November 7, 2022.
The Northern Wasatch Front NAA is required to attain the ozone standard by August 3, 2024, for moderate
classification based on data from 2021, 2022, and 2023. Recent monitoring data indicates the Northern
Wasatch Front NAA will not attain the standard and will be reclassified to serious status in February of 2025.
This anticipated reclassification from moderate to serious status will trigger new control strategy
requirements for major sources in the Northern Wasatch Front NAA. In particular, these requirements
include preparation and submittal to the EPA of State Implementation Plan (SIP) revisions that include
provisions to address the adoption of Reasonably Available Control Technologies (RACT) for each major
source of nitrogen oxide (NOx) and volatile organic compound (VOC) emissions within the non-attainment
area (i.e., sources that emit 50 tons/year [tpy] or more of NOx or VOC).
PacifiCorp’s Gadsby Power Plant has potential to emit emissions of NOx above 50 tpy and is thus classified
as a major source which is subject to the implementation rule. As a major source subject to the rule, DAQ
has requested assistance from PacifiCorp in determining acceptable pollution controls that meet RACT
controls.
The Gadsby Power Plant currently operates its boilers and turbines at a low-capacity factor; thereby
emitting NOx and VOC at significantly lower levels than the plant’s potential to emit. Gadsby followed the
top down RACT analysis process for each NOx and VOC emission source at the plant. Plant emissions
from 2017 were utilized to prepare cost effectiveness analyses for add-on controls; these analyses
demonstrate that no additional controls are cost effective at this time. Table E-1 summarizes the proposed
RACT and emission limits for the Gadsby emission sources.
Reasonable Available Control Technology
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Table E-1 RACT Summary for Gadsby Power Plant
Pollutant RACT Emission Limit
Electric Generating Utility Boilers (EU#1, EU#2, and EU#3, collectively EU#4)
NOx Units #1 and #2 low-NOx burners (LNB),
Unit #3 Flue Gas Recirculation (FGR),
no additional controls are cost effective.
EU#1 - 179 lbs/hr @ 3% O2
EU#1 - 336 ppmvd @ 3% O2
EU#2 - 204 lbs/hr @ 3% O2
EU#2 - 336 ppmvd @ 3% O2
EU#3 - 203 lbs/hr @ 3% O2 for March 1
through October 31
EU#3 - 142 lbs/hr @ 3% O2 for
November 1 through February 28[29]
EU#3 - 168 ppmvd @ 3% O2
Fuel oil may be combusted during natural gas
curtailments or maintenance firings.
Maintenance firings are limited to April 1 through
November 30 not to exceed one percent of total
plant BTU requirement
VOC Efficient boiler design, using natural gas, good
combustion practices, and fuel oil usage limits.
None are being proposed.
Combustion Turbines (Units #4, #5, and #6, collectively EU#24)
NOx Water injection, selective catalytic reduction,
good combustion practices, and use of
pipeline-quality natural gas.
5 ppmvd @ 15% O2 30-day rolling average per
turbine (steady state), 116 ppmvd @ 15% O2 on
a 4-hour rolling average, 22.2 lb/hr @ 15% O2
based on 30-day rolling average (total emissions
all turbines)
VOC Use of natural gas, oxidation catalyst, and good
combustion practices.
None are being proposed.
Emergency Diesel Engines (EU#10 and EU#25)
NOx Good combustion practices and hours of
operation limit.
None are being proposed.
VOC Good combustion practices, and hours of
operation limit.
None are being proposed.
Storage Tanks (EU#11, EU#12, EU#13, EU#15, EU#16, EU#20, EU#21)
VOC Fixed roof tanks.None are being proposed.
Miscellaneous Parts Painting/Paint Storage (EU#17 and EU#19)
VOC VOC content of paints, high efficiency
application equipment, good housekeeping.
None are being proposed.
Gasoline Refueling (EU#26)
VOC Submerged fill and Stage II vapor recovery None are being proposed.
Reasonable Available Control Technology
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Table of Contents
1.Introduction ........................................................................................................... 7
1.1 Overview..................................................................................................................................... 7
1.2 Gadsby Process and Emission Unit Descriptions......................................................................... 8
1.2.1 Emission Units Evaluated ............................................................................................................ 8
1.3 Facility Emissions ..................................................................................................................... 10
2.RACT Assessment Methodology ........................................................................ 12
2.1 Top-Down RACT Review ........................................................................................................... 12
3.Proposed RACT for Nitrogen Oxide Emissions .................................................. 14
3.1 Natural Gas Boilers ................................................................................................................... 14
3.1.1 NOx Formation.......................................................................................................................... 14
3.1.2 Description of Existing NOx Controls ......................................................................................... 14
3.1.3 Step 1 - Available NOx Control Options ..................................................................................... 14
3.1.3.1 Clean Burning Fuels .............................................................................................................. 14
3.1.3.2 Good Combustion Practices ................................................................................................... 14
3.1.3.3 Low NOx Burners .................................................................................................................. 15
3.1.3.4 Ultra-Low NOx Burners .......................................................................................................... 15
3.1.3.5 Flue Gas Recirculation (FGR) ................................................................................................ 15
3.1.3.6 Low Excess Air Firing ............................................................................................................. 15
3.1.3.7 Staged Air/Fuel Combustion (Over-fire Air Injection) ............................................................... 15
3.1.3.8 Selective Catalytic Reduction (SCR) ...................................................................................... 15
3.1.3.9 Selective Non-catalytic Reduction (SNCR) ............................................................................. 16
3.1.4 Step 2 - Evaluation of Technical Feasibility of Available Controls................................................ 16
3.1.5 Step 3 - Evaluation and Ranking of Technically Feasible Controls.............................................. 16
3.1.6 Step 4 – NOx Control Effectiveness Evaluation ......................................................................... 17
3.1.6.1 Economic Impacts.................................................................................................................. 17
3.1.6.2 Energy impacts ...................................................................................................................... 17
3.1.6.3 Environmental Impacts........................................................................................................... 18
3.1.7 Step 5 – Selection of RACT ....................................................................................................... 18
3.2 Combustion Turbines ................................................................................................................ 18
3.2.1 NOx Formation.......................................................................................................................... 18
3.2.2 Description of Existing NOx Controls ......................................................................................... 19
3.2.3 Step 1 - Available NOx Control Options ..................................................................................... 19
3.2.3.1 Good Combustion Practices ................................................................................................... 19
3.2.3.2 Dry Low NOx Combustors...................................................................................................... 19
3.2.3.3 Water or Steam Injection ........................................................................................................ 19
3.2.3.4 Selective Catalytic Reduction (SCR) ...................................................................................... 20
3.2.3.5 Selective Non-Catalytic Reduction (SNCR) ............................................................................ 20
3.2.4 Step 2 - Evaluation of Technical Feasibility of Available Controls................................................ 20
3.2.5 Step 3 - Evaluation and Ranking of Technically Feasible Controls.............................................. 21
3.2.6 Step 4 – NOx Control Effectiveness Evaluation ......................................................................... 21
3.2.6.1 Energy Impacts ...................................................................................................................... 21
3.2.6.2 Environmental Impacts........................................................................................................... 21
3.2.7 Step 5 – Selection of RACT for Simple Cycle Combustion Turbines ........................................... 21
3.2.8 Step 5 – Selection of RACT for Simple Cycle Combustion Turbine Startup and Shutdown ......... 22
3.3 Insignificant NOx Emission Sources .......................................................................................... 23
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3.3.1 Diesel-fired Emergency Engines ............................................................................................... 23
3.3.2 NOx Formation.......................................................................................................................... 23
3.3.3 Description of Existing NOx Controls ......................................................................................... 23
3.3.4 Step 1 - Available NOx Control Options ..................................................................................... 23
3.3.4.1 Limited Hours of Operation .................................................................................................... 23
3.3.4.2 Use of a Tier Certified Engine................................................................................................. 23
3.3.4.3 Selective Catalytic Reduction ................................................................................................. 23
3.3.5 Step 2 - Evaluation of Technical Feasibility of Available Controls................................................ 24
3.3.6 Step 3 - Evaluation and Ranking of Technically Feasible Controls.............................................. 24
3.3.7 Step 4 – NOx Control Effectiveness Evaluation ......................................................................... 24
3.3.7.1 Energy, Environmental, and Economic Impacts ...................................................................... 24
3.3.8 Step 5 – Selection of RACT ....................................................................................................... 25
4.Proposed RACT for Volatile Organic Compound Emissions ............................... 26
4.1 Natural Gas Boilers ................................................................................................................... 26
4.1.1 VOC Formation ......................................................................................................................... 26
4.1.2 Description of Existing VOC Controls ........................................................................................ 26
4.1.3 Step 1 - Available VOC Control Options..................................................................................... 26
4.1.3.1 Clean Burning Fuels .............................................................................................................. 26
4.1.3.2 Good Combustion Practices ................................................................................................... 26
4.1.3.3 Thermal Oxidation.................................................................................................................. 26
4.1.3.4 Catalytic Oxidation ................................................................................................................. 27
4.1.4 Step 2 - Evaluation of Technical Feasibility of Available Controls................................................ 27
4.1.5 Step 3 - Evaluation and Ranking of Technically Feasible Controls.............................................. 27
4.1.6 Step 4 – VOC Control Effectiveness Evaluation ......................................................................... 27
4.1.6.1 Energy and Environmental Impacts ........................................................................................ 28
4.1.7 Step 5 – Selection of RACT ....................................................................................................... 28
4.2 Combustion Turbines ................................................................................................................ 28
4.2.1 VOC Formation ......................................................................................................................... 29
4.2.2 Description of Existing VOC Controls ........................................................................................ 29
4.2.3 Step 1 - Available VOC Control Options..................................................................................... 29
4.2.3.1 Oxidation Catalyst .................................................................................................................. 29
4.2.3.2 Good Combustion Practices ................................................................................................... 29
4.2.4 Step 2 - Evaluation of Technical Feasibility of Available Controls................................................ 29
4.2.5 Step 3 - Evaluation and Ranking of Technically Feasible Controls.............................................. 30
4.2.6 Step 4 – VOC Control Effectiveness Evaluation ......................................................................... 30
4.2.6.1 Energy and Environmental Impacts ........................................................................................ 30
4.2.7 Step 5 – Selection of RACT ....................................................................................................... 31
4.3 Insignificant VOC Emission Sources ......................................................................................... 31
4.3.1 Diesel-fired Emergency Engines ............................................................................................... 31
4.3.1.1 VOC Formation ...................................................................................................................... 31
4.3.1.2 Description of Existing VOC Controls ..................................................................................... 31
4.3.1.3 Step 1 - Available VOC Control Options ................................................................................. 31
4.3.1.5 Good Combustion Practices ................................................................................................... 31
4.3.1.6 Diesel Oxidation Catalyst ....................................................................................................... 32
4.3.1.7 Step 2 - Evaluation of Technical Feasibility of Available Controls ............................................ 32
4.3.1.8 Step 3 - Evaluation and Ranking of Technically Feasible Controls .......................................... 32
4.3.1.9 Step 4 – VOC Control Effectiveness Evaluation...................................................................... 32
4.3.1.10 Step 5 – Selection of RACT ................................................................................................... 32
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4.3.2 Storage Tanks ........................................................................................................................... 32
4.3.2.1 VOC Formation/ Description of Existing VOC Controls ........................................................... 33
4.3.2.1.1 Step 1 - Available VOC Control Options .............................................................................. 33
4.3.3 Step 2 - Evaluation of Technical Feasibility of Available Controls................................................ 33
4.3.3.1 Step 3 - Evaluation and Ranking of Technically Feasible Controls .......................................... 33
4.3.3.2 Step 4 – VOC Control Effectiveness Evaluation...................................................................... 33
4.3.3.3 Step 5 – Selection of RACT ................................................................................................... 34
4.3.4 Miscellaneous Painting Operations ............................................................................................ 34
4.3.4.1 Description of Existing VOC Controls ..................................................................................... 34
4.3.4.3 Step 2 - Evaluation of Technical Feasibility of Available Controls ............................................ 34
4.3.4.4 Step 3 - Evaluation and Ranking of Technically Feasible Controls .......................................... 35
4.3.4.5 Step 4 – VOC Control Effectiveness Evaluation...................................................................... 35
4.3.4.6 Step 5 – Selection of RACT ................................................................................................... 35
4.3.5 Gasoline Refueling .................................................................................................................... 35
4.3.5.1 VOC Formation ...................................................................................................................... 35
4.3.5.2 Description of Existing VOC Controls ..................................................................................... 35
4.3.5.3 Step 1 - Available VOC Control Options ................................................................................. 35
4.3.5.3.1 Stage I Vapor Recovery (refueling) ...................................................................................... 35
4.3.5.3.2 Stage II Vapor Recovery (refueling) ..................................................................................... 36
4.3.5.3.3 Submerged Fill (gasoline tank) ............................................................................................ 36
4.3.5.4 Steps 2, 3 and 4 - Evaluation of Technical Feasibility of Available Controls ............................. 36
4.3.5.5 Step 5 – Selection of RACT ................................................................................................... 36
Tables
Table 1. NOx and VOC Emission Sources............................................................................................... 9
Table 2. Gadsby 2017 NOx and VOC Emission Summary ..................................................................... 10
Table 3. Gadsby PTE NOx and VOC Emission Summary ...................................................................... 11
Table 4. BACT Determination Summary for NOx from Large Industrial and Utility Boilers ...................... 16
Table 5. Control Effectiveness of Technically Feasible NOx Controls for Gadsby Boilers ........................ 17
Table 6. SCR Cost Effectiveness Summary for NOx from Emergency Engines ...................................... 24
Table 7. Replacement Cost Effectiveness Summary for NOx from Tier 2/3 Emergency Engines ............ 25
Table 8. Cost Effectiveness of Oxidation Catalyst on Boilers #1-#3 ....................................................... 28
Table 9. Cost Effectiveness of Diesel Oxidation Catalyst on Emergency Diesel Engines ........................ 32
Appendices
Appendix A – DAQ RACT Request Letter
Appendix B – Facility Emissions
Appendix C – RACT/BACT/LAER Clearinghouse Search Results
Appendix D – Control Cost Analyses
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1. Introduction
1.1 Overview
On August 3, 2018, the Environmental Protection Agency (EPA) classified the Northern Wasatch Front as
a marginal non-attainment area for the 2015 National Ambient Air Quality Standard (NAAQS) for ozone.
The Northern Wasatch Front was required to attain the ozone standard by August 3, 2021, for marginal
classification. However, the Northern Wasatch Front Ozone Nonattainment Area (NAA) did not attain the
ozone standard by the attainment date and was reclassified to moderate status on November 7, 2022.
The Northern Wasatch Front NAA is required to attain the ozone standard by August 3, 2024, for moderate
classification based on data from 2021, 2022, and 2023. Recent monitoring data indicates the Northern
Wasatch Front NAA will not attain the standard and will be reclassified to serious status in February of 2025.
This anticipated reclassification from moderate to serious status will trigger new control strategy
requirements for major sources in the Northern Wasatch Front NAA. In particular, these requirements
include preparation and submittal to the EPA of State Implementation Plan (SIP) revisions that include
provisions to address the adoption of Reasonably Available Control Technologies (RACT) for each major
source of nitrogen oxide (NOx) and volatile organic compound (VOC) emissions within the non-attainment
area (i.e., sources that emit 50 tons/yr [tpy] or more of NOx or VOC).
Based on the facility’s potential to emit, the Utah Department of Environmental Quality’s (UDEQ) Division
of Air Quality (DAQ) has determined that the PacifiCorp Energy Gadsby Power Plant (Gadsby) meets this
50 tpy emissions threshold and is subject to the requirement to evaluate RACT. In a letter received May 31,
2023, DAQ requested that Gadsby submit an analysis that addresses RACT for all the NOx and VOC
emission units at the plant no later than January 2, 2024. PacifiCorp requested and extension to the January
2, 2024, deadline and was granted an extension to January 9, 2024. A copy of the DAQ request letter is
enclosed in Appendix A for reference.
The DAQ letter requests the following for each applicable source:
 A list of each NOx and VOCs emission units at the facility. All emission units with a potential to
emit either NOx or VOCs must be evaluated.
 A physical description of each emission unit and its operating characteristics, including but not
limited to: the size or capacity of each affected emission unit; types of fuel combusted; and the
types and quantities of materials processed or produced in each affected emission unit.
 Estimates of the potential and actual NOx and VOC emissions from each affected source and
associated supporting documentation.
 The actual proposed option NOx RACT requirement(s) or NOx RACT emissions limitation(s),
and/or the actual proposed VOC requirement(s) or VOC RACT emissions limitation(s) (as
applicable).
 Supporting documentation for the technical and economic considerations for each affected
emission unit.
 A schedule for completing implementation of the RACT requirement or RACT emissions limitation
by May of 2026, including start and completion of project and schedule for initial compliance
testing.
 Proposed testing, monitoring, recordkeeping, and reporting procedures to demonstrate
compliance with the proposed RACT requirement(s) and/or limitation(s).
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 Additional information requested by DAQ necessary for the evaluation of the RACT analyses.
1.2 Gadsby Process and Emission Unit Descriptions
Gadsby is a natural gas-fired electric generating plant consisting of three (3) steam generating boilers (Units
#1, #2 and #3) and three (3) simple-cycle combustion turbines (Units #4, #5 and #6). Fuel oil may be used
in Units #1, #2, and #3 as a back-up fuel during natural gas curtailments or for maintenance firings.
Maintenance firings may not exceed one percent (1%) of the total annual heat input to the boilers. Unit #1
is a 65 MW unit constructed in 1951, Unit #2 is an 80 MW unit constructed in 1952, and Unit #3 is a 105
MW unit constructed in 1955. Units #1 and #2 are equipped with low NOx burners and Unit #3 uses a flue-
gas recirculation (FGR) system to reduce NOx emissions.
Units #4-6 are 43.5 MW General Electric LM6000 natural gas-fueled simple cycle combustion turbine
engines that were added in 2002. The plant also has two small black start (emergency) generators (175
kW and 1,007 kW), three cooling towers for the boilers, and several small storage tanks.
The facility's operating schedule is 24 hours per day, 7 days per week, 365 days a year, however current
operation of the boilers and turbines is less than 25 percent of permitted operation. Based on potential
emissions, the facility is a major source for PM10, NOx, CO, and Greenhouse Gases for the Title V program.
The facility is also major for Nonattainment New Source Review (NNSR) for NOx and PM10. Following the
ozone reclassification to serious nonattainment, the facility will also be a major source of VOC emissions
under the Title V and NNSR programs.
1.2.1 Emission Units Evaluated
Table 1 presents the primary sources of VOC and NOx emissions at the site and includes the Emission Unit
(EU) source identification, a description, rating or capacity and the existing emission control technologies
utilized on each source.
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Table 1. NOx and VOC Emission Sources
Emissio
n Unit ID
Emission Source Capacity NOx and/or
VOC
Existing Emission
Controls
EU1 Steam Generating Unit #1 –
Natural Gas Fired Boiler
726 MMBtu/hr, 65
MW
NOx, VOC Low NOx Burners
EU2 Steam Generating Unit #2 -
Natural Gas Fired Boiler
825 MMBtu/hr, 80
MW
NOx, VOC Low NOx Burners
EU3 Steam Generating Unit #3 -
Natural Gas Fired Boiler
1,155 MMBtu/hr,
105 MW
NOx, VOC Flue Gas Recirculation
EU4 Combined Emission Group of
Steam Generating Units
(EU1-3)
NOx, VOC
EU10 Emergency Diesel Generator 280 HP NOx, VOC NA
EU11 Distillate Fuel Oil Tank 500 gallons VOC
EU12 Lube Oil Storage Tanks (2) 2 x 4,200 gallons VOC
EU13 Oil Storage Area 55-gallon drums,
300-gallon totes,
300 and 500 gallon
used oil reservoirs
VOC
EU15 Misc. Electrical Equipment
(transformer insulating oil)
VOC
EU16 Water Treatment Chemical
Tanks
VOC
EU17 Paint Storage Areas (sealed
paint containers)
VOC
EU19 Misc. Parts Painting for
Maintenance
VOC
EU20 Lube Oil Conditioners (3)975 gallons VOC
EU21 Lube Oil Reservoirs (3)2 x 2,800 gallons
1 x 3,150 gallons
VOC
EU22 Hazardous Waste Storage
Area
VOC
EU24 LM6000 Natural Gas Simple
Cycle Turbines (3)
3 x 43.5 MW NOx, VOC Water Injection, SCR, CO
Catalysts
EU25 Black Start Generator 1,350 HP NOx, VOC
EU26 Gasoline Refueling Tank 500 gallons VOC
--Emergency Diesel Generator
Day Tank
100 gallons VOC
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1.3 Facility Emissions
A summary of calendar year 2017 emissions for each unit is presented in Table 2 below. The current
potential to emit (PTE) emission rates for the Gadsby emission units are presented in Table 3. A detailed
breakout of calendar year 2017 and facility PTE emissions are provided in Appendix B.
Table 2. Gadsby 2017 NOx and VOC Emission Summary
Emission Unit
ID
Emission
Source
NOx VOC
Tons
EU1 Steam Generating Unit #1 7.5 0.4
EU2 Steam Generating Unit #2 7.7 0.5
EU3 Steam Generating Unit #3 13.2 0.8
EU10 Emergency Diesel Generator 0.3 0.0
EU11 Distillate Fuel Oil Tank --*
EU12 Lube Oil Storage Tanks (2)--*
EU13 Oil Storage Area --*
EU15 Misc. Electrical Equipment
(transformer insulating oil)
--*
EU16 Water Treatment Chemical Tanks --*
EU17 Paint Storage Areas (sealed paint
containers)
--*
EU19 Misc. Parts Painting for Maintenance --*
EU20 Lube Oil Conditioners (3)--*
EU21 Lube Oil Reservoirs (3)--*
EU22 Hazardous Waste Storage Area --*
EU24-4 Gas Turbine Unit #4 3.3 0.33
EU24-5 Gas Turbine Unit #5 3.7 0.27
EU24-6 Gas Turbine Unit #6 2.8 0.25
EU25 Black Start Generator 0.3 0.0
EU26 Gasoline Refueling Tank *
--Emergency Diesel Generator Day
Tank
--*
Total 38.8 2.6
*Emission sources are negligible sources of emissions and were not individually calculated.
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Table 3. Gadsby PTE NOx and VOC Emission Summary
Emission Unit
ID
Emission
Source
NOx VOC
Tons
EU1 Steam Generating Unit #1 784.0 17.1
EU2 Steam Generating Unit #2 893.5 19.5
EU3 Steam Generating Unit #3 801.3 27.3
EU10 Emergency Diesel Generator 0.4 0.0
EU11 Distillate Fuel Oil Tank --*
EU12 Lube Oil Storage Tanks (2)--*
EU13 Oil Storage Area --*
EU15 Misc. Electrical Equipment
(transformer insulating oil)
--*
EU16 Water Treatment Chemical Tanks --*
EU17 Paint Storage Areas (sealed paint
containers)
--*
EU19 Misc. Parts Painting for Maintenance --*
EU20 Lube Oil Conditioners (3)--*
EU21 Lube Oil Reservoirs (3)--*
EU22 Hazardous Waste Storage Area --*
EU24 Gas Turbine Units #4-6 81.0 11.3
EU25 Black Start Generator 0.9 0.0
EU26 Gasoline Refueling Tank *
--Electro-hydraulic Control Reservoirs --*
--Emergency Diesel Generator Day
Tank
--*
Total 2,561.2 75.3
*Emission sources are insignificant activities with less than one ton per year of emissions.
These sources were not individually calculated and therefore not added into total potential emissions.
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2. RACT Assessment Methodology
2.1 Top-Down RACT Review
A RACT analysis requires identification of the lowest emission limitation that an emission source is capable
of meeting by the application of a control technology that is reasonably available, considering technological
and economic feasibility. A RACT analysis must include the latest information when evaluating control
technologies. Emission control measures evaluated in a RACT analysis can range from work practices to
add-on control systems. As part of the RACT analysis, current control technologies already in use for
sources can be taken into consideration. To conduct a RACT analysis, a top-down analysis is used to rank
all control technologies. A top-down RACT analysis steps includes the following five steps:
Step 1. Identify All Reasonably Available Control Technologies
Step 2. Eliminate Technically Infeasible Control Technologies
Step 3. Rank Remaining Control Technologies Based on Capture and Control Efficiencies
Step 4. Evaluate Remaining Control Technologies on Economic, Energy, and Environmental Feasibility
Step 5. Select RACT
Step 1 – Identification of All Reasonably Available Control Technologies
The first step consists of defining the spectrum of process and/or add-on control options potentially
applicable to the subject emissions unit.
A control technology must be “available” to be considered in a RACT determination. This means that the
technology has progressed beyond the conceptual stage and pilot testing phase and must have been
demonstrated successfully on full-scale operations for a sufficient period. Theoretical, experimental, or
developing technologies are not “available” under RACT. A control technology is neither demonstrated nor
available if government subsidies are required to fund evaluations of the technology. In many cases, a
technology is not “available” for all sizes of a unit. A control technology must also be “commercially
available.” This means that the technology must be offered for sale through commercial channels with
commercial terms.
The following categories of technologies are addressed in identifying candidate control options:
 Demonstrated add-on control technologies applied to the same emissions unit at other similar source
types;
 Add-on controls not demonstrated for the source category in question but transferred from other source
categories with similar emission stream characteristics;
Combustion controls;
 Add-on control devices serving multiple emission units in parallel; and
 Equipment or work practices, especially for fugitive or area emission sources where add-on controls
are not feasible.
There is no specific methodology that is required to be used to identify all available emission control
technologies and levels for a given source or pollutant. The most comprehensive source of this information,
however, is EPA’s RACT/BACT/LAER Clearinghouse (RBLC). This searchable database of emission
control technology determinations is maintained by EPA, and as such is generally the starting point for
developing the required ranking of emission control technologies and levels.
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Step 2 – Eliminate Technically Infeasible Control Technologies
The second step is an evaluation of the technical feasibility of the identified options and to reject those that
can be demonstrated as technically infeasible based on an engineering evaluation or on chemical or
physical principles. The following criteria were considered in determining technical feasibility: previous
commercial-scale demonstrations, precedents based on issued PSD permits, state requirements for similar
sources, technology transfer, and engineering evaluations for the control devices or work practice standards
considered.
Step 3 – Rank Remaining Control Technologies Based on Capture and Control Efficiencies
The economic evaluation is carried out using procedures recommended by the EPA’s Office of Air Quality
Planning and Standards (OAQPS) Air Pollution Control Cost Manual1. The economic evaluation looks at
the annualized control cost (in dollars per ton of emissions removed) for a particular control technology or
level on the source under consideration in comparison to commonly accepted values for cost effective
emission controls established by the state regulatory agency. As noted above, this is a site-specific
evaluation and the fact that a particular technology or level of emissions control has been concluded to be
representative of RACT at another facility does not mean that the same technology or level constitutes
RACT for the existing units at Gadsby.
Step 4 – Evaluate Remaining Control Technologies on Economic, Energy, and Environmental
Feasibility
The fourth step consists of an objective evaluation of the advantages and disadvantages of each option,
including any significant or unusual impacts to other media (i.e., water, solid waste, etc.) as well as adverse
energy or environmental impacts, including emissions of toxic or hazardous air pollutants.
Step 5 – Identification of RACT
The final step in the process is to summarize the selection of RACT and propose the associated emission
limits or work practices to be incorporated into the permit plus any recommended recordkeeping and
monitoring conditions that should be incorporated into the final permit.
1 EPA,EPA Air Pollution Control Cost Manual, at Sec. 1, Ch. 2 (7th ed. 2018).
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3. Proposed RACT for Nitrogen Oxide Emissions
3.1 Natural Gas Boilers
3.1.1 NOx Formation
NOx emissions are formed in the boilers in three ways: 1) the combination of elemental nitrogen and oxygen
in the combustion air within the high temperature environment of the boiler’s combustion zone (thermal
NOx), 2) the oxidation of nitrogen contained in the fuel (fuel NOx), and 3) the reaction of molecular nitrogen
with certain free radical compounds (e.g., CN, NH2) that are typically present in the fuel-rich zones of a
combustion flame. Although natural gas contains free nitrogen, it does not contain fuel bound nitrogen, and
at typical burner conditions, the contribution of free radical-based (or “prompt”) NOx formation is relatively
small. Therefore, the most predominant formation mechanism for NOx emissions from natural gas fired
utility boilers is thermal NOx. Prompt NOx contributes slightly only in the initial stages of combustion, and
fuel NOx is only a contributor during combustion of fuel oil (natural gas is inherently low in fuel nitrogen
content). All three processes are temperature dependent – combustion temperatures below 2700ºF greatly
inhibit NOx formation.
3.1.2 Description of Existing NOx Controls
Units #1 and #2 are equipped with low NOx burners and Unit #3 uses a flue-gas recirculation (FGR) system
to reduce NOx emissions.
3.1.3 Step 1 - Available NOx Control Options
Available NOx emission controls for utility boilers include both combustion and post-combustion options
and include the following:
1. Clean burning fuels,
2. Good combustion practices,
3. Low NOx Burners (LNB),
4. Ultra-low NOx burners (ULNB),
5. External flue gas recirculation (FGR)
6. Staged Air/Fuel Combustion or Overfire Air Injection (OFA),
7. Low Excess Air Firing
8. Selective Catalytic Reduction (SCR),
9. Selective Non-Catalytic Reduction (SNCR)
3.1.3.1 Clean Burning Fuels
The Gadsby utility boilers are dual-fuel boilers. The boilers are permitted to primarily utilize pipeline quality
natural gas with fuel oil as a back-up fuel during natural gas curtailments and maintenance firings.
Maintenance firings are limited to one percent of the total annual heat input to the boilers.
3.1.3.2 Good Combustion Practices
Good combustion practices (GCP) include the proper operation of the existing equipment as follows:
1.Proper air/fuel mixing in the combustion zone;
2.High temperatures and low oxygen levels in the primary combustion zone;
3. Overall excess oxygen levels high enough to complete combustion while maximizing boiler thermal
efficiency, and
4. Sufficient residence time to complete combustion. Good combustion practices are accomplished
through boiler design as it relates to time, temperature, and turbulence, and boiler operation as it
relates to excess oxygen levels.
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3.1.3.3 Low NOx Burners
Low-NOx Burners (LNB) use advanced burner design to reduce NOx formation through the restriction of
oxygen, flame temperature, and/or residence time. There are two main types of LNB: staged fuel and staged
air burners. Staged fuel burners divide the combustion zone into two regions, limiting the amount of fuel
supplied in the first zone with the standard amount of combustion air, and then supplying the remainder of
the fuel in the second zone to combust with the un-combusted oxygen from the first zone.
Staged air burners reverse this, limiting the combustion air in the first zone then supplying the remainder of
the combustion air in the second zone to combust the remaining fuel. Staged fuel LNBs are more suited to
natural gas-fired boilers as they are designed to restrict flame temperature.
3.1.3.4 Ultra-Low NOx Burners
Ultra-Low NOx Burners (ULNB) incorporate a variety of techniques to minimize NOx formation, including
internal flue gas recirculation, steam injection, or a combination of techniques. The ULNB is designed to
recirculate hot, oxygen depleted flue gas from the flame or firebox back into the combustion zone. By doing
this, the average oxygen concentration is reduced in the flame without reducing the flame temperatures
below which is necessary for optimal combustion efficiency. Reducing oxygen concentrations in the flame
reduces the amount of both thermal and fuel NOx generated.
3.1.3.5 Flue Gas Recirculation (FGR)
Flue Gas Recirculation (FGR) recycles the flue gas back into the firebox as part of the fuel-air mixture at
the burner to help cool the burner flame. Although similar to the concept of ULNB, rather than using burner
design features to recirculate gases from within the firebox, FGR uses external ductwork to route a portion
of the exhaust stream back to the inlet side of the boiler and returns it to the boiler wind box.
3.1.3.6 Low Excess Air Firing
The presence of excessive levels of air in a boiler’s combustion zone has the potential to increase the
formation of NOx in the boiler. Excess air levels greater than 45% may increase thermal NOx formation.
Limiting excess air can be accomplished via burner design and optimized through oxygen trim controls.
3.1.3.7 Staged Air/Fuel Combustion (Over-fire Air Injection)
Over-fire air (OFA) is a combustion staging practice typically used in combination with LNB, but not with
ULNB or FGR. In OFA designs, a portion of the combustion air is injected separately from the LNBs to a
higher elevation in the firebox. This lowers the flame temperature by reducing the oxygen concentration in
the area of the firebox where the fuel is being injected. This oxygen–reduced section is followed by a second
“over-fire air” section that acts as an oxidation zone to complete combustion. NOx formation is minimized
by completing combustion in an air-lean environment.
3.1.3.8 Selective Catalytic Reduction (SCR)
SCR is a process which involves post combustion removal of NOx from the flue gas with a catalytic reactor.
In the SCR process, ammonia injected into the combustion turbine exhaust gas reacts with nitrogen oxides
and oxygen to form nitrogen and water. The SCR process converts nitrogen oxides to nitrogen and water
by the following chemical reactions:
4 NO + 4 NH3 +O2 → 4 N2 + 6 H2O (1)
6 NO + 4 NH3 → 5 N2 + 6 H2O (2)
2 NO2 + 4 NH3 + O2 → 3 N2 + 6 H2O (3)
6 NO2 + 8 NH3 → 7 N2 + 12 H2O (4)
NO + NO2 + 2 NH3 → 2 N2 + 3 H2O (5)
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The reactions take place on the surface of a catalyst. The function of the catalyst is to effectively lower the
activation energy of the NOx decomposition reactions. Technical factors related to this technology include
increased combustion zone backpressure, exhaust temperature materials limitations, catalyst
masking/blinding, reported catalyst failure due to “crumbling,” design of the NH3 injection system, and high
NH3 slip.
For most SCR catalyst formulations, the NOx reduction reactions take place within the temperature range
of 650 to 850°F. Exhaust gas temperatures greater than the upper limit (850°F) will pass the NOx and
unreacted ammonia through the catalyst. The most widely used catalysts are vanadium, platinum, titanium,
or zeolite compounds impregnated on metallic or ceramic substrates in a plate or honeycomb configuration.
The catalyst life expectancy is typically 3 to 6 years, at which time the vendor can recycle the catalyst to
minimize waste.
3.1.3.9 Selective Non-catalytic Reduction (SNCR)
Selective Non-Catalytic Reduction (SNCR) reduces NOx emissions by injecting of ammonia or urea with
proprietary chemicals into the exhaust stream without the presence of a catalyst. SNCR technology requires
gas temperatures in the range of 1,600°F to 2,100°F.
3.1.4 Step 2 - Evaluation of Technical Feasibility of Available Controls
Searches of EPA’s RBLC were carried out to identify listings containing NOx BACT, RACT or LAER
determinations for large utility boilers permitted since 2013.
The results of these RBLC searches are summarized in Appendix C. All NOx controls listed in Step 1 are
widely used and have been demonstrated to control NOx emissions from large utility boilers.
3.1.5 Step 3 - Evaluation and Ranking of Technically Feasible Controls
A review of recent permitting actions for large industrial and utility boilers with input rates greater than 250
MMBtu/hr fired only on natural gas or fuel oil yielded twenty-five results since 2013 (See Appendix C for the
full table). The lowest emission limits were for utility boilers permitted with either LNB with SCR or SCR
alone achieving 0.01 lb/MMBtu. The Big Lakes Fuel, G2G Plant was permitted for 0.006 lb/MMBtu NOx
emissions utilizing SCR only; however, the plant has not been built and demonstrated compliance with the
lower NOx emission limit and was not included in this analysis. Table 4 provides a ranking of recently
permitted technologies.
Table 4. BACT Determination Summary for NOx from Large Industrial and Utility Boilers
Control Technology Control Effectiveness
(lb NOx/MMBtu)
SCR + LNB 0.01 (12-month avg) – 0.012 (30-day rolling avg)
SCR 0.01 (1-hr, 3-hr avg) – 0.015 (1-hr)
LNB + FGR 0.011 (30-day rolling avg) – 0.05
ULNB + OFA 0.035 (30-day rolling avg)
ULNB 0.035 (annual avg)
As seen from the RBLC search, SCR and LNB as well as SCR alone has been proven to meet 0.01 lb
NOx/MMBtu. LNB paired with FGR has proven similar control effectiveness as SCR with LNB and SCR
alone. ULNBs listed with OFA or alone showed lower control effectiveness.
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While ULNB paired with SCR would be expected to be the top control option, no large boilers permitted
recently were found using both ULNB and SCR in combination, nor were any permitted with UNLB paired
with FGR. In addition, no recent large boilers were permitted with SNCR.
3.1.6 Step 4 – NOx Control Effectiveness Evaluation
3.1.6.1 Economic Impacts
An economic impact analysis was conducted to determine the cost of installing additional NOx controls on
each of the electric generating utility boilers (Units #1, #2, and #3). For the purposes of this analysis, Gadsby
looked at the installation of separate SCR or SNCR systems for each boiler, separate installations of FGR
for Units #1 and #2 upgrade of Unit #3 with LNB. Given that SCR and SNCR were not economically feasible
for Units#1 and #2, an evaluation to add ULNBs in addition to these units was not conducted, as this
technology in addition to SCR would increase retrofit costs further.
For SCR/SNCR cost estimates, methods described in EPA’s Cost Control Manual and associated
SCR/SNCR Cost Calculation Spreadsheets2 were used to estimate capital and annualized costs for
installing SCR and SNCR on each utility boiler. Due to the age of the boilers and previous retrofits to convert
the boilers from coal to natural gas, the retrofit difficulty factor was increased.
FGR3,4 and LNB5 cost estimates were based on literature and vendor estimates. Table 5 provides cost
estimates of applying additional NOx control to each of the utility boilers (Unit #1, #2, and #3). See Appendix
D for full cost estimate worksheets.
Table 5. Control Effectiveness of Technically Feasible NOx Controls for Gadsby Boilers
Unit Control
Technology
Annualized Cost
of Control Option
NOx Reduction
(TPY)
Cost Effectiveness
($/Ton)
Unit #1 SCR $1,612,455 3 $538,814
Unit #1 SNCR $512,169 1 $610,970
Unit #1 FGR $384,755 1.5 $257,534
Unit #2 SCR $1,849,461 3 $536,646
Unit #2 SNCR $911,705 2 $474,954
Unit #2 FGR $473,545 1.5 $308,297
Unit #3 SCR $2,215,180 7 $295,377
Unit #3 SNCR $633,376 2 $300,741
Unit #3 LNB $1,760,935 7.3 $241,638
3.1.6.2 Energy impacts
Energy impacts of SCR, SNCR, and LNB (for Unit #3) systems on utility boilers are minimal. Flue gas
recirculation systems reduce the peak temperature of the flame leading to a reduction in thermal NOx
emissions. Heat absorption in the radiant heat transfer surfaces of the boilers is also reduced with the
reduction of the flame temperature reducing the thermal efficiency of the boiler. In addition to the boiler
efficiency loss, FGR systems have energy costs associated with the blower fans used to circulate the air
2 EPA Air Pollution Control Cost Manual, Section 4 Chapter 1 SNCR (March 2021)2 and Chapter 2 SCR (June 2019)
https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution
3 MPR Associates, Inc., NOx Reduction Overview
4 Entropy Technology & Environmental Consultants, Inc.,IFGR Cost Effectiveness Analysis
5 NESCAUM (2008), Applicability and Feasibility of NOx, SO2, and PM Emissions Control Technologies for Industrial, Commercial,
and Institutional (ICI) Boilers
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from the flue back into the combustion chamber. Flue gas recirculation can be increased to reduce NOx
emissions from the burners at the cost of boiler efficiency, flame stability, and vibration.
3.1.6.3 Environmental Impacts
EPA and state databases did not identify SNCR being used on large industrial or utility boilers. Both SCR
and SNCR pose adverse environmental, energy, and economic impacts. SCR and SNCR processes
generate ammonia slip; ammonium chloride is formed when the ammonia reacts with hydrochloric acid
(HCl) in the flue gas. Additionally, the use of SCR and SNCR lead to the conversion of SO2 to SO3 and
formation of ammonium sulfate/sulfite particles that could have a serious impact on downstream
components.
No environmental impacts were identified for installing FGR on Units #1 and #2 or LNB on Unit #3.
3.1.7 Step 5 – Selection of RACT
Retrofitting add-on controls to any of the three boilers is unrepresentative of RACT on the basis of adverse
economic impacts. The cost effectiveness of installing SCR is estimated at between $295,377- $538,814
per ton of NOx removed for the three units. Installation of SNCR is similarly not cost effective for any of the
three boilers at between $300,741- $610,970 per ton of NOx removed. Similarly, the installation of FGR on
Units #1 and #2 (at $257,534 and $308,297 per ton of NOx removed, respectfully) or the application of LNB
on Unit #3 ($241,638 per ton of NOx removed) are equally economically infeasible.
Gadsby proposes the current NOx controls for the three utility boilers to be RACT, including the use of
natural gas and good combustion controls on all three units. Units #1 and #2 will remain equipped with
LNB and Unit #3 will remain equipped with FGR. No changes to the existing emission limits or monitoring
methods for the boilers are proposed.
3.2 Combustion Turbines
Gadsby operates three LM6000 combustion turbines (CTs), permitted as EU-24 and identified by the plant
as Units #4, #5 and #6. Each is a simple-cycle unit fired exclusively on pipeline quality natural gas.
3.2.1 NOx Formation
As described in Section 3.1.1, NOx emissions are formed in combustion sources in three ways: 1) thermal
NOx, 2) fuel NOx, and 3) prompt NOx. The thermal NOx pathway is the most predominant formation
mechanism for NOx emissions from natural gas fired combustion turbine units. The rate of formation of
thermal NOx is a function of residence time and free oxygen concentration; it increases exponentially with
increasing peak flame temperature.
“Front end” NOx control techniques are aimed at controlling thermal NOx and/or fuel NOx. The two primary
front-end combustion control types for combustion turbine systems include water or steam injection into the
combustor and specific combustor design features. The addition of an inert diluent such as water or steam
into the high temperature region of the combustor decreases NOx formation by quenching peak flame
temperature. Combustor design improvements, specifically the development of dry low-NOx (DLN)
combustors, limit peak flame temperature and excess oxygen with lean, pre-mix flames that decrease NOx
formation to levels that are equal or better than achieved via water or steam injection when burning natural
gas.
Other control methods, known as “back-end” or post combustion controls and described in greater detail in
the following subsections, remove NOx from the exhaust gas stream once it has been formed.
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3.2.2 Description of Existing NOx Controls
The three simple-cycle combustion turbine units at the Gadsby (Units #4, 5, and 6) are equipped with water
injection and selective catalytic reduction to control NOx emissions. As simple cycle units, the turbines do
not have heat recovery steam generators (HRSGs), nor any form of duct (supplemental fuel) firing.
The turbines are required to meet a NOx emission limit of 5 ppmv @ 15% O2 on a 30-day rolling average
(per turbine) and 116 ppmvd @ 15% O2 on a 4-hour rolling average per turbine. Collectively these three
units are subject to a short-term emission limit of 22.2 pounds/hour (lb/hr) @ 15% O2 based on a 30-day
rolling average (for all three turbines).
The turbines are subject to New Source Performance Standards (NSPS) Subparts A (General Provisions)
and GG (Standards of Performance for Stationary Gas Turbines).
3.2.3 Step 1 - Available NOx Control Options
Available control technologies to reduce NOx emissions from simple cycle combustion turbines include the
following:
1. Good combustion practices,
2. Dry Low NOx Combustors
3. Water or Steam Injection
4. SCR, and
5. SNCR
Each of these are discussed in the following sections.
3.2.3.1 Good Combustion Practices
Good combustion practices include only using pipeline quality natural gas as fuel, maintaining high
combustion efficiencies, maintaining proper air-to-fuel ratios, and conducting proper maintenance.
3.2.3.2 Dry Low NOx Combustors
Combustion control techniques that utilize design and/or operational features of the turbine’s combustors
which reduce NOx emissions without injecting an inert diluent (water or steam) are generically referred to
as “dry” Low NOx (DLN) measures. The design features of a DLN combustor design are vendor-specific,
but generally DLN combustors seek to reduce thermal NOx formation by controlling peak combustion
temperature, combustion zone residence time, and combustion zone free oxygen concentration.
Alternatives include combustion distribution over several burner stages and pre-mixing air and fuel prior to
injection into the combustion zone. These measures produce a lean, pre-mixed flame that burns at a lower
flame temperature and excess oxygen levels than conventional combustors.
3.2.3.3 Water or Steam Injection
Water or steam injection as a NOx control alternative was concluded to represent the Best Demonstrated
Technology (BDT) for control of NOx emissions from stationary combustion turbines when the original
NSPS for this source category was promulgated in 19776. This alternative involves the injection of water or
steam into the high temperature region of the combustor flame. Thermal NOx formation is minimized with
this alternative because peak combustion temperature, combustion zone residence time, and combustion
zone free oxygen are all reduced. Water or steam injection also serves to augment a combustion turbine’s
power output due to the additional mass of fluid it provides through the turbine section.
6 42 Fed. Reg. 53,782, 53,785 (Oct. 3, 1977).
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3.2.3.4 Selective Catalytic Reduction (SCR)
As described in Section 3.1.3.8, SCR is a process which involves post combustion removal of NOx from
the flue gas with a catalytic reactor utilizing ammonia injected into the combustion turbine exhaust gas as
a reducing agent.
For most SCR catalyst formulations, the NOx reduction reactions take place within the temperature range
of 650 to 850°F. Since simple-cycle turbines typically have exhaust gas temperatures that are higher than
the normal range for SCR catalyst effectiveness, for these units either special high-temperature catalyst
formulations must be employed, or the turbine exhaust must be cooled prior to introducing it into the SCR
reactor. The most common mechanism used to cool simple cycle turbine exhaust gas is to mix it with a
sufficient quantity of ambient air.
SCR catalyst materials lose activity over time, necessitating catalyst cleaning or replacement. In base-
loaded natural gas-fired applications, expected SCR catalyst life is within the range of 32,000 to 80,000
operating hours.7 Catalyst life is lower in simple cycle applications as frequent temperature cycling
associated with episodic use causes catalyst sintering and loss of activity.
3.2.3.5 Selective Non-Catalytic Reduction (SNCR)
Selective Non-Catalytic Reduction (SNCR) reduces NOx emissions by injecting of ammonia or urea with
proprietary chemicals into the exhaust stream without the presence of a catalyst. SNCR technology requires
gas temperatures in the range of 1,600°F to 2,100°F and is most commonly used in boilers because gas
turbines do not have exhaust temperatures in that range.
3.2.4 Step 2 - Evaluation of Technical Feasibility of Available Controls
Searches of EPA’s RBLC were carried out to identify listings containing NOx BACT or RACT determinations
for large natural gas-fired simple-cycled units (greater than 25 megawatts [MW]) permitted since 2013. The
results of these RBLC searches are summarized in Appendix C.
Among the simple-cycle unit listings, there are 58 listings in which the NOx emission control option that is
employed is described. The breakdown in emission control options used by these simple cycle units is as
follows:
• 13 list the use of SCR,
• 47 list the use of DLN combustors,
• 6 list water or steam injection (during natural gas combustion),
• 14 list natural gas or clean fuels, and
• 13 list good combustion practices.
Thus, for simple-cycle units, SCR, DLN combustors, and water or steam injection are all considered a
technically feasible option for control of NOx emissions.
SNCR is eliminated from further BACM evaluation since the technology requires temperatures of the
exhaust stream in the range of 1,600°F to 2,100°F which is well above the 825°F exhaust temperatures
output by the GE LM6000 PC turbines.
As seen by the RBLC search, DLN combustors is a widely used technology for simple-cycle turbines.
However, the simple cycle turbines at Gadsby utilize water injection to reduce NOx emissions and water
injection is not compatible with DLN burners. While DLN Combustors are technically feasible, installation
7 EPA Air Pollution Control Cost Manual, Section 4 Chapter 2 “Selective Catalytic Reduction” (June 2019)
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of DLN would require that the existing combustors be removed and DLN combustors be retrofitted. Thus,
DLN combustors will not be considered further.
Water/Steam injection is a technically feasible and a common technology in simple-cycle configurations.
The technology has not proven capable of achieving emissions as low as 5 ppmvd at 15 percent oxygen
as a standalone technology and would require a post-combustion add-on, such as SCR to further reduce
NOx emissions.
SCR is a post-combustion NOx control technology that is a proven and technically feasible technology that
is widely used in simple-cycle turbine configurations. When combined with water/steam injection or DLN
burners, it is capable of achieving the 5 ppmvd at 15 percent oxygen.
3.2.5 Step 3 - Evaluation and Ranking of Technically Feasible Controls
The most effective control technology for controlling NOx emissions from the Gadsby GE LM6000PC
turbines is water injection to reduce the amount of thermal NOx formation combined with SCR as a post-
combustion treatment. As seen from the RBLC search, water injection alone has been proven to meet 25
ppmvd at 15% oxygen alone, while SCR has been proven to meet 5 ppmvd at 15 percent oxygen (the
existing limit for the Gadsby GE LM6000PC turbines) alone. However, SCR in combination with water
injection, lower emissions have been demonstrated at other facilities for Best Available Control Technology
(BACT) and Lowest Achievable Emissions Rate (LAER) demonstrations.
3.2.6 Step 4 – NOx Control Effectiveness Evaluation
The following energy and environmental impacts associated with SCR and water injection control
technologies are outlined below.
3.2.6.1 Energy Impacts
Adverse energy impacts from SCR technology include a reduction in the electrical generating capacity of a
combustion turbine because the catalyst grid causes backpressure within the turbine and reduces its
efficiency. Similarly, employing water injection results in an energy penalty due to the loss of the power
augmentation that accompanies the use of water injection for NOx control.
3.2.6.2 Environmental Impacts
The use of SCR requires that a reducing agent (ammonia) be injected into the turbine exhaust to react with
NOx. This creates two forms of adverse environmental impacts. Ammonia that is not consumed in the SCR
system is discharged to the atmosphere as ammonia slip. The storing of the ammonia on-site is another
environmental and safety concern. Finally, the catalyst must periodically be regenerated and must be
disposed of or recycled at the end of its useful life.
Water injection utilizes water, which is a natural resource, to control emissions. There are no adverse
environmental impacts, however, associated with combustors.
3.2.7 Step 5 – Selection of RACT for Simple Cycle Combustion Turbines
A search of several databases was conducted to determine the most stringent control measures placed on
simple-cycle turbines to achieve the lowest emission NOx emission rate. From the RBLC database, as
found under Process Type 15.110 (large gas-fired simple cycle combustion turbines), the most stringent
NOx emission rate is 2.5 parts per million volume dry corrected (ppmvd). The Bay Area Air Quality
Management District’s (BAAQMD) BACT guideline lists 2.5 ppmvd at 15 percent oxygen accomplished by
using high temperature SCR and water or steam injection.
The California Air Resources Board (CARB) BACT Clearinghouse for simple-cycle gas turbines showed
several simple-cycle combustion turbines, rated between 50 and 200 MW, with the most stringent NOx
limits at 2.0 ppmvd and as high as 2.5 ppmvd. The three facilities utilize SCR or equivalent for NOx control.
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The South Coast Air Quality Management District’s (SCAQMD) determinations for LAER for major sources
and BACT for non-major sources listed one simple-cycle gas turbine BACT. The units were 190 MW with
an emission limit of 2.5 ppmvd utilizing SCR and DLN for NOx control.
The Texas Commission on Environmental Quality’s (TCEQ) current BACT requirements list gas-fired simple
cycle turbines. Control technologies listed include DLN, water or steam injection in combination with SCR
and have a minimum control efficiency of 5 to 9 ppmvd at 15 percent oxygen.
Gadsby is utilizing pipeline quality natural gas, water injection, and SCR on the simple-cycle combustion
turbines to minimize NOx emissions from the simple cycle turbines. A NOx emission limit for each turbine
of 5 ppmvd @ 15% O2 based on a 30-day rolling average under steady state operation is currently in place
for all three simple-cycle combustion turbines. This limit is supported by EPA’s RACT/BACT/LAER
Clearinghouse (RBLC). Gadsby operates continuous emissions monitoring systems (CEMs) to determine
compliance with the NOx limits. While LAER and BACT for simple-cycle combustion turbines using water
injection and SCR has been achieved in practice, between 2.0 - 2.5 ppmvd at 15 percent oxygen and has
been achieved in practice, no additional limits or emissions monitoring techniques are proposed.
3.2.8 Step 5 – Selection of RACT for Simple Cycle Combustion Turbine Startup and Shutdown
Operation of a natural gas-fired combustion turbine requires periods of startup and shutdown (SUSD).
These events are a normal part of power plant operation, but they result in NOx emission rates that are
both highly variable and typically greater than emissions during normal (steady-state) operation. NOx
emissions are often higher because the emission control systems are not fully functioning during startup
and shutdown periods. Although the standard combustors installed on these turbines do not have the same
minimum operating rate issues that DLN combustors can have, the water/steam injection system can cause
problems with flame retention if the firing rate is too low. At the same time, the catalyst in the SCR control
system will be too cold to be effective. When the surface temperature of the catalyst is low, ammonia will
not completely react with the NOx, resulting in higher NOx concentrations, excess ammonia slip, or both.
No alternative control options during SUSD are viable for Gadby turbines. Using an alternate combustor to
employ DLNBs during SUSD is physically impossible, since the combustor is integrated into the unit and
cannot be swapped out during different stages of operation.
The primary method to limit NOx emissions during SUSD is to utilize best management practices, minimize
durations of SUSDs in accordance with manufacturer’s specifications and/or limit the hours of SUSD
operation.
Best management practices during a startup include ramping up the turbine to the minimum load necessary
to achieve compliance with the applicable NOx emissions limits as quickly as possible. Ammonia injection
is initiated to the SCR system as soon as the SCR catalyst and ammonia vaporization system have reached
minimum temperature.
During a shutdown, once the turbine has been ramped down below the minimum load required to maintain
NOx emission limits, the gas turbine load should be reduced to zero as quickly as possible, consistent with
manufacturer recommendations and safe operating practices. Ammonia injection to the SCR can be
maintained as long as the catalyst and ammonia vaporization system remains above the minimum
operating temperature.
Thus, RACT for startup and shutdown is best work practices and operating the units in accordance with
manufacturer specifications and adherence to NSPS NOx emissions standard (listed in the Title V permit)
to not exceed of 116 ppmvd @ 15% oxygen on a 4-hour rolling average. Periods of SUSD shall be limited
to two hours per combustion turbine per day as defined in the Title V Permit in and moderate PM2.5 SIP. No
technologies were identified for reducing emissions from startups and shutdowns.
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3.3 Insignificant NOx Emission Sources
3.3.1 Diesel-fired Emergency Engines
Two diesel-fired emergency engines are installed at the Gadsby facility, EU#10, a 175 kW (280 hp)
generator (subject to NEHSAP ZZZZ) and EU#25, a 1,007 kW (1,350 hp) generator (subject to NSPS IIII).
Both engines supply power to the control rooms and control emergency equipment if there is a loss of line
power or other emergency.
3.3.2 NOx Formation
Similar to the formation of NOx in simple-cycle turbines described in Section 3.2.1, NOx formation in internal
combustion engines is predominantly thermal NOx which arises from the thermal dissociation and
subsequent reaction of nitrogen and oxygen molecules in the combustion air.
3.3.3 Description of Existing NOx Controls
The emergency engines currently use good combustion practices and limit operation of the units to
maintenance and required testing during non-emergency events.
3.3.4 Step 1 - Available NOx Control Options
The following control options were evaluated for controlling NOx emissions from the diesel emergency
engines:
1. Limited Hours of Operation
2. Use of a Tier Certified Engine
3. Selective Catalyst Reduction
3.3.4.1 Limited Hours of Operation
Limiting the hours of operation is an opportunity to control the emissions of all pollutants released from
emergency generator engines. Due to the designation of these equipment as emergency equipment, only
100 hours of non-emergency operation for maintenance and testing are permitted per NSPS Subpart IIII
and NESHAP ZZZZ.
3.3.4.2 Use of a Tier Certified Engine
Diesel engine manufacturers incorporate into the internal design of Tier 2 and Tier 3 engines features that
help minimize NOx emissions created during combustion. The specific features used by individual engine
manufacturers vary, but generally include adjustments to the air to fuel ratio and/or valve/ignition timing.
Such measures aim to reduce the combustion temperature and reduce the residence time at peak
temperature. The Tier 2 NOx standard for these engines is approximately 60% lower than the EPA AP-42
emission factor for engine NOx. The Tier 3 NOx standard for a 175-kW engine is over 70% lower than the
EPA AP-42 emission factor.8 The Tier 4 NOx standard for these two engines is over 95% lower than EPA
AP-42 factor. Accordingly, significant NOx improvements are available using these advanced engine
designs.
EU#10 and EU#25 were manufactured prior to the implementation of the engine Tier system, and thus the
engine design features which are available on Tier 2, 3 or 4 engines are not available on the current engines.
Compliance with any of the current Tier standards would necessitate the existing engines being replaced
with new units.
3.3.4.3 Selective Catalytic Reduction
Selective Catalytic Reduction is used in some engine applications to reduce emissions of NOx. As
described in Sections 3.1.2.8 and 3.2.3.4, SCR reduces NOx emissions from combustion sources by
8 Note, Tier 3 standards do not exist for engines greater than 560 kW.
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reacting NOx with ammonia or urea over a catalyst. The process works by ammonia (the reagent) reacting
with NOx on a catalyst bed to form water and nitrogen (N2). Most new Tier 4 engines utilize SCR for NOx
control, and it is technically feasible to retrofit an existing engine with an SCR system.
3.3.5 Step 2 - Evaluation of Technical Feasibility of Available Controls
Each of these control strategies is technically feasible and will be reviewed further.
3.3.6 Step 3 - Evaluation and Ranking of Technically Feasible Controls
The top control strategy identified for controlling NOx from emergency engines is SCR followed by replacing
the existing engines with units that meet the Tier 4 standards, followed by replacement with engines that
meet the Tier 3 and Tier 2 standards. Limiting operating hours is the least stringent of the NOx control
technologies.
3.3.7 Step 4 – NOx Control Effectiveness Evaluation
The RBLC database contains over 15 entries of BACT determinations for new or modified emergency diesel
generators between 100 hp and 2,000 hp. BACT for these engines did not require any add-on controls of
SCR; instead, BACT was deemed as compliance with NSPS Subpart IIII, good combustion and operating
practices, and/or limited operating hours were listed. For those sources with emissions limits listed in
grams/hp-hr, the majority of emission limits listed ranged from 2.98 to 4.8 grams/hp-hr; which are equivalent
to the Tier 3 and Tier 2 Standard limits. One source, Big River Steel, permitted in 2013, was permitted at
Tier 4 emission levels, however the control listed was good operating practices and compliance with NSPS
Subpart IIII. Emergency engines are not required to conform to Tier 4 standards under NSPS Subpart IIII,
so the emission limit for this entry was excluded as RACT for Gadsby’s emergency engines.
While there were no emergency engines required to install SCR as BACT, SCR is technically feasible and
was further evaluated.
3.3.7.1 Energy, Environmental, and Economic Impacts
SCRs require an operating temperature between 260°C and 540°C. Reaching these temperatures may be
difficult in routine maintenance and testing operations where the engine is typically operated at low load for
a short period of time. If the critical temperatures are not met while the engine is running, there will be no
NOx reduction benefit. To have NOx reduction benefit, the engine would need to be operated with higher
loads and for a longer period of time. This would be a challenge for PacifiCorp since each engine is limited
to less than 50 operating hours per year in non-emergency situations.
There are several downsides with using an SCR. An improperly functioning SCR system can create excess
ammonia emissions. SCR systems add significant equipment to the engine system which increases the
backpressure on the combustion system and the possibility of failures and increasing on-going maintenance
costs. In addition, cost evaluations were performed to determine the cost of control per ton of NOx removed
associated with retrofitting an SCR onto the existing emergency engines. The cost per ton of NOx removed
per engine is presented in Table 6 and in Appendix D. These values include component and installation
costs of the SCR9.
Table 6. SCR Cost Effectiveness Summary for NOx from Emergency Engines
Emergency Engine Cost Effectiveness ($/Ton)
EU#10 175 kW (280 HP)$25,240
EU#25 1,007 kW (1350 HP)$122,546
9 Cost estimates provided by Wheeler machinery in Salt Lake City.
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Based on the high economic impact associated with retrofitting SCR systems on the existing engines, the
likelihood that the engine would not be at proper operating temperature for the SCR to be effective due to
limited operating hours, and the extra maintenance and disposal costs if urea were used, SCR has been
eliminated from further consideration.
In the 2005 NSPS Subpart IIII proposal, EPA estimated the cost effectiveness of Tier 4 control strategies
for NOx to be between ~$240,000 and $400,000 per ton when applied to emergency engines with similar
power ratings.10 Therefore, Tier 4 is unrepresentative of RACT based on the unreasonable estimated
annual cost of control.
Section 8B.6 - Diesel-fired emergency generators 200-600 hp, of UDAQ’s BACT for Various Emission Units
at Stationary Sources11 references a 2010 Alternative Control Techniques Document for Stationary Diesel
Engines by Bradley Nelson, indicating that a new Tier 2 or Tier 3 engine can be purchased for $10,000 for
a 100 hp engine to $180,000 for a 1,500 hp diesel engine. The Bradley Nelson document cites a 2003
Memorandum12 that provided the engine pricing. Table 7 below provides the cost effectiveness of replacing
EU#10 with a Tier 3 engine and EU#25 with a Tier 2 engine (Tier 3 engines are not available above 750
hp). Based on the economic costs to replace the engines with higher Tiered engines, has been eliminated
from further consideration.
Table 7. Replacement Cost Effectiveness Summary for NOx from Tier 2/3 Emergency Engines
Emergency Engine Cost Effectiveness ($/Ton)
EU#10 175 kW (280 HP)$32,719
EU#25 1,007 kW (1350 HP)$121,406
3.3.8 Step 5 – Selection of RACT
Neither replacement of the existing emergency equipment, nor retrofitting these engines with new controls
are cost effective. Thus, the only feasible and cost-effective control technology for the diesel emergency
generators at the Gadsby Power Plant is a work practice requirement to adhere to GCP and to limit the
operation of the units to required testing during non-emergency situations. This control strategy is
technically feasible and will not cause any adverse energy, environmental, or economic impacts and is
considered RACT.
10 Cost per Ton for NSPS for Stationary CI ICE, Table 5, June 2004, available at https://www.epa.gov/sites/default/files/2014-
02/documents/6-9-05_cost_per_ton_ci_nsps.pdf. In Table 4, EPA provides costs for NOx adsorber technology as low as $13,500 per
ton. However, since this technology is not listed as an aftertreatment device type in use for any Tier 4 certified engine in EPA’s annual
certification database (column Q), it is presumed that Tier 4 engines that reduce emissions of NOx at this level of cost-effectiveness
when used as emergency engines are not commercially available.
11 DAQ-2018-007161 Appendix A
12 Memorandum from Joe Thompson and Andrew Stewart-AM/7 to Caroline Garber-AM/7, Diesel Engine Retrofit Cost Analysis, March
17, 2003. http://dnr.wi.gov/air/pdf/attach5_final_WI_diesel_retrofit_tech_cost_analyis.pdf
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4. Proposed RACT for Volatile Organic Compound Emissions
4.1 Natural Gas Boilers
4.1.1 VOC Formation
VOC emissions from boilers are principally unburned hydrocarbons formed as a result of incomplete fuel
combustion. Operating conditions such as low temperatures, insufficient residence time, and low oxygen
levels due to inadequate mixing, and/or a low air-to-fuel ratio in the combustion zone result in VOC
formation.
4.1.2 Description of Existing VOC Controls
All three of Gadsby’s boilers are primarily fired on pipeline quality natural gas; however, diesel fuel may be
used during periods of natural gas curtailments and for maintenance firings. Maintenance firings may not
exceed one percent (1%) of the total annual heat input to the boilers.
4.1.3 Step 1 - Available VOC Control Options
The available control techniques for VOC emissions can be sorted into three categories: pre- combustion
controls, thermal oxidation and oxidation catalysts. Four control technologies were identified for controlling
VOC emissions from boilers:
1. Clean burning fuels,
2. Good combustion practices,
3. Thermal Oxidation, and
4. Catalytic Oxidation.
4.1.3.1 Clean Burning Fuels
Pipeline-quality natural gas is a fuel predominantly comprised of methane. An odorant is added to allow
easy leak detection of the otherwise odorless gas. It is processed to meet certain specifications such that
key combustion parameters are relatively consistent throughout the United States. These parameters
include percent methane, heating value, and sulfur content.
Distillate number 2 fuel oils have negligible nitrogen and ash content and typically contain less than 0.05
percent sulfur (by volume). Unburned hydrocarbons from fuel oil are primarily comprised of aliphatic,
oxygenated, and low molecular weight aromatic compounds which exist in vapor phase at flue gas
temperatures. Other organic compounds from fuel oil combustion are emitted in a condensed phase and
are almost exclusively classified as polycyclic organic matter.
4.1.3.2 Good Combustion Practices
Combustion controls (proper design and operation) are the most typical means of controlling VOC
emissions from natural gas- and fuel oil-fired boilers. Good combustion practice includes operational and
design elements to control the amount and distribution of excess air in the flue gas. Good combustion
efficiency relies on both hardware design and operating procedures. A firebox design that provides proper
residence time, temperature, and combustion zone turbulence, in combination with proper control of air-to-
fuel ratio, is essential for low VOC emissions.
4.1.3.3 Thermal Oxidation
Thermal oxidation is the use of a secondary combustion process to burn off (oxidize) the remaining
unburned VOCs into CO2 and water vapor. This process also oxidizes CO as a secondary benefit. The
oxidation process typically requires a separate combustion chamber, burner, and heat exchanger, and in
some cases, supplemental fuel input.
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4.1.3.4 Catalytic Oxidation
Oxidation catalysts are exhaust treatment devices which enhance oxidation of VOC and CO to CO2, without
the addition of any chemical reagents, because there is sufficient O2 in the exhaust gas stream for the
oxidation reactions to proceed in the presence of the catalyst alone. Typically, catalysts to promote VOC
oxidation are comprised of precious metals such as platinum or vanadium. The quantity of catalyst required
for a given application is dependent upon the exhaust flow, temperature, and the desired removal efficiency.
The catalyst material is subject to loss of activity over time due to physical deterioration or chemical
deactivation.
4.1.4 Step 2 - Evaluation of Technical Feasibility of Available Controls
No applications of thermal oxidation have been applied to industrial boilers of the size found at Gadsby.
Thermal oxidation requires a higher concentration of VOCs and CO than is typically present in industrial
boiler exhaust. The average exhaust gas temperature of 200-250ºF would require a high degree of
supplemental heat input to be added in the thermal combustor to raise the exhaust gas above the thermal
oxidation temperature of 1500ºF. For these reasons, thermal oxidation will not be considered further as a
technically feasible control.
The most common technologies for controlling VOC emissions from large industrial boilers is good
combustion practices and using clean burning fuel. Oxidation catalysts have been employed on industrial
boilers similarly sized to Gadsby’s and are considered both commercially and technically feasible.
Therefore, pre-combustion controls and oxidation catalysts will be evaluated further as RACT.
4.1.5 Step 3 - Evaluation and Ranking of Technically Feasible Controls
The top control strategy identified for controlling VOC from large industrial boilers is oxidation catalyst.
Adherence to good combustion practices is the least stringent of the VOC control technologies.
4.1.6 Step 4 – VOC Control Effectiveness Evaluation
Searches of EPA’s RBLC were performed to identify large natural gas-fired industrial boilers permitted since
2013 with BACT, RACT or LAER determinations for VOC. The results of these RBLC searches are
summarized in Appendix C.
The search among the simple-cycle unit listings found 16 listings that identify the VOC emission control
alternative. The breakdown of these listings by emission control alternatives employed is as follows:
•2 list the use of oxidation catalyst13,
•17 list good combustion practices, and
•6 list natural gas or clean fuels.
The most stringent emission limit is the use of oxidation catalyst with good combustion practices achieving
an emission of 0.0014 lb/MMBtu. RACT for controlling VOC is being achieved on large utility and industrial
boilers using good combustion practices, the use of clean burning fuel, oxidation catalyst systems, or a
combination of the controls to achieve emission limits in the range of 0.0014 to 0.0055 lb/MMBtu VOC.
PacifiCorp is utilizing good combustion practices on each of the electric generating steam utility boilers at
the Gadsby Power Plant. Units #1, #2, and #3 currently do not have an emission limit for VOC.
13 A second facility, Gulf Coast Methanol Complex, was permitted in Louisiana to operate four 258 MMBtu/hr inline boilers with an
oxidation catalyst and emission limit of 0.002 lb VOC/MMBtu/hr; however, the facility was never built, and emission rate confirmed.
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4.1.6.1 Energy and Environmental Impacts
Oxidation catalysts have traditionally been applied to control CO emissions with them being used to control
VOC to a lesser extent. Oxidation catalysts have three potential environmental impacts.
First, although natural gas is the primary fuel used for the Gadsby boilers, the boilers are permitted to burn
fuel oil which creates SO2 when burned. A percentage of SO2 in the flue gas will oxidize to SO3 within the
oxidation catalyst which will react with moisture in the flue gas to form H2SO4. Higher operating temperature
results in higher oxidation rates of SO2 to SO 3 resulting in higher conversion of SO3 to H2SO4. The increase
in H2SO4 emission may increase PM2.5 emissions since H2SO4 typically condenses at stack exhaust
conditions to form condensable particulate matter. In addition, the precious metals which are the active
components in oxidation catalyst are subject to irreversible poisoning when exposed to sulfur compounds.
The second environmental impact is ongoing replacement of the catalyst bed after several years. The
waste catalyst will have to be disposed of in accordance with state and federal regulations regarding
normal waste disposal. In addition, the precious metals which are the active components in oxidation
catalysts are subject to irreversible poisoning when exposed to sulfur compounds resulting in a higher
frequency of replacement. Because of the precious metal content of the catalyst, the oxidation catalyst
may also be recycled to recover the precious metals.
The third potential environmental impact of using an oxidation catalyst is the oxidation of CO to CO2 which
is regulated as a greenhouse gas.
Oxidation catalysts have a VOC reduction efficiency of approximately 50 percent. Table 8 presents the
cost effectiveness of installing an oxidation catalyst on each of the electric generating utility boilers.
Calculation spreadsheets are provided in Appendix D.
Table 8. Cost Effectiveness of Oxidation Catalyst on Boilers #1-#3
Unit Annualized Cost
of Control Option
VOC Reduction
(TPY)
Cost Effectiveness
($/Ton)
Unit #1 $2,399,922 0.21 $11,428,200
Unit #2 $2,727,184 0.25 $11,131,364
Unit #3 $3,818,058 0.38 $10,047,521
4.1.7 Step 5 – Selection of RACT
PacifiCorp utilizes good combustion practices paired with clean burning natural gas as the primary fuel for
controlling VOC emissions from the electric generating utility boilers. Fuel oil is limited to maintenance
firings and natural gas curtailments and is limited to less than one percent of the plant’s annual heat input
requirement.
The economic analysis provided in Section 4.1.6 to retrofit the boilers with an oxidation catalyst shows that
this add-on control alternative is not RACT for the Gadsby utility boilers on the basis of high economic
impacts. The remaining combustion controls, good combustion and natural gas, are already in use on the
boilers and no additional controls or emission limits are proposed.
4.2 Combustion Turbines
Gadsby operates three LM6000 combustion turbines (CTs), permitted as EU-24 and identified by the plant
as Units #4, #5 and #6. Each is operated as a simple-cycle unit fired exclusively on pipeline quality natural
gas. The CTs provide primary power generation by spinning a generator directly. As simple cycle units, the
turbines are not equipped with heat recovery steam generators (HRSGs) or any form of supplemental fuel
firing.
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4.2.1 VOC Formation
As noted in Section 4.1, VOC emissions from combustion sources result from the incomplete conversion of
carbon-containing compounds to CO2 and water during fuel combustion. VOC emission rates are principally
influenced by equipment operating conditions. In combustion turbines, high VOC emissions may be the
result of lower than optimal combustion temperature, insufficient combustor residence time, and lower
operating loads.
4.2.2 Description of Existing VOC Controls
Three simple-cycle combustion turbines are operated at the Gadsby Power Plant. Each combustion turbine
is fired exclusively on pipeline-quality natural gas and equipped with water injection system, SCR, and
oxidation catalysts.
4.2.3 Step 1 - Available VOC Control Options
Available control technologies to reduce VOC emissions from the simple cycle units include:
1. Oxidation catalyst, and
2. Combustion controls/good combustion practices.
4.2.3.1 Oxidation Catalyst
As described in Section 4.1.3.4, an oxidation catalyst is a post-combustion technology that removes VOC
from the exhaust gas stream after it is formed in the combustion turbine. In the presence of a catalyst, VOC
will react with oxygen present in the turbine exhaust, converting it to carbon dioxide. The activation energy
required for the oxidation reaction to proceed is lowered in the presence of the catalyst. Technical factors
relating to this technology include the catalyst reactor design, optimum operating temperature, back
pressure loss to the system, catalyst life, and potential collateral increases in emissions of particulate matter
and sulfuric acid mist.
VOC catalytic oxidation systems operate in a relatively narrow temperature range. At lower temperatures,
VOC conversion efficiency falls off rapidly. At higher temperatures, catalyst sintering may occur, thus
causing permanent damage to the catalyst. Simple-cycle combustion turbines employing oxidation catalyst
systems typically are equipped with the means to reduce the temperature of the turbine exhaust prior to
introducing it into the catalytic reactor.
Catalyst life may vary from the manufacturer’s typical 3-year guarantee to a 5 to 6-year predicted life.
Periodic testing of catalyst material is necessary to predict annual catalyst life for a given installation to
minimize VOC emissions.
No supplementary reactant is used in conjunction with an oxidation catalyst. The performance of an
oxidation catalyst system is dependent on the specific VOC constituents present in the turbine exhaust.
4.2.3.2 Good Combustion Practices
As noted above, VOCs are formed during the combustion process as a result of incomplete combustion of
the carbon present in the fuel. The formation of VOC is limited by designing and operating the combustion
system to maximize oxidation of the fuel carbon to CO2. Good combustion practices consisting primarily of
controlled fuel/air mixing and adequate temperature and gas residence time within the turbine combustor
will minimize the formation of VOCs.
4.2.4 Step 2 - Evaluation of Technical Feasibility of Available Controls
Searches of EPA’s RBLC were performed to identify large natural gas-fired simple-cycle units permitted
since 2013 with BACT, RACT or LAER determinations for VOC. The results of these RBLC searches are
summarized in Appendix C.
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The search among the simple-cycle unit listings found 16 listings14 that identify the VOC emission control
alternative. The breakdown of these listings by emission control alternatives employed is as follows:
 6 list the use of oxidation catalyst,
 15 list good combustion practices, and
 7 list natural gas or clean fuels.
Thus, oxidation catalyst and combustor design or good combustion practices are considered technically
feasible alternatives for control of VOC emissions from natural gas-fired simple-cycle combustion turbines.
4.2.5 Step 3 - Evaluation and Ranking of Technically Feasible Controls
The hierarchy of VOC emission controls for natural gas-fired combustion turbines, is as follows:
1. Oxidation catalyst, either alone or in combination with good combustion practices, and
2. Good combustion practices alone
4.2.6 Step 4 – VOC Control Effectiveness Evaluation
Applicable RACT/BACT/LAER Clearinghouse determinations were reviewed to determine VOC emission
rates achieved in practice for other simple cycle natural gas-fired combustion turbine installations. A full
listing of these determinations is presented in Appendix C. The most stringent emissions limit for these units
is for two facilities utilizing oxidation catalyst, natural gas and good combustion practices with emission
limits of 0.7 ppmvd with a 1 hour averaging period for one and a 3-hour averaging period for the other.
Emission limits for simple cycle combustion turbines utilizing good combustion practices and/or natural gas
combustion were as low as 1.4 ppmvd on a 3-hour average.
4.2.6.1 Energy and Environmental Impacts
There are four potential environmental impacts with the use of an oxidation catalyst system. As with SCR,
an oxidation catalyst grid reduces the combustion turbine system generating capacity due to increased
turbine backpressure and reduced efficiency. This decreased output will lead to increased emissions of all
pollutants on a unit power output basis.
Second, the use of an oxidation catalyst requires the replacement of the catalyst bed after several years.
The waste catalyst has to be disposed of in accordance with state and federal regulations regarding normal
waste disposal. Because of the precious metal content of the catalyst, the oxidation catalyst may also be
recycled to recover the precious metals.
A third potential environmental impact in using an oxidation catalyst to reduce VOC emissions, is a
percentage of SO2 in the flue gas oxidizes to SO3. The higher the operating temperature, the higher the
SO2 to SO3 oxidation potential. The SO3 reacts with moisture in the flue gas to form H2SO4. The increase
in H2SO4 emissions may increase PM2.5 emissions since H2SO4 typically condenses at stack exhaust
conditions to form condensable particulate matter.
The fourth potential environmental impact of using an oxidation catalyst is the oxidation of CO can result in
increased CO2 emissions. CO2 is a regulated as a greenhouse gas which contributes to global climate
change.
Although there are environmental and energy impacts associated with the use of an oxidation catalyst
system, these impacts are not considered significant enough to preclude the use of this system for VOC
control at Gadsby. Oxidation catalyst systems are currently installed on the simple-cycle combustion
turbines (Units #4, #5, and #6) at the plant.
14 Search included natural gas fired simple cycle combustion turbines greater than 25 MW with emission limits provided in ppmvd.
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4.2.7 Step 5 – Selection of RACT
Gadsby’s most recent NSR permit contains no specific limits on VOC emissions but does set limits on CO
emissions of 10 ppmvd. Historically, CO and VOC emission rates (ppmvd) for natural gas simple cycle
turbines with oxidation catalyst systems are roughly equivalent. The average CO emission rate measured
in 2017 by the CEMS installed on the three turbines ranged from 0.004 – 0.0073 lb/MMBtu or 1.78 – 3.25
ppmvd @ 15% O2. Assuming the VOC and CO emission rates are the same, turbine VOC emissions are
currently in the range and/or a little higher than the BACT limits for oxidation catalysts in the RBLC review
that ranged from 0.7 – 2 ppmvd @ 15% O2.
During the review of Gadsby’s BACT Analysis for the 2017/2018 PM2.5 Serious SIP Evaluation, UDAQ
requested Gadsby evaluate the installation of a more efficient oxidation catalyst or upgrading the existing
catalyst to meet current efficiency ratings. PacifiCorp provided a cost analysis for the second option. By
upgrading the control efficiency of the catalyst bed and reducing the emission rate, PacifiCorp estimated a
reduction of 1.6 tons of VOC annually, with a cost effectiveness of $65,000/ton VOC removed. It is not cost
effective to upgrade the control efficiency of the current system. Gadsby concludes that the existing
controls, emission limits, and monitoring method on these units are representative of RACT for VOC.
4.3 Insignificant VOC Emission Sources
4.3.1 Diesel-fired Emergency Engines
4.3.1.1 VOC Formation
VOC emissions from engines are generated from incomplete combustion of the diesel fuel. These
emissions occur when there is a lack of available oxygen, the combustion temperature is too low, or if the
residence time in the cylinder is too short.
4.3.1.2 Description of Existing VOC Controls
Good combustion practices are currently utilized to control VOC emissions on the emergency engines.
4.3.1.3 Step 1 - Available VOC Control Options
The following control options were evaluated for controlling VOC emissions from the diesel emergency
engines:
1. Limited Hours of Operation
2. Good Combustion Practices
3. Diesel Oxidation Catalyst
4.3.1.4 Limited Hours of Operation
Limiting the hours of operation is an opportunity to control the emissions of all pollutants released from
emergency generator engines. Due to the designation of these equipment as emergency equipment, only
100 hours of operation for maintenance and testing are permitted per NSPS Subpart IIII and NESHAP
ZZZZ.
4.3.1.5 Good Combustion Practices
Good combustion practices refer to the operation of engines at high combustion efficiency which reduces
the products of incomplete combustion. The emergency generators located at the Gadsby Power Plant are
designed to achieve maximum combustion efficiency. The manufacturer has provided operation and
maintenance manuals that detail the required methods to achieve the highest levels of combustion
efficiency.
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4.3.1.6 Diesel Oxidation Catalyst
A diesel oxidation catalyst (DOC) utilizes a catalyst such as platinum or palladium to further oxidize the
engine's exhaust, which includes hydrocarbons (HC), (e.g., VOC), to carbon dioxide (CO2) and water.
4.3.1.7 Step 2 - Evaluation of Technical Feasibility of Available Controls
The control technologies identified in Step 1 are technically feasible.
4.3.1.8 Step 3 - Evaluation and Ranking of Technically Feasible Controls
Use of a diesel oxidation catalyst can result in approximately 90 percent reduction in HC/VOC emissions.15
Combustion controls have been demonstrated to reduce VOC emissions from CI engines by approximately
50%.
4.3.1.9 Step 4 – VOC Control Effectiveness Evaluation
EPA’s RBLC was searched to identify facilities with emergency diesel engines between 100 and 2,000 hp
utilizing VOC controls. Of the twenty-nine engines identified, the database did not contain data suggesting
that add on controls like DOC were required. Of these units, the control method required was determined
to be good combustion practices, compliance with NSPS IIII, and limited operating hours.
The cost effectiveness of installing and operating standard diesel oxidation catalysts on each of the
proposed engines was evaluated and presented in Table 9. The cost effectiveness of an oxidation catalyst
includes general maintenance, assuming proper operation of the system. If poisoning of the catalyst occurs,
replacement of the catalyst will occur more frequently which increases the cost of control. In addition, engine
valves/heads beyond the typical maintenance schedule will add to the maintenance costs.
Table 9. Cost Effectiveness of Diesel Oxidation Catalyst on Emergency Diesel Engines
Unit Cost Effectiveness ($/Ton)
EU#10 175 kW (280 HP)$136,419
EU#25 1,007 kW (1350 HP)$1,569,989
Based on the economic impact presented in Table 9, DOCs are not cost effective for the emergency
generators at the Gadsby Power Plant and have been eliminated from further consideration.
4.3.1.10 Step 5 – Selection of RACT
While adding a DOC would be the most stringent control for VOC on the two emergency generator engines,
these additional controls would not be cost effective. A search of similar engines in EPA’s RBLC did not
indicate that any determinations had been made that DOC was considered BACT for these engines that
operate so infrequently and typically for short periods of time for maintenance and testing purposes. Good
combustion practices are currently utilized on emergency generators at the Gadsby Power Plant and is
considered RACT. These engines are maintained in accordance with manufacturer recommendations.
Maintenance activities performed on the generators are subject to recordkeeping, reporting, and notification
requirements defined in NESHAP Subpart ZZZZ and NSPS IIII. No additional limits or emissions monitoring
techniques are being proposed.
4.3.2 Storage Tanks
Storage tanks are used at the Gadsby Power Plant to store distillate fuel, lube oils, water treatment
chemicals, and water treatment sludge. Used and new oil is also stored in 55-gallon drums, 300-gallon
15 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)
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totes and 300- and 500-gallon mobile used oil reservoirs. Emissions from storage tanks result from
displacement of headspace vapor during filling operations (working losses) in the case of fixed roof or
internal floating roof tanks, and from diurnal temperature and heating variations (breathing losses).
4.3.2.1 VOC Formation/ Description of Existing VOC Controls
Emissions from storage tanks generally include VOCs; however, tanks that store chemicals that are not
hydrocarbon based (water treatment chemicals and sludge in the case for Gadsby Power Plant) are
assumed to have negligible VOC emissions. Water treatment chemicals utilized at the Gadsby plant consist
of aluminum sulfate, sodium hypochlorite, EDTA, and sulfuric acid. Typically, lower vapor pressure liquids
such as lube oils, heating oils, diesel or kerosene are stored in fixed roof tanks; crude oils and lighter
products such as gasoline are stored in floating roof tanks. Filling losses for fixed roof tanks constitute 80-
90% of the total emissions.
4.3.2.1.1 Step 1 - Available VOC Control Options
The available control technologies for tanks storing organic liquids include control equipment designed to
minimize leakage from tanks, air pollution control equipment, less polluting processes, and combinations
of each. Control options that were identified include:
1. A fixed roof (commonly used for smaller tanks or containing low vapor pressure materials),
2. A fixed roof with vapor collection by a closed vent system routed to a control device,
3. Fixed roof in combination with an internal floating roof,
4. Fixed roof in combination with an internal roof and with a vapor collection system in a closed vent
system routed to a control device, and
5. An external floating roof.
4.3.3 Step 2 - Evaluation of Technical Feasibility of Available Controls
External, internal or domed floating roof tanks are not utilized at the Gadsby Power Plant because the
products stored at the facility (distillate fuel and lube oil) are less volatile than typical products (such as
gasoline) that are stored in these types of tanks. The fuels being stored at the Gadsby Plant have vapor
pressures <0.02 psia. Thus, this option and any additional control options associated with external or domes
floating roof tanks have been eliminated from further consideration.
4.3.3.1 Step 3 - Evaluation and Ranking of Technically Feasible Controls
The remaining control options are listed in order of control effectiveness:
1. Fixed roof, and
2. Fixed roof with vapor collection by a closed vent system routed to a control device.
4.3.3.2 Step 4 – VOC Control Effectiveness Evaluation
Routing vapors by a closed vent system routed to a control device is between 95-99% effective in reducing
VOC emissions from storage tanks. However, the cost of a thermal oxidizer or carbon absorber would result
in adverse energy and environmental impacts due to the auxiliary fuels needs for a thermal oxidizer and
the additional combustion emissions (NOx, SO2, PM2.5, and VOC) that would result from a thermal oxidizer.
If activated carbon were used, a solid waste is generated that will need to be disposed of in accordance
with applicable regulations.
The cost of a vapor control system is a function of the vapor flow rate to the system. The flow rate is
controlled by the rate at which liquids are pumped into the tank. No facility was identified as using a vapor
control system for the size of tanks that are present Gadsby. Thus, the installation of a vapor control device
is determined to be not economically feasible and is not RACT for the tanks at Gadsby.
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4.3.3.3 Step 5 – Selection of RACT
VOC emissions from the storage tanks occur as a result of displacement of headspace during filling
operations and to a lesser degree due to temperature variations and solar heating cycles. Due to the nature
of the products being stored (distillate fuel and lube oil), the Gadsby Power Plant utilizes fixed roof tanks.
The Gadsby Power Plant has nine tanks permitted – a 500-gallon diesel tank, two 4,200-gallon lube oil
tanks, three 975-gallon lube oil conditioner tanks, two 2,800 lube oil reservoirs, and one 3,150 lube oil
reservoir. Gadsby also has an oil storage area permitted that stores new and used oil in 55-gallon drums,
300-gallon totes and 300- and 500-gallon mobile used oil reservoirs. Emission from these tanks, totes and
reservoirs are estimated to be less than 5 pounds per year.
No economically viable options exist to control emissions from tanks, totes and drums permitted at the
Gadsby Power Plant due to the size and low volatility of the products being stored. The use of fixed roof
tanks for the diesel and lube oil represents RACT.
No more stringent control measures were identified than the use of fixed roof tanks, limiting tank turnovers,
for the storage of low volatile products such as distillate fuel oil and lube oil. No additional limits or emissions
monitoring techniques are being proposed.
4.3.4 Miscellaneous Painting Operations
Process equipment parts at Gadsby periodically require painting as preventative maintenance. In addition,
the Gadsby Plant has various paint storage areas where sealed paint containers are kept. VOC emissions
from the maintenance painting accounts for less than one ton per year.
4.3.4.1 Description of Existing VOC Controls
Gadsby uses low VOC compliant coatings, high transfer efficiency application equipment, and good
housekeeping when painting miscellaneous parts.
4.3.4.2 Step 1 - Available VOC Control Options
Painting activities are classified into two categories; enclosed painting occurs in a paint booth and outdoor
painting occurs in unconfined areas.
Control technologies for painting in enclosed or confined quarters such as paint booths, include:
1. Use of low VOC compliant coatings,
2. Use of high transfer efficiency application equipment,
3. Collecting and venting VOCs to an add-on control device such as a thermal oxidizer.
Thermal oxidizer, or thermal incinerator, uses a burner to destroy VOC emissions prior to release to the
atmosphere through a stack. This technology includes preheating the incoming air stream to obtain
additional fuel efficiencies. Time, temperature, turbulence (for mixing) and the amount of oxygen affect the
rate and efficiency of the combustion process.
For outdoor (unconfined) painting, use of low VOC compliant coatings is the only control method. Other
control techniques utilize good housekeeping practices for spills as well as storing coatings, solvents, and
waste products in closed containers.
4.3.4.3 Step 2 - Evaluation of Technical Feasibility of Available Controls
Collecting VOCs and venting them to a control device, such as a thermal oxidation unit, is typically reserved
for large painting operations with moderate-to-high VOC loadings and is not appropriate for maintenance
painting activities that occur infrequently outside with total VOC emissions of less than one ton per year.
Thus, the application of this control technology to outside painting operations is not technically feasible.
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All other control technologies (low VOC compliant coatings, use of high transfer efficiency application
equipment, and good housekeeping practices) are technically feasible.
4.3.4.4 Step 3 - Evaluation and Ranking of Technically Feasible Controls
All remaining control technologies from Step 2 are equally effective.
4.3.4.5 Step 4 – VOC Control Effectiveness Evaluation
Using low VOC compliant coatings along with high transfer efficiency application equipment, and good
housekeeping are considered RACT for maintenance painting. The type of paints utilized at Gadsby include
high build polyurethane products which are low VOC compliant coatings. The frequency of the painting
occurs on average of 80 hours per year using approximately 200 gallons per year. VOC emissions from
miscellaneous parts painting is less than one ton per year.
Utah Administrative Code R307-350 is applicable to the painting operations at Gadsby. The products used
meet the VOC content limits as specified in R307-350-5.
There are no anticipated energy, environmental or economic impacts associated with the remaining control
technologies identified for painting operations at Gadsby.
4.3.4.6 Step 5 – Selection of RACT
Gadsby uses low VOC compliant coatings, high transfer efficiency application equipment, and good
housekeeping when painting miscellaneous parts. As previously indicated these controls are deemed
RACT for the small painting operations that Gadsby performs. No additional limits or emissions monitoring
techniques are being proposed.
4.3.5 Gasoline Refueling
The Gadsby Power Plant operates one gasoline fueling station with one 500 gallon above ground gasoline
tank. Less than 10,000 gallons is pumped per year from the fueling station.
4.3.5.1 VOC Formation
Gasoline fueling can emit VOC and HAP emissions during loading of the storage tank and refilling the
vehicle’s fuel tank. The displaced air volume within each of the tanks is laden with VOC and HAP emissions
that are vented to the atmosphere. Given the small quantity of fuel throughput each year, VOC emissions
are estimated less than 0.1 tpy.
4.3.5.2 Description of Existing VOC Controls
The 500 gallon above ground storage tank is filled via submerged fill. Stage II vapor recovery is employed
for to collect VOC during dispensing of gasoline to vehicles.
4.3.5.3 Step 1 - Available VOC Control Options
Control options for gasoline tank filling and vehicle fuel tank filling include the following:
1. Stage I Vapor Recovery (refueling)
2. Stage II Vapor Recovery (refueling)
3. Submerged Fill (gasoline tank)
4.3.5.3.1 Stage I Vapor Recovery (refueling)
Stage I vapor recovery consists of a vapor capture line that connects to the tanker truck delivering fuel to a
storage vessel. This control strategy prevents vapors from being emitted to the atmosphere by recycling
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the vapors from the tanker truck or storage vessel, whichever is being loaded, into the other, which is being
emptied. This control strategy is common practice in gasoline fueling operations.16
4.3.5.3.2 Stage II Vapor Recovery (refueling)
Stage II vapor recovery consist of a vapor capture line for vehicle fuel tanks, this involves a special vapor
capture fill nozzle that allows VOC emission to enter the storage vessel as they are expelled from the
vehicle’s fuel tank.
4.3.5.3.3 Submerged Fill (gasoline tank)
Submerged loading occurs when a tank is filled using a line that is nearly or completely submerged below
the surface of the liquid material being loaded. There are two styles of submerged loading: fill pipe method
and bottom loading method.
In the fill pipe method, like with splash loading, a fill pipe is lowered into the tank and materials flow through.
However, in submerged loading the fill pipe extends almost to the bottom of the cargo tank to minimize any
splash and resulting vapors from turbulence. The bottom loading method uses a fill pipe permanently affixed
to the cargo tank’s bottom to eliminate splash as materials are loaded.
Because a submerged fill pipe is below the liquid surface level, liquid turbulence is significantly controlled,
and a lower quantity of vapors is produced.
4.3.5.4 Steps 2, 3 and 4 - Evaluation of Technical Feasibility of Available Controls
UDAQ’s BACT for Various Emission Units at Stationary Sources states that submerged filling is
economically and technically feasible and results in 30% control efficiency during loading.
Stage I recovery systems are both economically and technically feasible to implement for controlling VOC
emissions from gasoline fueling operations and result in at least 70% control efficiency.
Stage II Vapor recovery is not required by any federal regulations and given the small quantity of
emissions from this source; the assumption is that it is too costly to implement a stage II vapor recovery
system.
4.3.5.5 Step 5 – Selection of RACT
The addition of Stage 1 recovery has been deemed by UDAQ as BACT for small sources. Stage 1 recovery
results in 40% more control submerged filling provides. Given that emissions from this source are
approximately 100 pounds VOC per year and converting to Stage 1 recovery would reduce VOC emissions
only by 40 pounds per year, Gadsby concludes that current operations of submerged fill and Stage II vapor
recovery are RACT for this source.
16 Section 13B of UDAQs BACT for Various Emission Units at Stationary Sources DAQ-2018-007161
Reasonable Available Control Technology
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Appendix A – DAQ Request Letter
State of Utah
SPENCERJ. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor
Department of
Environmental Quality
Kimberly D. Shelley
Exeantivb Director
DTVISION OF AIRQUALITY
Bryce C. Bird
Director
DAQP1042-23
Ill4ay 31,2023
Brett Shakespear
Pacificorp Energy Gadsby Power Plant
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
Brett. Shakespear@pacifi corp. com
Dear Mr. Shakespear:
RE: Serious OzoneNonattainment Area Designation - Potential Impact to Pacificorp Energy
Gadsby Power Plant
The Division of Air Quality (DAQ) has identified your facility as having the potential to become a
majot stationary source located in the Ozone Nonattainment Area (NAA) in the Wasatch Front.
DAQ anticipates that the Environmental Protection Agency (EPA) will redesignate the Northern
Wasatch Front ozone NAA to serious classification in February of 2025. A seriousWasatch Front ozone NAA to serious classiflcation in February of 2025. A serious nonattai
classification will trigger requirements for major stationary sources and new thresholds for
stationary sources that will potentially apply to your facility.
This letter provides a background of the requirements for ozone nonattainment areas, a
of the requirements that will apply to major stationary sources in or impacting these areas,
upcoming next steps. Action will be required from Pacificorp Energy Gadsby Power
detailed in the'oNext Steps and RACT Requirements" section of this letter.
nt, as
Background
On August 3,2018, EPA designated the Northern Wasatch Front as marginal nonattainment for
the 2015 eight-hour ozone standard. The Northern Wasatch FrontNAA includes all or part of Salt
Lake, Davis, Weber, and Tooele counties.
195 North 1950 West . Salt t.ake City, UT
Mailing Address: P.O. Box 144820 . Salt Lake City, UT 841 14-4820
Telephone [phone] . Fax [phone]. T.D.D. [phone]
w.deq.utah.gov
Printed on 100% recycled paper
ajor
DAQP-042-23
Page2
The Northern Wasatch Front was required to attain the ozone standard by August 3,2021, for
marginal classification. However, the Northern Wasatch Front NAA did not attain the ozone
standard by the attainment date and was reclassified to moderate status on Novemb et 7 , 2022. The
Northern Wasatch Front NAA is required to attain the ozone standard by August 3,2024, for
moderate classification based on data fuom2021,2022, and2023. Recent monitoring data
indicates the Northern Wasatch Front NAA will not attainthe standard and will be reclassified to
serious status in February of 2025.
This anticipated reclassification from moderate to serious status will trigger new control strategy
requirements for major sources in the Northern Wasatch Front NAA. Specifically, the Ozone
Irn-plementation RulL in 83 FR 62998 requires the State Implementation Plan (SIP) to include
Reasonably Available Control Technologies (RACT) for all major stationary sources in
nonattainment areas classified as moderate or higher. The requirements for RACT in a serious
ozone nonattainment area are found in Clean Air Act (CAA) Section 182(c). A major stationary
source in a serious ozone nonattainment area is defined as any stationary source that emits or has
the potential to emit 50 tons per year or more of nitrogen oxides (NO^) or volatile organic
compounds (VOCs).
The exact dates for the submittal of SIP RACT and RACT implementation will be announced
when EPA publishes the notice of reclassification in the federal register. However, based on the
general timeline provided in the Ozone lmplementation Rule, DAQ anticipates the tbllowing
schedule:
1) Reclassification to seiious February of 2025.
2) Serious SIP is due to EPA January l,2\26,within 12 months from the effective date of
reclassification.
3) RACT measures will be required to be implemented as expeditiously as practicable but
likelybefore May of 2026.
Next Steps and RACT Requirements
DAQ has identified your facility as having the potential to emit 50 tons per year or more of NO*
and/or VOCs. After the Northem Wasatch Front NAA is reclassified to serious status in February
of 2025,your facility will be considered a major stationary source. As a major stationary source,
you will Le requiredto submit a RACT analysis for the emission unit(s) at your facility, as well as
apply for a Title V permit within 12 months of becoming a Title V source.
To meet the RACT requirements of the Ozone tmplementation Rule, DAQ is soliciting RACT
analyses for the .ont ol of NO* and VOC emissions from all major stationary sources or potential
major stationary sources located in or impacting the Northern Wasatch Front NAA. DAQ will
review the RACT analyses submitted and make a RACT determination for each affected emission
unit.
DAQP-042-23
Page 3
The requirements for RACT in CAA Section 182(c) and (f) are specific to major stationary
sources of VOCs and NO* in a nonattainment area. Major stationary sources located outside a
nonattainment area but impacting the nonattainment area are required to submit a RACT analysis
under the provisions of CAA 172(c)(6) Other Measures. This provision states that other measures
may be implemented if attainment cannot be demonstrated by the applicable attainment date with
the controls implemented within the nonattainment area. DAQ is soliciting RACT analyses from
sources with the potential to impact the Wasatch Front NAA; however, RACT will only be
required for these sources ifnecessary.
DAQ has identified your facility as having the potential to become a major stationary sourc,e
located in or impacting the Northern Wasatch Front NAA. Due to the location and potentiaf to
emit from your facility, DAQ is requesting either:
1) a RACT analysis for the emission units at'your facility; or
2) a Notice of Intent (NOD application to lower the potential to emit from your facility to
below 50 tons psr year of NO* and VOCs.
If choosing to lower the potential to emit from your facility, please submit a NOI appllcation
to DAQ by July 31,2023. Otherwise, please submit a RACT analysis to DAQ by Janupry 2,
2024. The RACT submittal requirements are listed in the attachment to this letter. NpI
applications and RACT analyses shall be submitted to Ana Williams at
anarvilliams@ utah.gov.
Inventory and Modeling Data
The SIP process requires that DAQ perform a modeling demonstration to evaluate attainmdnt. As
part of this evaluation, DAQ will model baseline emissions based on the 2017 emissions inventory
and projected emissions for future years.
DAQ anticipates preparing the modeling emissions inventory for point sources in early 20?A.This
emission inventory data will incorporate RACT to existing equipment and any anticipated changes
to the facility. DAQ will work with major stationary sources to prepare the emission inventory
data for each affected facility that will be included in the model.
DAQ will contact major sources in late 2023 to develop emissions inventory data. No action is
required at this time.
DAQP-042-23
Page 4
Additional Information
Additional information regarding major source requironents and timelines can be found here:
://deo.utah.sov/ai itv/moderate-zone-stat ntation
sip-development
You can also sign up for the ozone SIP email list on the website above.
Informational Meeting
DAQ invites you to attend an informational meeting June 13r2023rfrom 1:00pm-2:00pm. The
meeting will be held at the DAe offices in the Multi-Agency State office Building first floor
Boardroom 1015 with an option to attend virlually. You will receive an email with ameeting
invitation in the coming weeks.
At this meeting DAe staff will provide information regarding reguiatory timelin_es and the actions
DAe will be obligated to take to meet the new requirernents for a serious classification.
We will provide an opportunity during the meeting for you to ask questions. You may also submit
written questions to DAQ after the meeting.
Please contact Ana Williams at [phone] with any questions.
Sincerely,
-4r*LlU
Bryce C. Btud
Director
BCB:AW:my
DAQP-042-23
Page 5
ATTACHMENT - RACT Submittal Requirements
The RACT proposals to be submitted to DAQ must include the following:
1) A list of each NO* and VOCs emission unit at the facility. Al1 emission units with a
potential to emit either NO* or VOCs must be evaluated.
2) A physical description of each emission unit and its operating characteristics, including but
not limited to: the size or capacity of each affected emission unit; types of fuel combusted;
the types and quantities of materials processed or produced in each affected emission unit.
3) Estimates of the potential and actual NO^ and VOC emissions from each affected slurce,
and associated supporting documentation.
4) The actual proposed alternative NO* RACT requirement(s) or NO* RACT emissionb
limitation(s), and/or the actual proposed VOC requirement(s) or VOC RACT emissions
limitation(s) (as applicable).
5) Supporting documentation for the technical and economic considerations for each affected
emission unit.
6) A schedule for completing implementation of the RACT requirement or RACT emissions
limitation by May of 2026, including start and completion of project and schedule for
initial compliance testing.
7) Proposed testing, monitoring, recordkeeping, and reporting procedures to demonstrate
compliance with the proposed RACT requirement(s) and/or limitation(s).
8) Additional information requested by DAQ necessary for the evaluation of the neCf
analyses.
RACT analyses due to DAO by Januarv 2.2024.
Reasonable Available Control Technology
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Appendix B – 2017 Emission Inventory
and Facility PTE
aecom.com
GADSBY EMISSIONS SUMMARY
For Calendar Year:2017
Emission State PM10 PM2.5 SO2 NOX NH3 VOC CO
Unit ID #ID Description of Emission Unit (tons/yr)(tons/yr)(tons/yr)(tons/yr)(tons/yr)(tons/yr)(tons/yr)
01 4025 Steam generating unit #1 (primary fuel, natural gas)0.58 0.6 0.0 7.5 0.2 0.4 7.3
2 9143 Steam generating unit #2 (primary fuel, natural gas)0.68 0.7 0.1 7.7 0.3 0.5 13.3
3 9144 Steam generating unit #3 (primary fuel, natural gas)1.05 1.0 0.1 13.2 0.4 0.8 4.3
4 174520 Gas turbine Unit # 4 1.05 1.1 0.09 3.3 1.5 0.33 0.8
5 174521 Gas turbine Unit # 5 0.84 0.8 0.08 3.70 1.20 0.27 0.5
6 174522 Gas turbine Unit # 6 0.80 0.8 0.07 2.78 1.09 0.25 0.9
7 13689 Circulating water cooling tower for Unit #1 1.02 0.0 -----
8 13690 Circulating water cooling tower for Unit #2 0.91 0.0 -----
9 13691 Circulating water cooling tower for Unit #3 1.21 0.0 -----
10 13692 Emergency diesel generator for Unit #1 0.02 0.0 0.0 0.3 -0.0 0.1
25 176981 Black Start Generator 0.01 0.0 0.0 0.3 -0.0 0.1
Total 8.2 5.0 0.5 38.8 4.7 2.6 27.1
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/Summary
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby plant Type of Emission: Point source
Emission Unit:Steam generating unit #1 (primary fuel, natural gas)Type of Emission Unit: Natural gas fired utility boiler
ID # :01 SCC: 1-01-006-04
UDAQ ID # :4025
Year:2017
Emissions Summary Filterable Condensable
(tons/yr)(tons/yr)(tons/yr)
PM 0.58 0.14 0.43
PM10 0.58 0.14 0.43
PM2.5 0.58 0.14 0.43
SO2 0.05
NOX 7.47
NH3 0.24
VOC 0.42
CO 7.26
Pollutant Emission Factor or Equation Value Filterable Condensable Reference
PM 7.6 lb/mmcf*7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-98
PM10 7.6 lb/mmcf*7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-98
PM2.5 7.6 lb/mmcf*7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-99
SO2 0.629 lb/mmcf 0.0006 lbmmBtu Average value from CEMS
NOX 97.911 lb/mmcf 0.093 lbmmBtu Average value from CEMS
NH3 3.200 lb/mmcf 3.200 lb/mmcf EPA Ammonia Factors
VOC 5.5 lb/mmcf 5.5 lb/mmcf AP-42 Table 1.4-2, 3-98
CO 95.169 lb/mmcf 0.090 lbmmBtu Average value from CEMS
Production Data
Natural gas consumption, mmcf/yr 152.55 mmcf/yr EIA-767
Heating value of fuel, Btu/ft3 1,044.6 Btu/ft3 EIA-767
Heat Input 160,607 mmBtu/yr Annual average CEM value
Hours of operation, hr/yr 585.4 hr/yr Actual hours of operation
NOx control through Low-NOx burners 70 %Estimate from design data
Equations
Mass emissions = (emission factor) * (gas consumption) * (conversion factors)
Example:
Tons CO/yr = (A lb/mmcf) * (B mmcf/yr) * [(C mmBtu/mmcf) / (1000 mmBtu/mmcf)] * (ton/2000 lb)
*Emission factor includes both the filterable and condensable portions of the particulate emissions from AP-42 Table 1.4-2 dated 7/98.
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/1-steam
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby plant Type of Emission: Point source
Emission Unit:Steam generating unit #2 (primary fuel, natural gas)Type of Emission Unit: Natural gas fired utility boiler
ID # :2 SCC: 1-01-006-04
UDAQ ID # :9143
Year:2017
Emissions Summary Filterable Condensable
(tons/yr)(tons/yr)(tons/yr)
PM 0.68 0.17 0.51
PM10 0.68 0.17 0.51
PM2.5 0.68 0.17 0.51
SO2 0.06
NOX 7.68
NH3 0.28
VOC 0.49
CO 13.25
Pollutant Emission Factor or Equation Value Filterable Condensable Reference
PM 7.6 lb/mmcf 7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-98
PM10 7.6 lb/mmcf 7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-98
PM2.5 7.6 lb/mmcf 7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-98
SO2 0.641 lb/mmcf 0.0006 lbmmBtu Average value from CEMS
NOX 86.316 lb/mmcf 0.082 lbmmBtu Average value from CEMS
NH3 3.200 lb/mmcf 3.200 lb/mmcf EPA Ammonia Factors
VOC 5.5 lb/mmcf 5.5 lb/mmcf AP-42 Table 1.4-2, 3-98
CO 148.998 lb/mmcf 0.142 lbmmBtu Average value from CEMS
Production Data
Natural gas consumption, mmcf/yr 177.91 mmcf/yr EIA-767
Heating value of fuel, Btu/ft3 1,044.8 Btu/ft3 EIA-767
Heat Input 187,275 mmBtu/yr Annual average CEM value
Hours of operation, hr/yr 669.6 hr/yr Actual hours of operation
NOx control through Low-NOx burners 70 %Estimate from design data
Equations
Mass emissions = (emission factor) * (gas consumption) * (conversion factors)
Example:
Tons CO/yr = (A lb/mmcf) * (B mmcf/yr) * [(C mmBtu/mmcf) / (1000 mmBtu/mmcf)] * (ton/2000 lb)
*Emission factor includes both the filterable and condensable portions of the particulate emissions from AP-42 Table 1.4-2 dated 7/98.
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/2-steam
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby plant Type of Emission: Point source
Emission Unit:Steam generating unit #3 (primary fuel, natural gas)Type of Emission Unit: Natural gas fired utility boiler
ID # :3 SCC: 1-01-006-04
UDAQ ID # :9144
Year:2017
Emissions Summary Filterable Condensable
(tons/yr)(tons/yr)(tons/yr)
PM 1.05 0.26 0.79
PM10 1.05 0.26 0.79
PM2.5 1.05 0.26 0.79
SO2 0.09
NOX 13.25
NH3 0.44
VOC 0.76
CO 4.26
Pollutant Emission Factor or Equation Value Filterable Condensable Reference
PM 7.6 lb/mmcf 7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-98
PM10 7.6 lb/mmcf 7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-98
PM2.5 7.6 lb/mmcf 7.6 lb/mmcf 1.9 lb/mmcf 5.7 lb/mmcf AP-42 Table 1.4-2, 3-98
SO2 0.630 lb/mmcf 0.0006 lbmmBtu Average value from CEMS
NOX 95.887 lb/mmcf 0.091 lbmmBtu Average value from CEMS
NH3 3.200 lb/mmcf 3.200 lb/mmcf EPA Ammonia Factors
VOC 5.5 lb/mmcf 5.5 lb/mmcf AP-42 Table 1.4-2, 3-98
CO 30.855 lb/mmcf 0.029 lbmmBtu Average value from CEMS
Production Data
Natural gas consumption, mmcf/yr 276.29 mmcf/yr EIA-767
Heating value of fuel, Btu/ft3 1,043.7 Btu/ft3 EIA-767
Heat Input 291,131 mmBtu/yr Annual average CEM value
Summer hours (Mar. thru Oct.) of operation, hr/yr 798.8 hr/yr Actual hours of operation
Winter hours (Nov. thru Feb.) of operation, hr/yr 0.0 hr/yr Actual hours of operation
Equations
Mass emissions = (emission factor) * (gas consumption) * (conversion factors)
Example:
Tons CO/yr = (A lb/mmcf) * (B mmcf/yr) * [(C mmBtu/mmcf) / (1000 mmBtu/mmcf)] * (ton/2000 lb)
*Emission factor includes both the filterable and condensable portions of the particulate emissions from AP-42 Table 1.4-2 dated 7/98.
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/3-steam
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby Plant Type of Emission: Point source
Emission Unit:Gas Turbine Unit #4 (primary fuel, natural gas)Type of Emission Unit: Natural gas fired utility turbine
ID # :4 SCC: 2-01-002-01
UDAQ ID # :174520
Year:2017
Emissions Summary Filterable Condensable
(tons/yr)(tons/yr)(tons/yr)
PM 1.05 0.30 0.75
PM10 1.05 0.30 0.75
PM2.5 1.05 0.30 0.75
SO2 0.09
NOX 3.35
NH3 1.45
VOC 0.33
CO 0.80
Pollutant Emission Factor or Equation Value Filterable Condensable Reference
PM 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
PM10 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
PM2.5 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
SO2 0.589 lb/mmcf 0.0006 lbmmBtu Average value from CEMS
NOX 20.961 lb/mmcf 0.021 lbmmBtu Average value from CEMS
NH3 0.0091 lb/mmBtu 9.100 lb/mmcf EPA Ammonia Factors
VOC 0.0021 lb/mmBtu 0.0021 lb/mmBtu AP-42 Table 3.1-2a, 4/00
CO 0.005 lb/mmBtu 0.005 lbmmBtu Average value from CEMS
Production Data
Natural gas consumption, mmcf/yr 319.248 mmcf/yr EIA-767
Heating value of fuel, Btu/ft3 1,044.4 Btu/ft3 EIA-767
Heat Input 318,662.4 mmBtu/yr Annual average CEM value
Hours of operation, hr/yr 1,455.9 hr/yr Actual hours of operation
Equations
Mass emissions = (emission factor) * (heat input) * (conversion factors)
Example:
Tons SO2/yr = (A lb/mmBtu) * (B mmBtu/yr) * (ton/2000 lb)
*Emission factor includes both the filterable and condensable portions of the particulate emissions from AP-42 Table 3.1-2a dated 4/00.
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/4-Trbn
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby Plant Type of Emission: Point source
Emission Unit:Gas Turbine Unit #5 (primary fuel, natural gas)Type of Emission Unit: Natural gas fired utility turbine
ID # :5 SCC: 2-01-002-01
UDAQ ID # :174521
Year:2017
Emissions Summary Filterable Condensable
(tons/yr)(tons/yr)(tons/yr)
PM 0.84 0.24 0.60
PM10 0.84 0.24 0.60
PM2.5 0.84 0.24 0.60
SO2 0.08
NOX 3.70
NH3 1.20
VOC 0.27
CO 0.50
Pollutant Emission Factor or Equation Value Filterable Condensable Reference
PM 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
PM10 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
PM2.5 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
SO2 0.586 lb/mmcf 0.0006 lbmmBtu Average value from CEMS
NOX 28.176 lb/mmcf 0.029 lbmmBtu Average value from CEMS
NH3 0.0094 lb/mmBtu 9.100 lb/mmcf EPA Ammonia Factors
VOC 0.0021 lb/mmBtu 0.0021 lb/mmBtu AP-42 Table 3.1-2a, 4/00
CO 0.004 lb/mmBtu 0.004 lbmmBtu Average value from CEMS
Production Data
Natural gas consumption, mmcf/yr 262.923 mmcf/yr EIA-767
Heating value of fuel, Btu/ft3 1,044.2 Btu/ft3 EIA-767
Heat Input 255,455.2 mmBtu/yr Annual average CEM value
Hours of operation, hr/yr 1,183.0 hr/yr Actual hours of operation
Equations
Mass emissions = (emission factor) * (heat input) * (conversion factors)
Example:
Tons SO2/yr = (A lb/mmBtu) * (B mmBtu/yr) * (ton/2000 lb)
*Emission factor includes both the filterable and condensable portions of the particulate emissions from AP-42 Table 3.1-2a dated 4/00.
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/5-Trbn
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby Plant Type of Emission: Point source
Emission Unit:Gas Turbine Unit #6 (primary fuel, natural gas)Type of Emission Unit: Natural gas fired utility turbine
ID # :6 SCC: 2-01-002-01
UDAQ ID # :174522
Year:2017
Emissions Summary Filterable Condensable
(tons/yr)(tons/yr)(tons/yr)
PM 0.80 0.23 0.57
PM10 0.80 0.23 0.57
PM2.5 0.80 0.23 0.57
SO2 0.07
NOX 2.78
NH3 1.09
VOC 0.25
CO 0.89
Pollutant Emission Factor or Equation Value Filterable Condensable Reference
PM 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
PM10 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
PM2.5 0.0066 lb/mmBtu*0.0066 lb/mmBtu 0.0019 lb/mmBtu 0.0047 lb/mmBtu AP-42 Table 3.1-2a, 4/00
SO2 0.590 lb/mmcf 0.0006 lbmmBtu Average value from CEMS
NOX 23.075 lb/mmcf 0.023 lbmmBtu Average value from CEMS
NH3 0.0091 lb/mmBtu 9.100 lb/mmcf EPA Ammonia Factors
VOC 0.0021 lb/mmBtu 0.0021 lb/mmBtu AP-42 Table 3.1-2a, 4/00
CO 0.007 lb/mmBtu 0.0073 lbmmBtu Average value from CEMS
Production Data
Natural gas consumption, mmcf/yr 240.540 mmcf/yr EIA-767
Heating value of fuel, Btu/ft3 1,043.9 Btu/ft3 EIA-767
Heat Input 241,327 mmBtu/yr Annual average CEM value
Hours of operation, hr/yr 1,099.2 hr/yr Actual hours of operation
Equations
Mass emissions = (emission factor) * (heat input) * (conversion factors)
Example:
Tons SO2/yr = (A lb/mmBtu) * (B mmBtu/yr) * (ton/2000 lb)
*Emission factor includes both the filterable and condensable portions of the particulate emissions from AP-42 Table 3.1-2a dated 4/00.
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/6-Trbn
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby plant Type of Emission: Point source
Emission Unit:Circulating water cooling tower for Unit #1 Type of Emission Unit: Induced draft wet cooling tower
ID # :7 SCC: 3-85-00x-xx
UDAQ ID # :13689
Year:2017
Emissions Summary
(tons/yr)
PM10 1.02
PM2.5 0.00
Pollutant Emission Factor or Equation Value Reference
PM10 Drift * ppm of TDS in circulating water 0.00083 lb/103 gal Calculated from production data
PM2.5 Drift * ppm of TDS in circulating water 0.0000 lb/103 gal Assume all PM is greater than PM2.5
Production Data
Drift, percent of circulating water 0.002 %Vendor information
Circulating water flow, gal/min 70,000 gal/min Design circulating water flowrate
Drift (lb/103 gallons of circ. water)0.01168 lb/103 gal Design cooling tower drift (calculated value)
Conductivity of circulating water,mho/cm 5,500 mho/cm Measured conductivity of circulating water
Total dissolved solids in circulating water, ppm 4,950 ppm Calculated with conversion factor (0.9 ppm/mho/cm)
Hours of operation, hr/yr 585 hr/yr Actual hours of operation
Gallons per year 2,458.7 106 gal/yr Calculated
Equations
Mass emissions = (emission factor) * (water flow rate) * (conversion factors)
Example:
Tons PM10/yr = (A lb/103 gal) * (B gal/min) * (60 min/hr) * (C hr/yr) * (ton/2000 lb)
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/7
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby plant Type of Emission: Point source
Emission Unit:Circulating water cooling tower for Unit #2 Type of Emission Unit: Induced draft wet cooling tower
ID # :8 SCC: 3-85-00x-xx
UDAQ ID # :13690
Year:2017
Emissions Summary
(tons/yr)
PM10 0.91
PM2.5 0.00
Pollutant Emission Factor or Equation Value Reference
PM10 Drift * ppm of TDS in circulating water 0.00065 lb/103 gal Calculated from production data
PM2.5 Drift * ppm of TDS in circulating water 0.0000 lb/103 gal Assume all PM is greater than PM2.5
Production Data
Drift, percent of circulating water 0.002 %Vendor information
Circulating water flow, gal/min 70,000 gal/min Design circulating water flowrate
Drift (lb/103 gallons of circ. water)0.01168 lb/103 gal Design cooling tower drift (calculated value)
Conductivity of circulating water,mho/cm 4,300 mho/cm Measured conductivity of circulating water
Total dissolved solids in circulating water, ppm 3,870 ppm Calculated with conversion factor (0.9 ppm/mho/cm)
Hours of operation, hr/yr 670 hr/yr Actual hours of operation
Gallons per year 2,812.5 106 gal/yr Calculated
Equations
Mass emissions = (emission factor) * (water flow rate) * (conversion factors)
Example:
Tons PM10/yr = (A lb/103 gal) * (B gal/min) * (60 min/hr) * (C hr/yr) * (ton/2000 lb)
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/8
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby plant Type of Emission: Point source
Emission Unit:Circulating water cooling tower for Unit #3 Type of Emission Unit: Induced draft wet cooling tower
ID # :9 SCC: 3-85-00x-xx
UDAQ ID # :13691
Year:2017
Emissions Summary
(tons/yr)
PM10 1.21
PM2.5 0.00
Pollutant Emission Factor or Equation Value Reference
PM10 Drift * ppm of TDS in circulating water 0.00062 lb/103 gal Calculated from production data
PM2.5 Drift * ppm of TDS in circulating water 0.0000 lb/103 gal Assume all PM is greater than PM2.5
Production Data
Drift, percent of circulating water 0.002 %Vendor information
Circulating water flow, gal/min 82,000 gal/min Design circulating water flowrate
Drift (lb/103 gallons of circ. water)0.01368 lb/103 gal Design cooling tower drift (calculated value)
Conductivity of circulating water,mho/cm 4,100 mho/cm Target conductivity of circulating water
Total dissolved solids in circulating water, ppm 3,690 ppm Calculated with conversion factor (0.9 ppm/mho/cm)
Hours of operation, hr/yr 799 hr/yr Actual hours of operation
Gallons per year 3,929.9 106 gal/yr Calculated
Equations
Mass emissions = (emission factor) * (water flow rate) * (conversion factors)
Example:
Tons PM10/yr = (A lb/103 gal) * (B gal/min) * (60 min/hr) * (C hr/yr) * (ton/2000 lb)
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/9
PacifiCorp Gadsby INV
1/5/2024
Emissions Inventory Calculation Sheet
Facility:Gadsby plant Type of Emission: Point source
Emission Unit:Emergency generator diesel engine Type of Emission Unit: Diesel industrial engine
ID # :10 SCC: 2-02-001-02
UDAQ ID # :13692
Year:2017
Emissions Summary Filterable Condensable
(tons/yr)(tons/yr)(tons/yr)
PM 0.02 0.0 0.0
PM10 0.02 0.0 0.0
PM2.5 0.02 0.0 0.0
SO2 0.02
NOX 0.27
VOC 0.02
CO 0.06
Pollutant Emission Factor or Equation Value Filterable Condensable Reference
PM 0.00220 lb/hp-hr 0.0022 lb/hp-hr 0.0020 lb/hp-hr 0.0002 lb/hp-hr AP-42 Table 3.3-2, & 3.4-2, 1/95
PM10 0.00220 lb/hp-hr 0.0022 lb/hp-hr 0.0020 lb/hp-hr 0.0002 lb/hp-hr AP-42 Table 3.3-2, & 3.4-2, 1/95
PM2.5 0.00220 lb/hp-hr 0.0022 lb/hp-hr 0.0020 lb/hp-hr 0.0002 lb/hp-hr AP-42 Table 3.3-2, & 3.4-2, 1/95
SO2 0.00205 lb/hp-hr 0.00205 lb/hp-hr AP-42 Table 3.3-2, page 3.3-3, 1/95
NOX 0.031 lb/hp-hr 0.031 lb/hp-hr AP-42 Table 3.3-2, page 3.3-3, 1/95
VOC 0.00247 lb/hp-hr as TOC 0.00247 lb/hp-hr AP-42 Table 3.3-2, page 3.3-3, 1/95
CO 0.00696 lb/hp-hr 0.00696 lb/hp-hr AP-42 Table 3.3-2, page 3.3-3, 1/95
Production Data
Hours of operations, hr/year 63 hr/yr EPA guidance document, Sept. 6, 1995
Engine design brake horsepower, hp 280 hp Design rated capacity
Annual horsepower hours 17500 hp-hr
Equations
Mass emissions = (emission factor) * (hours of operation) * (design capacity) * (conversion factors)
Example:
Tons SO2/yr = (A lb/hp-hr) * (B hp) * (C hr/yr) * (ton/2000lb)
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/10
PacifiCorp Gadsby INV
1/5/2024
Emission Inventory Calculation Sheet
Facility:Gadsby plant Type of Emission: Point source
Emission Unit:Emergency generator diesel engine Type of Emission Unit: Diesel industrial engine
ID # :25 SCC: 2-02-004-01
UDAQ ID # :176981
Year:2017
Emissions Summary Filterable Condensable
(tons/yr)(tons/yr)(tons/yr)
PM 0.01 0.0 0.0
PM10 0.01 0.0 0.0
PM2.5 0.01 0.0 0.0
SO2 0.01
NOX 0.32
VOC 0.01
CO 0.07
Pollutant Emission Factor or Equation Value Filterable Condensable Reference
PM 0.0007 lb/hp-hr 0.0007 lb/hp-hr 0.0006 lb/hp-hr 0.0001 lb/hp-hr AP-42 Table 3.4-1, & 3.4-2 10/96
PM10 0.0007 lb/hp-hr 0.0007 lb/hp-hr 0.0006 lb/hp-hr 0.0001 lb/hp-hr AP-42 Table 3.4-1, & 3.4-2 10/96
PM2.5 0.0007 lb/hp-hr 0.0007 lb/hp-hr 0.0006 lb/hp-hr 0.0001 lb/hp-hr AP-42 Table 3.4-1, & 3.4-2 10/96
SO2 0.00809 x %S lb/hp-hr 0.00040 lb/hp-hr AP-42 Table 3.4-1, 10/96
NOX 0.024 lb/hp-hr 0.024 lb/hp-hr AP-42 Table 3.4-1, 10/96
VOC 0.000642 lb/hp-hr (TOC x 0.91 as nonmethane TOC)0.000642 lb/hp-hr AP-42 Table 3.4-1, 10/96
CO 0.0055 lb/hp-hr 0.0055 lb/hp-hr AP-42 Table 3.4-1, 10/96
Production Data
Hours of operations, hr/year 20 hr/yr Actual hours of operation
Engine design brake horsepower, hp 1,350 hp Design data
Annual horsepower hours 26325 hp-hr
Sulfur content of fuel oil, %0.05 %Power Statistics
Equations
Mass emissions = (emission factor) * (hours of operation) * (horse power rating) * (conversion factors)
Example:
Tons SO2/yr = (A lb/hp-hr) * (B hr/yr) * (C hp) * (ton/2000lb)
Gadsby 2017 - Unofficial Emissions Inventory.xlsx/25
PacifiCorp Jim Bridger INV
1/5/2024
Gadsby Plant: Emissions Summary
Emission Unit No.Emission Source Description
1 Steam Generating Unit #1 5.9 1.9 784.0 261.9 17.1 5.9 374,103.5 374,872.6
2 Steam Generating Unit #2 6.7 2.1 893.5 297.6 19.5 6.7 425,117.6 425,991.6
3 Steam Generating Unit #3 9.4 3.0 801.3 416.6 27.3 9.4 595,164.7 598,786.8
4 Steam Generating Units 44.39
7 Emission Unit #1 Cooling Tower 11.8 0.0
8 Emission Unit #2 Cooling Tower 9.2 0.0
9 Emission Unit #3 Cooling Tower 10.3 0.0
10 Emergency Generator (diesel engine)0.0 0.0 0.0 0.4 0.1 0.0 0.0 16.1 16.2
24 Natural Gas Simple Cycle Turbine Units 29.5 25.2 6.1 81.0 98.3 11.3 5.5 589,775.2 590,743.5
25 Black Start Generator 0.0 0.0 0.0 0.9 0.1 0.0 0.0 78.3 16.2
Total Emissions (tons/year):105.3 47.3 13.1 2,561.2 1,074.6 75.3 27.4 1,984,255.5 1,990,427.0
Notes:
Units #1, #2 and #3 boiler emissions (Emission Units 1, 2 and 3) are calculated on a potential-to-emit basis assuming 8,760 hours of operation per year.
Units #1, #2, and #3 cooling tower emissions (Emission Units 7, 8, and 9) are calculated on a potential-to-emit basis assuming 8,760 hours of operation per year
utilizing unit-specifc average annual circulating water conductivity values.
Emergency Generator Engine emissions (Emission Unit 10) are calculated based on 100 hours of operation per year for maintenance checks and readiness testing.
Natural Gas Simple Cycle Tubine Units emissions (Emission Unit 24) are calculated on a potential-to-emit basis assuming 8,760 hours of operation per year.
Black Start Generator emissions (Emission Unit 25) are calculated based on 100 hours of operation per year for maintenance checks and readiness testing.
Emission Source ID #24 (three natural gas simple cycle gas turbines) has a 12-month rolling SO2 limitation of 6.12 tons.
CO2 CO2eCOVOCs HAPsPM10SO2NOXPM2.5
Emission calculation worksheets are included for each emission source ID number.
Emission Source ID #4 (Steam Generating Units) has a 12-month rolling PM10 limitation of 44.39 tons.
Emission Source ID #24 (three natural gas simple cycle gas turbines) has a 12-month rolling PM10 limitation of 29.5 tons.
Emission Source ID #24 (three natural gas simple cycle gas turbines) has a 12-month rolling NOX limitation of 81.0 tons.
Emission Source ID #24 (three natural gas simple cycle gas turbines) has a 12-month rolling CO limitation of 98.30 tons.
Facility:Gadsby Plant Criteria Pollutant Emissions
Emission Source:Steam Generating Unit #1
Emission Unit #:1
Emissions Summary
tons/year
PM 23.7
PM10 5.9
PM2.5 5.9
SO2 1.9
NOX 784.0
CO 261.9
VOC 17.1
CO2 374,103.5
CH4 7.2
N2O 2.0
CO2e 374,872.6
Pollutant Emission Factor (Natural Gas) Reference
PM 0.0075 lb/MMBtu AP-42, Table 1.4-2
PM10 0.0019 lb/MMBtu AP-42, Table 1.4-2
PM2.5 0.0019 lb/MMBtu AP-42, Table 1.4-2
SO2 0.0006 lb/MMBtu AP-42, Table 1.4-2
NOX 179 lb/hour Emission Limit
CO 0.0824 lb/MMBtu AP-42, Table 1.4-1
VOC 0.0054 lb/MMBtu AP-42, Table 1.4-2
CO2 117.6 lb/MMBtu AP-42, Table 1.4-2
CH4 0.0023 lb/MMBtu AP-42, Table 1.4-2
N2O 0.00063 lb/MMBtu AP-42, Table 1.4-2
CO2 GWP Factor 1 Global Warming Potential Factor
CH4 GWP Factor 21 Global Warming Potential Factor
N2O GWP Factor 310 Global Warming Potential Factor
Production Data
Boiler Heat Input Rating:726 MMBtu/hour 11700.7 cfm
Natural Gas Heating Value:1,020 Btu/scf (AP-42 Table 1.4-2, footnote a)
Note:Gadsby Unit 1 is a wall-fired boiler with low-NOX burners.
Annual emission rates were based on firing on the primary fuel source (natural gas).
The Gadsby plant has the capability of firing on fuel oil during periods of natural gas curtailment.
Facility:Gadsby Plant Criteria Pollutant Emissions
Emission Source:Steam Generating Unit #2
Emission Unit #:2
Emissions Summary
tons/year
PM 26.9
PM10 6.7
PM2.5 6.7
SO2 2.1
NOX 893.5
CO 297.6
VOC 19.5
CO2 425,117.6
CH4 8.1
N2O 2.3
CO2e 425,991.6
Pollutant Emission Factor (Natural Gas) Reference
PM 0.0075 lb/MMBtu AP-42, Table 1.4-2
PM10 0.0019 lb/MMBtu AP-42, Table 1.4-2
PM2.5 0.0019 lb/MMBtu AP-42, Table 1.4-2
SO2 0.0006 lb/MMBtu AP-42, Table 1.4-2
NOX 204 lb/hour Emission Limit
CO 0.0824 lb/MMBtu AP-42, Table 1.4-1
VOC 0.0054 lb/MMBtu AP-42, Table 1.4-2
CO2 117.6 lb/MMBtu AP-42, Table 1.4-2
CH4 0.0023 lb/MMBtu AP-42, Table 1.4-2
N2O 0.00063 lb/MMBtu AP-42, Table 1.4-2
CO2 GWP Factor 1 Global Warming Potential Factor
CH4 GWP Factor 21 Global Warming Potential Factor
N2O GWP Factor 310 Global Warming Potential Factor
Production Data
Boiler Heat Input Rating:825 MMBtu/hour
Natural Gas Heating Value:1,020 Btu/scf (AP-42 Table 1.4-2, footnote a)
Note:Gadsby Unit 2 is a wall-fired boiler with low-NOX burners.
Annual emission rates were based on firing on the primary fuel source (natural gas).
The Gadsby plant has the capability of firing on fuel oil during periods of natural gas curtailment.
Facility:Gadsby Plant Criteria Pollutant Emissions
Emission Source:Steam Generating Unit #3
Emission Unit #:3
Emissions Summary
tons/year
PM 37.7
PM10 9.4
PM2.5 9.4
SO2 3.0
NOX 801.3
CO 416.6
VOC 27.3
CO2 595,164.7
CH4 11.4
N2O 10.9
CO2e 598,786.8
Pollutant Emission Factor (Natural Gas) Reference
PM 0.0075 lb/MMBtu AP-42, Table 1.4-2
PM10 0.0019 lb/MMBtu AP-42, Table 1.4-2
PM2.5 0.0019 lb/MMBtu AP-42, Table 1.4-2
SO2 0.0006 lb/MMBtu AP-42, Table 1.4-2
NOX 142 lb/hour Emission Limit 2,880 hours/year (November 1 through February 28 (29))
NOX 203 lb/hour Emission Limit 5,880 hours/year (March 1 through October 31)
CO 0.0824 lb/MMBtu AP-42, Table 1.4-1
VOC 0.0054 lb/MMBtu AP-42, Table 1.4-2
CO2 117.6 lb/MMBtu AP-42, Table 1.4-2
CH4 0.0023 lb/MMBtu AP-42, Table 1.4-2
N2O 0.00216 lb/MMBtu AP-42, Table 1.4-2
CO2 GWP Factor 1 Global Warming Potential Factor
CH4 GWP Factor 21 Global Warming Potential Factor
N2O GWP Factor 310 Global Warming Potential Factor
Production Data
Boiler Heat Input Rating:1,155 MMBtu/hour
Natural Gas Heating Value:1,020 Btu/scf (AP-42 Table 1.4-2, footnote a)
Note:Gadsby Unit 3 is a tangentially-fired boiler with low-NOX burners.
Annual emission rates were based on firing on the primary fuel source (natural gas).
The Gadsby plant has the capability of firing on fuel oil during periods of natural gas curtailment.
Facility:Gadsby Plant Criteria Pollutant Emissions
Emission Source:Emission Unit #1 Cooling Tower
Emission Unit #:7
Emissions Summary
tons/year
PM 11.8
PM10 11.8
PM2.5 0.0
Pollutant Emission Factor or Equation Value Reference
PM Drift * ppm of TDS in circulating water 0.0006 lb/103 gallons (assume PM same as PM10)
PM10 Drift * ppm of TDS in circulating water 0.0006 lb/103 gallons AP-42 Text, page 13.4-3, 1/95
PM2.5 0.0000 lb/103 gallons (assume all PM is greater than PM2.5)
Production Data
Circulating Water Flow:70 103 gallons/min Design circulating water flow rate of 70,000 gallons/minute
Drift (lb/103 gallons of circ. water)0.1668 lb/103 gallons Design cooling tower drift rate of 0.002%
Conductivity of circulating water 5,500 µmho/cm Measured conductivity of circulating water (2016 Emission Inventory value)
Total dissolved solids in circ water 3,850 ppm Calculated with conversion factor (0.7 ppm/µmho/cm)
Hours of Operation 8,760 hours/year Total potential annual hours of operation
Facility:Gadsby Plant Criteria Pollutant Emissions
Emission Source:Emission Unit #2 Cooling Tower
Emission Unit #:8
Emissions Summary
tons/year
PM 9.2
PM10 9.2
PM2.5 0.0
Pollutant Emission Factor or Equation Value Reference
PM Drift * ppm of TDS in circulating water 0.0005 lb/103 gallons (assume PM same as PM10)
PM10 Drift * ppm of TDS in circulating water 0.0005 lb/103 gallons AP-42 Text, page 13.4-3, 1/95
PM2.5 0.0000 lb/103 gallons (assume all PM is greater than PM2.5)
Production Data
Circulating Water Flow:70 103 gallons/min Design circulating water flow rate of 70,000 gallons/minute
Drift (lb/103 gallons of circ. water)0.1668 lb/103 gallons Design cooling tower drift rate of 0.002%
Conductivity of circulating water 4,300 µmho/cm Measured conductivity of circulating water (2016 Emission Inventory value)
Total dissolved solids in circ water 3,010 ppm Calculated with conversion factor (0.7 ppm/µmho/cm)
Hours of Operation 8,760 hours/year Total potential annual hours of operation
Facility:Gadsby Plant Criteria Pollutant Emissions
Emission Source:Emission Unit #3 Cooling Tower
Emission Unit #:9
Emissions Summary
tons/year
PM 10.3
PM10 10.3
PM2.5 0.0
Pollutant Emission Factor or Equation Value Reference
PM Drift * ppm of TDS in circulating water 0.0005 lb/103 gallons (assume PM same as PM10)
PM10 Drift * ppm of TDS in circulating water 0.0005 lb/103 gallons AP-42 Text, page 13.4-3, 1/95
PM2.5 0.0000 lb/103 gallons (assume all PM is greater than PM2.5)
Production Data
Circulating Water Flow:82 103 gallons/min Design circulating water flow rate of 82,000 gallons/minute
Drift (lb/103 gallons of circ. water)0.1668 lb/103 gallons Design cooling tower drift rate of 0.002%
Conductivity of circulating water 4,100 µmho/cm Measured conductivity of circulating water (2016 Emission Inventory value)
Total dissolved solids in circ water 2,870 ppm Calculated with conversion factor (0.7 ppm/µmho/cm)
Hours of Operation 8,760 hours/year Total potential annual hours of operation
Facility:Gadsby Plant
Emission Source:Emergency Generator (diesel engine)
Source ID#:10
Emissions Summary
tons/year
PM 0.0
PM10 0.0
PM2.5 0.0
NOX 0.4
SO2 0.0
CO 0.1
VOC 0.0
CO2 16.1
CO2e 16.2
Pollutant Emission Factor or Equation Value Reference
PM 2.20 E-03 lb/hp-hr 2.20E-03 lb/hp-hr AP-42 Table 3.3-1, 10/96
PM10 2.20 E-03 lb/hp-hr 2.20E-03 lb/hp-hr AP-42 Table 3.3-1, 10/96
PM2.5 2.20 E-03 lb/hp-hr 2.20E-03 lb/hp-hr AP-42 Table 3.3-1, 10/96
SO2 2.05 E-03 lb/hp-hr 2.05E-03 lb/hp-hr AP-42 Table 3.3-1, 10/96
NOX 0.031 lb/hp-hr 0.031 lb/hp-hr AP-42 Table 3.3-1, 10/96
VOC 2.47 E-03 lb/hp-hr (VOCs as TOC)2.47E-03 lb/hp-hr AP-42 Table 3.3-1, 10/96
CO 6.68 E-03 lb/hp-hr 6.68E-03 lb/hp-hr AP-42 Table 3.3-1, 10/96
CO2 1.15 lb/hp-hour 1.15 lb/hp-hr AP-42 Table 3.3-1, 10/96
CH4 0.09 lb/MMBtu 0.09 lb/MMBtu AP-42 Table 3.4-1
CO2 GWP Factor 1 Global Warming Potential Factor
CH4 GWP Factor 21 Global Warming Potential Factor
Production Data
Rated capacity, hp 280 horsepower (Diesel engine rating)
Hours of operation, hr/yr 100 hours/year (Engine is operated a maximum of 100 hours per year for maintenance checks and readiness testing.)
Diesel engine thermal efficiency 50 %(Typical thermal efficiency of a diesel engine)
Conversion factor 0.7068 Btu/sec-horsepower
Heat input 1.4 MMBtu/hour
PM = (0.00220 lb/hp-hour) x (280 hp) x (100 hours/year) x (ton/2000 lb) =0.0 tons/year PM
PM10 = (0.00220 lb/hp-hour) x (280 hp) x (100 hours/year) x (ton/2000 lb) =0.0 tons/year PM10
PM2.5 = (0.00220 lb/hp-hour) x (280 hp) x (100 hours/year) x (ton/2000 lb) =0.0 tons/year PM2.5
CO2 = (1.15 lb/hp-hour) x (280 hp) x (100 hours/year) x (ton/2000 lb) =16.1 tons/year CO2
CH4 = (0.09 lb/MMBtu) x (1.4 MMBtu/hour) x (100 hours/year) x (ton/2000 lb) =0.0 tons/year CH4
CO2e = [CO2 emissions] + [(N2O emissions) x (N2O GWP factor)] + [(CH4 emissions) x (CH4 GWP factor)]
CO2e = [16.1 tons/year) + [(0.0 tons/year) x (310)] + [(0.0 tons/year) x (21)] =16.2 tons/year CO2e
Facility:Gadsby Plant
Emission Source:Unit 4, 5 and 6 Gas Turbines
Source ID#:24
Emissions Summary
tons/year
PM 35.4
PM10 29.5
PM2.5 25.2
NOX 81.0
SO2 6.1
CO 98.3
VOC 11.3
CO2 589,775.2
CO2e 590,743.5
Pollutant Emission Factor or Equation Value Reference
PM 6.6 E-03 lb/MMBtu 6.6E-03 lb/MMBtu AP-42 Table 3.1-2a, 4/00
PM10 29.5 tons/year 29.5 tons/12-month period Permit Limit
PM2.5 4.7 E-03 lb/MMBtu 4.7E-03 lb/MMBtu AP-42 Table 3.1-2a, 4/00 (assume condensible)
SO2 6.12 tons/year 6.12 tons/12-month period Permit Limit
NOX 81.0 tons/year 81.0 tons/12-month period Permit Limit
VOC 2.1 E-03 lb/MMBtu 2.1E-03 lb/MMBtu AP-42 Table 3.1-2a, 4/00
CO 98.30 tons/year 98.30 tons/12-month period Permit Limit
CO2 110 lb/MMBtu 110 lb/MMBtu AP-42 Table 3.1-2a, 4/00
CH4 8.6 E-03 lb/MMBtu 8.6E-03 lb/MMBtu AP-42 Table 3.1-2a, 4/00
CO2 GWP Factor 1 Global Warming Potential Factor
CH4 GWP Factor 21 Global Warming Potential Factor
Production Data
Combustion Gas Turbine Design Heat Input at LHV 367.6 MMBtu/hour (at LHV)(Each; three required)
Combustion Gas Turbine Heat Input at HHV1 408.0 MMBtu/hour (at HHV) (Each; three required)
Combustion Gas Turbine Heat Input at HHV 1,224.1 MMBtu/hour (total for three; Units 4, 5 and 6 using higher heating value (HHV))
Hours of operation, hr/yr 8,760 hours/year (potential annual operating time)
PM2.5 = (0.0047 lb/MMBtu) x (1224.1 MMBtu/hour) x (8760 hours/year) x (ton/2000 lb)
PM2.5 =25.2 tons/year PM2.5
CO2 = (110 lb/MMBtu) x (1224.1 MMBtu/hour) x (8760 hours/year) x (ton/2000 lb)
CO2 =589,775.2 tons/year CO2
CH4 = (0.0086 lb/MMBtu) x (1224.1 MMBtu/hour) x (8760 hours/year) x (ton/2000 lb)
CH4 =46.1 tons/year CH4
CO2e = [CO2 emissions] + [(N2O emissions) x (N2O GWP factor)] + [(CH4 emissions) x (CH4 GWP factor)]
CO2e = [589775.2 tons/year] + [(0.0 tons/year) x (310)] + [(46.1 tons/year) x (21)]
CO2e =590,743.5 tons/year CO2e
1 HHV (higher heating value) is obtained by multiplying natural gas LHV (lower heating value) by conversion factor of 1.11
Facility:Gadsby
Emission Source:Black Start Generator
Source ID#:25
Emissions Summary
tons/year
PM 0.0
PM10 0.0
PM2.5 0.0
NOX 0.9
SO2 0.0
CO 0.1
VOC 0.0
CO2 78.3
CO2e 79.3
Pollutant Emission Factor or Equation Value Reference
PM 0.0007 lb/hp-hour 0.0007 lb/hp-hour AP-42 Table 3.4-1, 10/96
PM10 54.4 g/hour 54.4 g/hour Manufacturer (Detroit Diesel) Emission Data
PM2.5 0.0479 lb/MMBtu 0.0479 lb/MMBtu AP-42 Table 3.4-2 guidance
SO2 104 g/hour 104 g/hour Manufacturer (Detroit Diesel) Emission Data
NOX 8,235 g/hour 8,235 g/hour Manufacturer (Detroit Diesel) Emission Data
VOC 0.000705 lb/hp-hour (TOC)0.000705 lb/hp-hour AP-42 Table 3.4-1, 10/96
CO 834 g/hour 834 g/hour Manufacturer (Detroit Diesel) Emission Data
CO2 1.16 lb/hp-hour 1.16 lb/hp-hour AP-42 Table 3.4-1, 10/96
CH4 0.000705 lb/hp-hour 0.000705 lb/hp-hour AP-42 Table 3.4-1, 10/96
CO2 GWP Factor 1 Global Warming Potential Factor
CH4 GWP Factor 21 Global Warming Potential Factor
Production Data
Rated capacity, hp 1,350 horsepower (Detroit Diesel engine rating)
Model No. 16V2000 G43 R163-7M36 (Detroit Diesel information)
Hours of operation, hr/yr 100 hours/year (Engine is operated maximum of 100 hours per year for rmaintenance checks and readiness testing)
Fuel Consumption 64.1 gallons/hour (Manufacturer)
Fuel Heating Value 140,439 Btu/gallon
Heat input 9.0 MMBtu/hour
PM = (0.0007 lb/hp-hour) x (1350 hp) x (100 hours/year) x (ton/2000 lb) =0.0 tons/year PM
PM10 = (54.4 g/hour) x (100 hour/year) x (lb/453.59 g) x (ton/2000 lb) =0.0 tons/year PM10
PM2.5 = (0.0479 lb/MMBtu) x (9.0 MMBtu/hour) x (100 hours/year) x (ton/2000 lb) =0.0 tons/year PM2.5
CO2 = (1.16 lb/hp-hour) x (1350 hp) x (100 hours/year) x (ton/2000 lb) =78.3 tons/year CO2
CH4 = (0.000705 lb/hp-hour) x (1350 hp) x (100 hours/year) x (ton/2000 lb) =0.0 tons/year CH4
CO2e = [CO2 emissions] + [(N2O emissions) x (N2O GWP factor)] + [(CH4 emissions) x (CH4 GWP factor)]
CO2e = [78.3 tons/year) + [(0.0 tons/year) x (310)] + [(0.0 tons/year) x (21)] =79.3 tons/year CO2e
Reasonable Available Control Technology
Review for Gadsby Power Plant
AECOM
39
Appendix C – RACT/BACT/LAER
Clearinghouse Search Results
RBLC Search For Large Natural Gas Boilers > 250 MMBtu/hr - NOx Emissions
RBLCID FACILITY NAME FACILITY
STATE
PERMIT ISSUE
DATE PROCESS NAME THROUGHPUT THROUGHPUT
UNIT CONTROL METHOD DESCRIPTION
*LA-0315 G2G PLANT LA 5/23/2014 Utility Boiler 1 656 MMBTU/HR Selective Catalytic Reduction (SCR)0.006 LB/MMBTU
12-MONTH
AVERAGE
*LA-0315 G2G PLANT LA 5/23/2014 Utility Boiler 2 656 MMBTU/HR Selective Catalytic Reduction (SCR)0.006 LB/MMBTU
12-MONTH
AVERAGE
*LA-0315 G2G PLANT LA 5/23/2014 Utility Boiler 3 656 MMBTU/HR Selective Catalytic Reduction (SCR)0.006 LB/MMBTU
12-MONTH
AVERAGE
*LA-0312 ST. JAMES METHANOL PLANT LA 6/30/2017 B1-13 - Boiler 1
(EQT0003)350 MM BTU/hr Selective Catalytic Reduction, Low NOx
Burners, & Good Combustion Practices 0.01 LB/MMMTU
12 MONTH
AVERAGE
*LA-0312 ST. JAMES METHANOL PLANT LA 6/30/2017 B2-13 - Boiler 2
(EQT0004)350 MM BTU/hr Selective Catalytic Reduction, Low NOx
Burners, & Good Combustion Practices 0.01 LB/MMBTU
12-MONTH
AVERAGE
LA-0364 FG LA COMPLEX LA 1/6/2020 Boilers 1200 mm btu/h SCR and LNB 0.01 LB/MMBTU 12-MONTH
ROLLING AVERAGE
TX-0656 GAS TO GASOLINE PLANT TX 12/2/2014 Boiler 950 MMBTU/H SCR 0.01 LB/MMBTU
TX-0659 DEER PARK PLANT TX 12/20/2013 Boiler 515 MMBTU/H Selective catalytic reduction 0.01 LB/MMBTU 1-HR
TX-0698 BAYPORT COMPLEX TX 9/5/2013 (3) gas-fired boilers 550 MMBTU/H Selective Catalytic Reduction (SCR)0.01 LB/MMBTU 3 HOUR ROLLING
AVERAGE
TX-0704 UTILITY PLANT TX 12/2/2014 (2) boilers 450 MMBTU/H Selective Catalytic Reduction 0.01 LB/MMBTU 3-HR ROLLING
AVERAGE
TX-0704 UTILITY PLANT TX 12/2/2014 boiler 250 MMBTU/H Selective Catalytic Reduction 0.01 LB/MMBTU 3-HR ROLLING
AVERAGE
TX-0707 CHEMICAL MANUFACTURING
FACILITY TX 12/20/2013 (2) boilers 515 MMBTU/H Selective Catalytic Reduction 0.01 LB/MMBTU 1 HOUR
WY-0074 GREEN RIVER SODA ASH PLANT WY 11/18/2013 Natural Gas Package
Boiler 254 MMBTU/H low NOx burners and flue gas recirculation 0.011 LB/MMBTU 30-DAY ROLLING
IL-0114 CRONUS CHEMICALS, LLC IL 9/5/2014 Boiler 864 MMBTU/H low-nox burners, scr (or equivalent)0.012 LB/MMBTU 30-DAY AVERAGE
ROLLED DAILY
TX-0888 ORANGE POLYETHYLENE PLANT TX 4/23/2020 BOILERS 250 MMBTU SCR 0.015 LB/MMBTU HOURLY
ND-0032 SPIRITWOOD NITROGEN PLANT ND 6/20/2014 Package boiler 280 MMBTU/H ultra low NOx burners and flue gas
recirculation 0.018 LB/MMBTU 30 DAY ROLLING
AVERAGE
AL-0271 GEORGIA PACIFIC BRETON LLC AL 6/11/2014 No.4 Power Boiler 425 MMBTU/H Low NOx Burner with FGR 0.02 LB/MMBTU
FL-0344 OKEELANTA COGENERATION PLANT FL 8/27/2013 Natural Gas Boiler 589 MMBTU/H Ultra-low NOx burners with over-fire air 0.035 LB/MMBTU 30-DAY ROLLING
AVERAGE BY CEMS
LA-0323 MONSANTO LULING PLANT LA 1/9/2017 No. 9 Boiler - Natural
Gas Fired 325 MMBTU/h Ultra Low NOx Burners 0.035 LB/MMBTU ANNUAL AVERAGE
LA-0323 MONSANTO LULING PLANT LA 1/9/2017 No. 10 Boiler - Natural
Gas Fired 325 MMBTU/h Ultra Low NOx Burners 0.035 LB/MMBTU ANNUAL AVERAGE
NE-0065 CARGILL, INCORPORATED NE 9/12/2013 Boiler L 299 MMBtu/hr Low-NOx burners and Induced Flue Gas
Recirculation 0.036 LB/MMBTU 30-DAY ROLLING
AVERAGE
MI-0440 MICHIGAN STATE UNIVERSITY MI 5/22/2019 EUSTMBOILER 300 MMBTU/H Low-NOx burners and internal flue gas
recirculation (FGR)0.04 LB/MMBTU
30 DAY ROLL AVG
WHEN FIRING
NAT. GAS
NE-0054 CARGILL, INCORPORATED NE 9/12/2013 Boiler K 300 mmbtu/h LOW NOX BURNERS AND INDUCED FLUE
GAS RECIRCULATION 0.04 LB/MMBTU 30-DAY ROLLING
AVERAGE
IN-0234 GRAIN PROCESSING CORPORATION IN 12/8/2015 BOILER 1 271 MMBTU/H LOW-NOX BURNER AND FLUE GAS
RECIRCULATION SYSTEM 0.05 LB/MMBTU NORMAL
OPERATION
IN-0234 GRAIN PROCESSING CORPORATION IN 12/8/2015 BOILER 2 271 MMBTU/H LOW-NOX BURNERS AND FLUE GAS
RECIRCULATION 0.05 LB/MMBTU NORMAL
OPERATION
STANDARD EMISSION LIMIT
RBLC Search For Large Natural Gas Boilers > 250 MMBtu/hr - VOC Emissions
RBLCID FACILITY NAME FACILITY
STATE
PERMIT
ISSUE DATE PROCESS NAME THROUGHPUT THROUGHPUT
UNIT CONTROL METHOD DESCRIPTION
AL-0271 GEORGIA PACIFIC BRETON LLC AL 6/11/2014 No.4 Power Boiler 425 MMBTU/H Good Combustion Practices 0.0053 LB/MMBTU
IA-0106 CF INDUSTRIES NITROGEN, LLC -
PORT NEAL NITROGEN COMPLEX IA 7/12/2013 Boilers 456 MMBTU/HR Oxidation Catalyst, good operating
practices and use of natural gas 0.0014 LB/MMBTU
AVERAGE OF
THREE (3)
STACK TEST
RUNS
IL-0114 CRONUS CHEMICALS, LLC IL 9/5/2014 Boiler 864 MMBTU/HR good combustion practices 0.0054 LB/MMBTU 3-HOUR
AVERAGE
IN-0234 GRAIN PROCESSING CORPORATION IN 12/8/2015 BOILER 1 271 MMBTU/HR GOOD COMBUSTION PRACTICES 0.0015 LB/MMBTU
IN-0234 GRAIN PROCESSING CORPORATION IN 12/8/2015 BOILER 2 271 MMBTU/HR GOOD COMBUSTION PRACTICES 0.0015 LB/MMBTU
*LA-0312 ST. JAMES METHANOL PLANT LA 6/30/2017 B1-13 - Boiler 1
(EQT0003)350 MMBTU/HR Good Combustion Practices 0.0054 LB/MMBTU
*LA-0312 ST. JAMES METHANOL PLANT LA 6/30/2017 B2-13 - Boiler 2
(EQT0004)350 MMBTU/HR Good Combustion Practices 0.0054 LB/MMBTU
*LA-0315 G2G PLANT LA 5/23/2014 Utility Boiler 1 656 MMBTU/HR
Combustion controls (proper
burner design and operation using
natural gas)
0.0054 LB/MMBTU 12 month
rolling average
*LA-0315 G2G PLANT LA 5/23/2014 Utility Boiler 2 656 MMBTU/HR
Combustion controls (proper
burner design and operation using
natural gas)
0.0054 LB/MMBTU 12 month
rolling average
*LA-0315 G2G PLANT LA 5/23/2014 Utility Boiler 3 656 MMBTU/HR
Combustion controls (proper
burner design and operation using
natural gas)
0.0054 LB/MMBTU 12 month
rolling average
LA-0346 GULF COAST METHANOL COMPLEX LA 1/4/2018 Inline Boilers (4)258 MMBTU/HR catalytic oxidation 0.002 LB/MM BTU
LA-0364 FG LA COMPLEX LA 1/6/2020 Boilers 1200 MMBTU/HR
Good combustion practices and
compliance with the applicable
provisions of 40 CFR 63 Subpart
DDDDD
0.0055 LB/MMBTU
TX-0704 UTILITY PLANT TX 12/2/2014 (2) boilers 450 MMBTU/H good combustion practices 0.004 LB/MMBTU
TX-0704 UTILITY PLANT TX 12/2/2014 boiler 250 MMBTU/H good combustion practices 0.004 LB/MMBTU
TX-0888 ORANGE POLYETHYLENE PLANT TX 4/23/2020 BOILERS 250 MMBTU
Good combustion practice and
proper design.

VOC emissions associated with vent
streams routed to the boiler firebox
will be minimized by achieving a
DRE of at least 99%.
0.0054 LB/MMBTU
TX-0936 BILL GREEHEY REFINERY EAST PLANT TX 3/29/2022 BOILER 334 MMBTU/HR Gaseous fuel and good combustion
practices 0.0054 LB/MMBTU
WI-0267 GREEN BAY PACKAGING, INC. - MILL
DIVISION WI 9/6/2018
Two Natural Gas-Fired
Boilers (Boilers B34 and
B35)
285 mmBtu/hr Good combustion practices, only
fire natural gas and/or biogas 0.0055 LB/MMBTU
WY-0074 GREEN RIVER SODA ASH PLANT WY 11/18/2013 Natural Gas Package
Boiler 254 MMBTU/H good combustion practices 0.0054 LB/MMBTU 3-HR AVERAGE
STANDARD EMISSION LIMIT
RBLC Search For Simple Cycle Combustion Turbines > 25 MW - NOx Determinations
RBLCID FACILITY NAME FACILITY
STATE Permit Date PROCESS NAME THROUGHPUT THROUGHPUT
UNIT CONTROL METHOD DESCRIPTION
AK-0088 LIQUEFACTION PLANT AK 7/7/2022 Six Simple Cycle Gas-Fired Turbines 1113 MMBtu/hr SCR, DLN combustors, and good
combustion practices 2 PPMV @ 15%
O2 3-HOURS
AK-0085 GAS TREATMENT PLANT AK 8/13/2020 Six (6) Simple Cycle Gas-Turbines
(Power Generation)386 MMBtu/hr DLN combustors and Good Combustion
Practices 15 PPMV @ 15%
O2 3-HOUR AVERAGE
FL-0346 LAUDERDALE PLANT FL 4/22/2014 Five 200-MW combustion turbines 2000 MMBtu/hr
Required to employ dry low-NOx
technology and wet injection. Water
injection must be used when firing ULSD.
9 PPMVD @ 15%
02
24-HR BLOCK AVG,
BY CEMS (NAT GAS)
FL-0354 LAUDERDALE PLANT FL 8/25/2015 Five 200-MW combustion turbines 2100 MMBtu/hr Dry-low-NOx combustion system. Wet
injection when firing ULSD.9 PPMVD@15%O
2
24-HR BLOCK
AVERAGE
FL-0355 FORT MYERS PLANT FL 9/10/2015 Combustion Turbines 2262.4 MMBtu/hr DLN and wet injection (for ULSD operation)9 PPMVD@15%
O2
GAS FIRING, 24-HR
BLOCK AVG
IL-0121 INVENERGY NELSON EXPANSION
LLC IL 9/27/2016 Two Simple Cycle Combustion
Turbines 190 MW
Dry low-NOx combustion technology for
natural gas and low-NOx combustion
technology and water injection for ULSD.
9 PPMV @ 15%
O2 12 MO Rolling Total
IN-0264 MONTPELIER GENERATING
STATION IN 1/6/2017 PRATT; TWIN-PAC SIMPLE CYCLE
TURBINES 270.9 MMBTU/H WATER INJECTION 25 PPMV AT 15% O2 FOR
NATURAL GAS
KS-0036 WESTAR ENERGY - EMPORIA
ENERGY CENTER KS 3/18/2013 GE LM6000PC SPRINT Simple cycle
combustion turbine 405.3 MMBTU/hr dry low NOx burners and fire only pipeline
natural gas 9 PPMDV
24-HR ROLLING AVE,
CORRECTED TO 15%
O2
KS-0036 WESTAR ENERGY - EMPORIA
ENERGY CENTER KS 3/18/2013 GE 7FA Simple Cycle Combustion
Turbine 1780 MMBTU/HR dry low NOx burners and fire only pipeline
natural gas 9 PPMDV
24-HR ROLLING AVE,
CORRECTED TO 15%
O2
KS-0036 WESTAR ENERGY - EMPORIA
ENERGY CENTER KS 3/18/2013 GE LM6000PC SPRINT Simple cycle
combustion turbine 405.3 MMBTU/hr water injection 25 PPMDV
24-HR ROLLING AVE;
CORRECTED TO 15%
O
LA-0349 DRIFTWOOD LNG FACILITY LA 7/10/2018 Compressor Turbines (20)540 MMBTU/hr DLN and SCR 5 PPMVD
@ 15% O2
*LA-0327 WASHINGTON PARISH ENERGY
CENTER LA 5/23/2018
CTG01 NO - Simple-Cycle
Combustion Turbine 1 (Normal
Operations) [EQT0017]
2201 MMBTU/hr Pipeline quality natural gas & dry-low-NOX
burners 9 PPMVD
@15%O2
30-DAY ROLLING
AVERAGE
*LA-0327 WASHINGTON PARISH ENERGY
CENTER LA 5/23/2018
CTG02 NO - Simple-Cycle
Combustion Turbine 2 (Normal
Operations) [EQT0018]
2201 MMBTU/hr Pipeline quality natural gas & dry-low-NOX
burners 9 PPMVD
@15%O2
30-DAY ROLLING
AVERAGE
LA-0331 CALCASIEU PASS LNG PROJECT LA 9/21/2018 Simple Cycle Combustion Turbines
(SCCT1 to SCCT3)927 MMBTU/hr
Dry Low NOx Combustor Design, Good
Combustion Practices, and Natural Gas
Combustion.
9 PPMV 30 DAY ROLLING
AVERAGE
LA-0316 CAMERON LNG FACILITY LA 2/17/2017 Gas turbines (9 units)1069 MMBTU/hr good combustion practices and dry low nox
burners 15 PPMVD @15%O2
LA-0307 MAGNOLIA LNG FACILITY LA 3/21/2016 Gas Turbines (8 units)333 MMBTU/hr Dry Low NOX burners and good
combustion practices 25 PPMVD @15 %O2
LA-0331 CALCASIEU PASS LNG PROJECT LA 9/21/2018 Aeroderivative Simple Cycle
Combustion Turbine 263 MM BTU/h
Selective Catalytic Reduction (SCR),
exclusive combustion of fuel gas, and good
combustion practices.
25 PPMV 30 DAY ROLLING
AVERAGE
MD-0043 PERRYMAN GENERATING STATION MD 7/1/2014 (2) 60-MW SIMPLE CYCLE
COMBUSTION TURBINES 120 MW
USE OF NATURAL GAS, WATER/STEAM
INJECTION, AND A SELECTIVE CATAYTIC
REDUCTION (SCR) SYSTEM
2.5 PPMVD @ 15%
O2
3-HOUR BLOCK
AVERAGE,
EXCLUDING SU/SD
MD-0044 COVE POINT LNG TERMINAL MD 6/9/2014 2 COMBUSTION TURBINES 130 MW
USE OF DRY LOW-NOX COMBUSTOR
TURBINE DESIGN (DLN1), USE OF FACILITY
PROCESS FUEL GAS AND PIPELINE
NATURAL GAS DURING NORMAL
OPERATION AND SCR SYSTEM
2.5 PPMVD @ 15%
O2
3-HOUR BLOCK
AVERAGE,
EXCLUDING SU/SD
MI-0441 LBWL--ERICKSON STATION MI 12/21/2018
EUCTGSC1-A nominally rated 667
MMBTU/hr natural gas-fired simple
cycle CTG
667 MMBTU/hr Dry low NOx burners (DLNB) and good
combustion practices.25 PPM
AT 15%O2;4-HR
ROLL AVG; SEE
NOTES BELOW
MI-0447 LBWL--ERICKSON STATION MI 1/7/2021 EUCTGSC1-natural gas fired simple
cycle CTG 667 MMBTU/hr DLNB and good combustion practices.25 PPM
4-HR ROLL AVG
EXCEPT LESS THAN
75% PEAK
MI-0454 LBWL-ERICKSON STATION MI 12/20/2022
EUCTGSC1--A nominally rated 667
MMBTU/H natural gas-fired simple
cycle CTG
667 MMBTU/hr DLNB and good combustion practices.25 PPM
4-HR ROLLING AVG
EXCEPT <75% PEAK
LOAD
ND-0029 PIONEER GENERATING STATION ND 5/14/2013 Natural gas-fired turbines 451 MMBTU/hr Water injection plus SCR 5 PPPMVD
4 HR. ROLLING
AVERAGE EXCEPT
FOR STARTUP
ND-0030 LONESOME CREEK GENERATING
STATION ND 9/16/2013 Natural Gas Fired Simple Cycle
Turbines 412 MMBTU/hr SCR 5 PPMVD
4 HOUR ROLLING
AVERAGE EXCEPT
STARTUP
ND-0028 R.M. HESKETT STATION ND 2/22/2013 Combustion Turbine 986 MMBTU/hr Dry low-NOx combustion (DLN)9 PPMVD @15%
OYYGEN
4 H.R.A. WHEN >
50MWE AND > 0
DEGREES F
NJ-0086 BAYONNNE ENERGY CENTER NJ 8/26/2016 Simple Cycle Stationary Turbines
firing Natural gas 2143980 MMBTU/YR
Selective Catalytic Reduction, water
injection, use of natural gas a low NOx
emitting fuel
2.5 PPMVD@15%O
2
3 H ROLLING AV
BASED ON ONE H
BLOCK AV
NY-0103 CRICKET VALLEY ENERGY CENTER NY 2/3/2016 Turbines and duct burners 228 MW dry low NOx burners in combination with
selective catalytic reduction 2 PPMVD @ 15%
O2 1 H
OR-0050 TROUTDALE ENERGY CENTER, LLC OR 3/5/2014 GE LMS-100 combustion turbines,
simple cycle with water injection 1690 MMBTU/hr
Utilize water injection when combusting
natural gas or ULSD;

Utilize selective catalytic reduction (SCR)
with aqueous ammonia injection at all
Ɵmes except during startup and shutdown;

Limit the time in startup or shutdown.
2.5 PPMDV AT 15%
O2
3-HR ROLLING
AVERAGE ON NG
*TN-0187
TENNESSEE VALLEY AUTHORITY -
JOHNSONVILLE COMBUSTION
TURBINE
TN 8/31/2022 Ten Simple Cycle NG Turbines 465.8 MMBtu/hr dry low-NOx burners

selective catalytic reduction 5 PPMVD @ 15%
O2
4-HOUR ROLLING
AVERAGE
EXCLUDING
STA/SHU
TX-0686 ANTELOPE ELK ENERGY CENTER TX 4/22/2014 Combustion Turbine-Generator
(CTG)202 MW DLN 9 PPM 15% O2, 3 HR.
ROLLING AVG.
TX-0688 SR BERTRON ELECTRIC
GENERATION STATION TX 12/19/2014 Simple cycle natural gas turbines 225 MW DLN 9 PPM 3HR ROLLING AVG.
TX-0693 ANTELOPE ELK ENERGY CENTER TX 4/22/2014 combustion turbine 202 MW DLN combustors 9 PPMVD @15% O2, 3-HR
ROLLING AVERAGE
TX-0694 INDECK WHARTON ENERGY
CENTER TX 2/2/2015 (3) combustion turbines 220 MW DLN combustors 9 PPMVD @15% O2, 3-HR
ROLLING AVERAGE
TX-0695 ECTOR COUNTY ENERGY CENTER TX 8/1/2014 (2) combustion turbines 180 MW DLN combustors 9 PPMVD @15% O2, 3-HR
ROLLING AVG
TX-0696 ROAN'S PRAIRIE GENERATING
STATION TX 9/22/2014 (2) simple cycle turbines 600 MW DLN combustors 9 PPMVD @15% O2, 3-HR
ROLLING AVG
TX-0701 ECTOR COUNTY ENERGY CENTER TX 8/1/2014 Simple Cycle Combustion Turbines 180 MW Dry low NOx combustor 9 PPMVD 15%O2, 3HR
ROLLING BASIS
TX-0733 ANTELOPE ELK ENERGY CENTER TX 5/12/2015 Simple Cycle Turbine &amp;
Generator 202 MW Dry Low NOx burners 9 PPMVD AT 15%
O2
STANDARD EMISSION LIMIT
RBLC Search For Simple Cycle Combustion Turbines > 25 MW - NOx Determinations
RBLCID FACILITY NAME FACILITY
STATE Permit Date PROCESS NAME THROUGHPUT THROUGHPUT
UNIT CONTROL METHOD DESCRIPTION STANDARD EMISSION LIMIT
TX-0734 CLEAR SPRINGS ENERGY CENTER
(CSEC)TX 5/8/2015 Simple Cycle Turbine 183 MW dry low-NOx (DLN) burners 9 PPMVD @ 15%
O2 3-HR AVERAGE
TX-0764 NACOGDOCHES POWER ELECTRIC
GENERATING PLANT TX 10/14/2015 Natural Gas Simple Cycle Turbine (25
MW)232 MW Dry Low NOx burners, good combustion
practices, limited operations 9 PPMVD @ 15%
O2
TX-0768 SHAWNEE ENERGY CENTER TX 10/9/2015 Simple cycle turbines greater than 25
megawatts (MW)230 MW Dry Low NOx burners 9 PPMVD @ 15%
O2
TX-0769 VAN ALSTYNE ENERGY CENTER
(VAEC)TX 10/27/2015 Simple Cycle Turbine 183 MW DLN burners 9 PPMVD @ 15%
O2 3-HR AVERAGE
TX-0777 UNION VALLEY ENERGY CENTER TX 12/9/2015 Simple Cycle Turbine 183 MW dry low NOX burners 9 PPMVD @ 15%
O2
3-HR ROLLING
AVERAGE PEAK
TX-0788 NECHES STATION TX 3/24/2016 Large Combustion Turbines; 25 MW 232 MW Dry low-NOx burners (DLN), good
combustion practices 9 PPM
TX-0794 HILL COUNTY GENERATING
FACILITY TX 4/7/2016 Simple cycle turbine 171 MW Emission controls consist of dry low-NOx
combustors (DLN).9 PPMVD @ 15%
O2
3-HR ROLLING
AVERAGE
TX-0819 GAINES COUNTY POWER PLANT TX 4/28/2017 Simple Cycle Turbine 227.5 MW
Dry Low NOx burners (control), natural gas,
good combustion practices, limited
operating hours (prevention)
9 PPMV 15% O2 3-H AVG
TX-0826 MUSTANG STATION TX 8/16/2017 Simple Cycle Turbine 162.8 MW Dry low-NOx burners 9 PPMVD
TX-0833 JACKSON COUNTY GENERATORS TX 1/26/2018 Combustion Turbines 920 MW Dry low NOx burners 9 PPMVD
TX-0691 PH ROBINSON ELECTRIC
GENERATING STATION TX 5/20/2014 (6) simple cycle turbines 65 MW DLN combustors 15 PPMVD @15% O2, 3-HR
ROLLING AVERAGE
VA-0326 DOSWELL ENERGY CENTER VA 10/4/2016 Two (2) GE 7FA simple cycle
combustion turbines 1961 MMBTU/HR Low NOx Burners/Combustion Technology 9 PPM VD/12 MO ROLLING
TOTAL
WV-0026 WAVERLY FACILITY WV 1/23/2017 GE Model 7FA Turbine 1571 MMBTU/hr Dry Low-NOx Combustion System (DLNB),
Water Injection 9 PPM NATURAL GAS
RBLC Search For Simple Cycle Combustion Turbines > 25 MW - VOC Determinations
RBLCID FACILITY NAME FACILITY
STATE Permit Date PROCESS NAME THROUGHPUT THROUGHPUT
UNIT CONTROL METHOD DESCRIPTION
MD-0044 COVE POINT LNG TERMINAL MD 6/9/2014 2 COMBUSTION TURBINES 130 MW
THE USE OF PROCESS FUEL GAS AND
PIPELINE NATURAL GAS, GOOD
COMBUSTION PRACTICES, AND USE OF AN
OXIDATION CATALYST
0.7 PPMVD @ 15%
O2
3-HOUR BLOCK
AVERAGE,
EXCLUDING SU/SD
NY-0103 CRICKET VALLEY ENERGY CENTER NY 2/3/2016 Turbines and duct burners 228 mw good combustion practices and oxidation
catalyst 0.7 PPMVD @ 15%
O2 1 H
LA-0331 CALCASIEU PASS LNG PROJECT LA 9/21/2018 Simple Cycle Combustion Turbines
(SCCT1 to SCCT3)927 MMBTU/hr
Proper Equipment Design, Proper
Operation, and Good Combustion
Practices.
1.4 PPMV 3 HOUR AVERAGE
PA-0306
TENASKA PA
PARTNERS/WESTMORELAND GEN
FAC
PA Large Combustion turbine Combined
Cycle 400 MMBtu/hr Ox Cat and good combustion practices 1.4 PPMVD @ 15%
O2
TX-0696 ROANS PRAIRIE GENERATING
STATION TX 9/22/2014 (3) simple cycle turbines 600 MW good combustion 1.4 PPMVD @15% O2 GE
OPTION
TX-0768 SHAWNEE ENERGY CENTER TX 10/9/2015 Simple cycle turbines 230 MW Pipeline quality natural gas; limited hours;
good combustion practices.1.4 PPMV
2,920 hours on a 12-
month rolling
average
LA-0331 CALCASIEU PASS LNG PROJECT LA 9/21/2018 Aeroderivative Simple Cycle
Combustion Turbine 263 MMBTU/hr
Proper Equipment Design, Proper
Operation, and Good Combustion
Practices.
1.5 PPMV 3 HOUR AVERAGE
LA-0316 CAMERON LNG FACILITY LA 2/17/2017 Gas turbines (9 units)1069 MMBTU/hr good combustion practices and fueled by
natural gas 1.6 PPMVD @15%O2
AK-0088 LIQUEFACTION PLANT AK 8/13/2020 Six Simle Cycle Gas-Fired Turbines 1113 MMBtu/hr Oxidation catalyst and good combustion
practices 2 PPMV @ 15%
O2 3-HOURS
NJ-0086 BAYONNNE ENERGY CENTER NJ 8/26/2016 Simple Cycle Stationary Turbines
firing Natural gas 2143980 MMBTU/YR
Add-on VOC control is Oxidation Catalyst,
and use of natural gas as fuel for pollution
prevention
2 PPMVD@15%O
2
3 H ROLLING AV
BASED ON ONE H
BLOCK AV
TX-0733 ANTELOPE ELK ENERGY CENTER TX 5/12/2015 Simple Cycle Turbine & Generator 202 MW Good combustion practices 2 PPMVD @ 15%
O2
TX-0764 NACOGDOCHES POWER ELECTRIC
GENERATING PLANT TX 10/14/2015 Natural Gas Simple Cycle Turbine
(232)232 MW Pipeline quality natural gas; limited hours;
good combustion practices.2 PPMVD @ 15%
O2
2,500 hours on a 12-
month rolling
average
TX-0788 NECHES STATION TX 3/24/2016 Large Combustion Turbines 232 MW good combustion practices 2 PPM
TX-0819 GAINES COUNTY POWER PLANT TX 4/28/2017 Simple Cycle Turbine 227.5 MW Pipeline quality natural gas; limited hours;
good combustion practices 2 PPMVD 15% O2
TX-0833 JACKSON COUNTY GENERATORS TX 1/26/2018 Combustion Turbines 920 MW Good combustion practices 2 PPMVD
TX-0908 NEWMAN POWER STATION TX 8/27/2021 Simple Cycle Turbine 230 MW Use of Natural gas, good combustion
practices, and oxidation catalyst 2 PPMVD
STANDARD EMISSION LIMIT
RBLC Search For Emergency Generators 100 - 2000 hp NOx Emissions
RBLCID FACILITY NAME FACILITY
STATE PROCESS NAME THROUGHPUT THROUGHPUT
UNIT CONTROL METHOD DESCRIPTION
AR-0140 BIG RIVER STEEL LLC AR EMERGENCY GENERATOR SN-62 625 HP
GOOD OPERATING PRACTICES, LIMITED
HOURS OF OPERATION, COMPLIANCE
WITH NSPS SUBPART IIII
0.4 G/KW-H
IN-0359 NUCOR STEEL IN Emergency Generator (CC-GEN2)500 Horsepower certified engine 3 G/HP-HR
KY-0110 NUCOR STEEL BRANDENBURG KY EP 11-01 - Melt Shop Emergency
Generator 260 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
2.98 G/HP-HR NMHC + NOX
KY-0110 NUCOR STEEL BRANDENBURG KY EP 11-02 - Reheat Furnace
Emergency Generator 190 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
2.98 G/HP-HR NMHC + NOX
KY-0110 NUCOR STEEL BRANDENBURG KY 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
KY-0110 NUCOR STEEL BRANDENBURG KY EP 11-03 - Rolling Mill Emergency
Generator 440 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
2.98 G/HP-HR NMHC + NOX
KY-0110 NUCOR STEEL BRANDENBURG KY EP 11-04 - IT Emergency Generator 190 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
2.98 G/HP-HR NMHC + NOX
KY-0110 NUCOR STEEL BRANDENBURG KY 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
LA-0292 HOLBROOK COMPRESSOR STATION LA Emergency Generators No. 1
&amp; No. 2 1341 HP
Good equipment design, proper
combustion techniques, use of low sulfur
fuel, and compliance with 40 CFR 60
Subpart IIII
14.16 LB/HR HOURLY
MAXIMUM
*LA-0312 ST. JAMES METHANOL PLANT LA DEG1-13 - Diesel Fired Emergency
Generator Engine (EQT0012)1474 horsepower Compliance with NSPS Subpart IIII 4.93 G/HP-HR
MD-0043 PERRYMAN GENERATING STATION MD EMERGENCY GENERATOR 1300 HP
GOOD COMBUSTION PRACTICES,
LIMITED HOURS OF OPERATION, AND
EXCLUSIVE USE OF ULSD
4.8 G/HP-H
MD-0044 COVE POINT LNG TERMINAL MD EMERGENCY GENERATOR 1550 HP GOOD COMBUSTION PRACTICES AND
DESIGNED TO ACHIEVE EMISSION LIMIT 4.8 G/HP-H COMBINED NOX +
NMHC
OH-0360 CARROLL COUNTY ENERGY OH Emergency generator (P003)1112 KW Purchased certified to the standards in
NSPS Subpart IIII 6.4 g/KW NMHC + NOx
OH-0363 NTE OHIO, LLC OH Emergency generator (P002)1100 KW
Emergency operation only, < 500
hours/year each for maintenance checks
and readiness testing designed to meet
NSPS Subpart IIII
29.01 LB/H
OH-0378 PTTGCA PETROCHEMICAL COMPLEX OH 1,000 kW Emergency Generators
(P008 - P010)1341 HP
certified to the meet the emissions
standards in Table 4 of 40 CFR Part 60,
Subpart IIII, shall employ good
combustion practices per the
manufacturer’s operating manual
4.8 G/HP-H SEE NOTES.
OK-0154 MOORELAND GENERATING STA OK DIESEL-FIRED EMERGENCY
GENERATOR ENGINE 1341 HP COMBUSTION CONTROL 0.011 LB/HP-HR
WV-0027 INWOOD WV Emergency Generator - ESDG14 900 bhp Engine Design 4.77 G/HP-HR
STANDARD EMISSION LIMIT
RBLC Search For Emergency Generators 100 - 2000 hp VOC Emissions
RBLCID FACILITY NAME FACILITY
STATE PROCESS NAME THROUGHPUT THROUGHPUT
UNIT CONTROL METHOD DESCRIPTION STANDARD EMISSION LIMIT
FL-0347 ANADARKO PETROLEUM
CORPORATION - EGOM FL Remotely Operated Vehicle
Emergency Generator 427 hp
Use of good combustion practices based
on the most recent manufacturer's
specifications issued for engines and
with turbocharger, aftercooler, and high
injection pressure
0
IN-0359 NUCOR STEEL IN Emergency Generator (CC-GEN2)500 Horsepower certified engine 1.13 G/HP-HR
KY-0110 NUCOR STEEL BRANDENBURG KY EP 11-01 - Melt Shop Emergency
Generator 260 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
0
KY-0110 NUCOR STEEL BRANDENBURG KY EP 11-02 - Reheat Furnace
Emergency Generator 190 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
0
KY-0110 NUCOR STEEL BRANDENBURG KY EP 10-07 - Air Separation Plant
Emergency Generator 700 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
0
KY-0110 NUCOR STEEL BRANDENBURG KY EP 11-03 - Rolling Mill Emergency
Generator 440 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
0
KY-0110 NUCOR STEEL BRANDENBURG KY EP 11-04 - IT Emergency Generator 190 HP
This EP is required to have a Good
Combustion and Operating Practices
(GCOP) Plan.
0
LA-0292 HOLBROOK COMPRESSOR
STATION LA Emergency Generators No. 1
&amp; No. 2 1341 HP
Good combustion practices consistent
with the manufacturer's
recommendations to maximize fuel
efficiency and minimize emissions
0.83 LB/HR HOURLY MAXIMUM
*LA-0312 ST. JAMES METHANOL PLANT LA DEG1-13 - Diesel Fired Emergency
Generator Engine (EQT0012)1474 horsepower Compliance with NSPS Subpart IIII 0.04 LB/HR
LA-0364 FG LA COMPLEX LA Emergency Generator Diesel
Engines 550 hp
Compliance with the limitations
imposed by 40 CFR 63 Subpart IIII and
operating the engine in accordance with
the engine manufacturer's instructions
and/or written procedures designed to
maximize combustion efficiency and
minimize fuel usage.
0
LA-0379 SHINTECH PLAQUEMINES PLANT 1 LA PVC Emergency Combustion
Equipment 2A and 2B 300 hp Compliance with 40 CFR 60 Subpart IIII.0.19 G/KW-HR
LA-0390 DERIDDER SAWMILL LA GEN-1 - Emergency Generator No.
1 750 horsepower
Good combustion practices and
maintenance and compliance with
applicable 40 CFR 60 Subpart JJJJ
limitation for VOC.
1.98 LB/HR
LA-0390 DERIDDER SAWMILL LA GEN-2 - Emergency Generator No.
2 750 horsepower
Good combustion practices and
maintenance and compliance with
applicable 40 CFR 60 Subpart JJJJ
limitation for VOC
1.98 LB/HR
LA-0390 DERIDDER SAWMILL LA GEN-3 - Emergency Generator No.
2 750 horsepower
Good Combustion practices and
maintenance and compliance with
applicable 40 CFR 60 Subpart JJJJ
limitations for VOC
1.98 LB/HR
MD-0044 COVE POINT LNG TERMINAL MD EMERGENCY GENERATOR 1550 HP
USE ONLY ULSD, GOOD COMBUSTION
PRACTICES, AND DESIGNED TO ACHIEVE
EMISSION LIMIT
4.8 G/HP-H COMBINED NOX +
NMHC
MI-0433 MEC NORTH, LLC AND MEC
SOUTH LLC MI EUEMENGINE (North Plant):
Emergency Engine 1341 HP Good combustion practices.0.86 LB/H HOURLY
MI-0433 MEC NORTH, LLC AND MEC
SOUTH LLC MI EUEMENGINE (South Plant):
Emergency Engine 1341 HP Good combustion practices 0.86 LB/H HOURLY
MI-0451 MEC NORTH, LLC MI EUEMENGINE (North Plant):
Emergency engine 1341 HP Good combustion practices 0.86 LB/H HOURLY
MI-0452 MEC SOUTH, LLC MI EUEMENGINE (South Plant):
Emergency engine 1341 HP Good combustion practices.0.86 LB/H HOURLY
OH-0360 CARROLL COUNTY ENERGY OH Emergency generator (P003)1112 KW Purchased certified to the standards in
NSPS Subpart IIII 0.79 G/KW-HR VOC
OH-0370 TRUMBULL ENERGY CENTER OH Emergency generator (P003)1529 HP State-of-the-art combustion design 6.4 G/KW-HR COMBINED NOX +
NMHC
OH-0372 OREGON ENERGY CENTER OH Emergency generator (P003)1529 HP State-of-the-art combustion design 6.4 G/KW-HR COMBINED NOX +
NMHC
OH-0377 HARRISON POWER OH 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.
OH-0378 PTTGCA PETROCHEMICAL
COMPLEX OH 1,000 kW Emergency Generators
(P008 - P010)1341 HP
certified to the meet the emissions
standards in Table 4 of 40 CFR Part 60,
Subpart IIII, shall employ good
combustion practices per the
manufacturer’s operating manual
6.4 G/KW-HR COMBINED NOX +
NMHC
OH-0387 INTEL OHIO SITE OH 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
OK-0154 MOORELAND GENERATING STA OK DIESEL-FIRED EMERGENCY
GENERATOR ENGINE 1341 HP COMBUSTION CONTROL.0.0007 LB/HP-HR
SC-0193 MERCEDES BENZ VANS, LLC SC Emergency Generators and Fire
Pump 1500 hp Must meet the standards of 40 CFR 60,
Subpart IIII 100 HR/YR 12 MONTH
ROLLING SUM
TX-0728 PEONY CHEMICAL
MANUFACTURING FACILITY TX Emergency Diesel Generator 1500 hp Minimized hours of operations Tier II
engine 0.7 LB/H
WI-0300 NEMADJI TRAIL ENERGY CENTER WI Emergency Diesel Generator (P07)1490 HP
Operation limited to 500 hours/year and
operate and maintain generator
according to the manufacturer’s
recommendations
0.32 G/HP-H
Reasonable Available Control Technology
Review for Gadsby Power Plant
AECOM
40
Appendix D – Control Cost Analyses
(1)
(2)
(3)
(4)
Step 4: Complete all of the cells highlighted in yellow. If you do not know the catalyst volume (Volcatalyst) or flue gas flow rate (Qflue gas), please enter "UNK" and
these values will be calculated for you. As noted in step 1 above, some of the highlighted cells are pre-populated with default values based on 2014 data. Users
should document the source of all values entered in accordance with what is recommended in the Control Cost Manual, and the use of actual values other than
the default values in this spreadsheet, if appropriately documented, is acceptable. You may also adjust the maintenance and administrative charges cost factors
(cells highlighted in blue) from their default values of 0.005 and 0.03, respectively. The default values for these two factors were developed for the CAMD
Integrated Planning Model (IPM). If you elect to adjust these factors, you must document why the alternative values used are appropriate.
Step 5: Once all of the data fields are complete, select the SCR Design Parameters tab to see the calculated design parameters and the Cost Estimate tab to view
the calculated cost data for the installation and operation of the SCR.
Air Pollution Control Cost Estimation Spreadsheet
For Selective Catalytic Reduction (SCR)
This spreadsheet allows users to estimate the capital and annualized costs for installing and operating a Selective Catalytic Reduction (SCR) control device. SCR is a
post-combustion control technology for reducing NOx emissions that employs a metal-based catalyst and an ammonia-based reducing reagent (urea or ammonia).
The reagent reacts selectively with the flue gas NOx within a specific temperature range to produce N2 and water vapor.
The calculation methodologies used in this spreadsheet are those presented in the U.S. EPA's Air Pollution Control Cost Manual. This spreadsheet is intended to
be used in combination with the SCR chapter and cost estimation methodology in the Control Cost Manual. For a detailed description of the SCR control
technology and the cost methodologies, see Section 4, Chapter 2 of the Air Pollution Control Cost Manual (as updated March 2019). A copy of the Control Cost
Manual is available on the U.S. EPA's "Technology Transfer Network" website at: http://www3.epa.gov/ttn/catc/products.html#cccinfo.
Step 1:Please select on the Data Inputs tab and click on the Reset Form button. This will clear many of the input cells and reset others to default values.
U.S. Environmental Protection Agency
Air Economics Group
Health and Environmental Impacts Division
Office of Air Quality Planning and Standards
(June 2019)
Instructions
The size and costs of the SCR are based primarily on five parameters: the boiler size or heat input, the type of fuel burned, the required level of NOx reduction,
reagent consumption rate, and catalyst costs. The equations for utility boilers are identical to those used in the IPM. However, the equations for industrial boilers
were developed based on the IPM equations for utility boilers. This approach provides study-level estimates (±30%) of SCR capital and annual costs. Default data
in the spreadsheet is taken from the SCR Control Cost Manual and other sources such as the U.S. Energy Information Administration (EIA). The actual costs may
vary from those calculated here due to site-specific conditions. Selection of the most cost-effective control option should be based on a detailed engineering
study and cost quotations from system suppliers. The methodology used in this spreadsheet is based on the U.S. EPA Clean Air Markets Division (CAMD)'s
Integrated Planning Model (IPM) (version 6). For additional information regarding the IPM, see the EPA Clean Air Markets webpage at
http://www.epa.gov/airmarkets/power-sector-modeling. The Agency wishes to note that all spreadsheet data inputs other than default data are merely available
to show an example calculation.
The spreadsheet can be used to estimate capital and annualized costs for applying SCR, and particularly to the following types of combustion units:
Coal-fired utility boilers with full load capacities greater than or equal to 25 MW.
Fuel oil- and natural gas-fired utility boilers with full load capacities greater than or equal to 25 MW.
Coal-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Fuel oil- and natural gas-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Step 2: Select the type of combustion unit (utility or industrial) using the pull down menu. Indicate whether the SCR is for new construction or retrofit of an
existing boiler. If the SCR will be installed on an existing boiler, enter a retrofit factor between 0.8 and 1.5. Use 1 for retrofits with an average level of difficulty.
For more difficult retrofits, you may use a retrofit factor greater than 1; however, you must document why the value used is appropriate.
Step 3:Select the type of fuel burned (coal, fuel oil, and natural gas) using the pull down menu. If you select fuel oil or natural gas, the HHV and NPHR fields will
be prepopulated with default values. If you select coal, then you must complete the coal input box by first selecting the type of coal burned from the drop down
menu. The weight percent sulfur content, HHV, and NPHR will be pre-populated with default factors based on the type of coal selected. However, we encourage
you to enter your own values for these parameters, if they are known, since the actual fuel parameters may vary from the default values provided. Method 1 is
pre-selected as the default method for calculating the catalyst replacement cost. For coal-fired units, you choose either method 1 or method 2 for calculating the
catalyst replacement cost by selecting appropriate radio button.
Is the combustion unit a utility or industrial boiler?What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
1.15
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)?65 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel?
1,045 Btu/scf
What is the estimated actual annual MWhs output?8,794 MWhs
Enter the net plant heat input rate (NPHR)8.2 MMBtu/MW
Fraction in
Coal Blend %S HHV (Btu/lb)
If the NPHR is not known, use the default NPHR value:Fuel Type Default NPHR 0 1.84 11,841
Coal 10 MMBtu/MW 0 0.41 8,826
Fuel Oil 11 MMBtu/MW 0 0.82 6,685
Natural Gas 8.2 MMBtu/MW
Plant Elevation 4240 Feet above sea level
Enter the following design parameters for the proposed SCR:
SCR Data Inputs Unit 1 (2017 Operating Data)
Enter the following data for your combustion unit:
Bituminous
Sub-Bituminous
Enter the sulfur content (%S) =percent by weight
Please enter a retrofit factor between 0.8 and 1.5 based on the level of difficulty. Enter 1 for
projects of average retrofit difficulty.
Coal Type
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV and %S. Please enter the actual values for
these parameters in the table below. If the actual value for any parameter is not known, you may use the
default values provided.
* NOTE: You must document why a retrofit factor of 1.15 is appropriate for
the proposed project.
Lignite
Please click the calculate button to calculate weighted average
values based on the data in the table above.
For coal-fired boilers, you may use either Method 1 or Method 2 to calculate the
catalyst replacement cost. The equations for both methods are shown on rows 85
and 86 on the Cost Estimate tab. Please select your preferred method:
Method 1
Method 2
Not applicable
Number of days the SCR operates (tSCR)24 days Number of SCR reactor chambers (nscr)1
Number of days the boiler operates (tplant)24 days Number of catalyst layers (Rlayer)3
Inlet NOx Emissions (NOxin) to SCR 0.093 lb/MMBtu Number of empty catalyst layers (Rempty)1
Outlet NOx Emissions (NOxout) from SCR 0.01 lb/MMBtu Ammonia Slip (Slip) provided by vendor 2 ppm
Stoichiometric Ratio Factor (SRF)1.050 UNK
*The SRF value of 1.05 is a default value. User should enter actual value, if known.
UNK
Estimated operating life of the catalyst (Hcatalyst)24,000 hours
Estimated SCR equipment life 30 Years*
Gas temperature at the SCR inlet (T)258
* For utility boilers, the typical equipment life of an SCR is at least 30 years.
455.5
Concentration of reagent as stored (Cstored)29 percent*
Density of reagent as stored (ρstored)56 lb/cubic feet*
Number of days reagent is stored (tstorage)14 days Densities of typical SCR reagents:
50% urea solution 71 lbs/ft3
29.4% aqueous NH3 56 lbs/ft3
Select the reagent used
Enter the cost data for the proposed SCR:
Desired dollar-year 2023
CEPCI for 2023 793.5 Enter the CEPCI value for 2023 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index September 2023
Annual Interest Rate (i)8.5 Percent
Reagent (Costreag)0.293 $/gallon for 29% ammonia*
Electricity (Costelect)0.0730 $/kWh
Catalyst cost (CC replace)227.00
Operator Labor Rate 60.00 $/hour (including benefits)*
Operator Hours/Day 4.00 hours/day*
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) =0.005
Administrative Charges Factor (ACF) =0.03
Volume of the catalyst layers (Volcatalyst)
(Enter "UNK" if value is not known)
Flue gas flow rate (Qfluegas)
(Enter "UNK" if value is not known)
Cubic feet
acfm
oF
ft3/min-MMBtu/hourBase case fuel gas volumetric flow rate factor (Qfuel)
*The reagent concentration of 29% and density of 56 lbs/cft are default
values for ammonia reagent. User should enter actual values for reagent, if
different from the default values provided.
* $0.293/gallon is a default value for 29% ammonia. User should enter actual value, if known.
Data for October 2023
* $227/cf is a default value for the catalyst cost based on 2016 prices. User should enter actual value,
if known.
$/cubic foot (includes removal and disposal/regeneration of existing
catalyst and installation of new catalyst
Current Bank Prime Rate October 2023
* $60/hour is a default value for the operator labor rate. User should enter actual value, if known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet
users. Use of other well-known cost indexes (e.g., M&S) is acceptable.
* 4 hours/day is a default value for the operator labor. User should enter actual value, if known.
Data Sources for Default Values Used in Calculations:
Data Element Default Value
Recommended data sources for site-specific
information
Reagent Cost ($/gallon)-Check with reagent vendors for current prices.
Electricity Cost ($/kWh)-Plant's utility bill or use U.S. Energy Information
Administration (EIA) data for most recent year.
Available at
https://www.eia.gov/electricity/monthly/epm_table_
grapher.php?t=epmt_5_6_a.
Percent sulfur content for Coal (% weight)Check with fuel supplier or use U.S. Energy
Information Administration (EIA) data for most recent
year." Available at
http://www.eia.gov/electricity/data/eia923/.
Higher Heating Value (HHV) (Btu/lb)1,033 Fuel supplier or use U.S. Energy Information
Administration (EIA) data for most recent year."
Available at
http://www.eia.gov/electricity/data/eia923/.
Catalyst Cost ($/cubic foot)227 Check with vendors for current prices.
Operator Labor Rate ($/hour)$60.00 Use payroll data, if available, or check current edition
of the Bureau of Labor Statistics, National
Occupational Employment and Wage Estimates –
United States
(https://www.bls.gov/oes/current/oes_nat.htm).
Interest Rate (Percent)5.5 Use known interest rate or use bank prime rate,
available at
https://www.federalreserve.gov/releases/h15/.
8.5% Bank prime rate - October 2023 rate from
https://www.federalreserve.gov/releases/h15/
Default bank prime rate
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.
Not applicable to units burning fuel oil or natural gas
2016 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics, U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-923, Power
Plant Operations Report. Available at http://www.eia.gov/electricity/data/eia923/.
If you used your own site-specific values, please enter the value
used and the reference source . . .
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.
Sources for Default Value
U.S. Geological Survey, Minerals Commodity Summaries, January 2017
(https://minerals.usgs.gov/minerals/pubs/commodity/nitrogen/mcs-2017-nitro.pdf
U.S. Energy Information Administration. Electric Power Annual 2016. Table 8.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
0.073 EIA data for October 2023
http://www.eia.gov/electricity/data.cfm#sales.
1044.6 Fuel sampling data provided by Gadsby for Unit 1 in 2017
Annual Emission Inventory.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) =Bmw x NPHR =533 MMBtu/hour
Maximum Annual MW Output (Bmw) =Bmw x 8760 =569,400 MWhs
Estimated Actual Annual MWhs Output (Boutput)
=8,794 MWhs
Heat Rate Factor (HRF) =NPHR/10 =0.82
Total System Capacity Factor (CFtotal) =(Boutput/Bmw)*(tscr/tplant) =0.015 fraction
Total operating time for the SCR (top) =CFtotal x 8760 =135 hours
NOx Removal Efficiency (EF) =(NOxin - NOxout)/NOxin =89.2 percent
NOx removed per hour =NOxin x EF x QB =44.24 lb/hour
Total NOx removed per year =(NOxin x EF x QB x top)/2000 =2.99 tons/year
NOx removal factor (NRF) =EF/80 =1.12
Volumetric flue gas flow rate (qflue gas) =Qfuel x QB x (460 + T)/(460 + 700)nscr =150,273 acfm
Space velocity (Vspace) =qflue gas/Volcatalyst =12.00 /hour
Residence Time 1/Vspace 0.08 hour
Coal Factor (CoalF) =
1 for oil and natural gas; 1 for bituminous; 1.05 for sub-
bituminous; 1.07 for lignite (weighted average is used for
coal blends)
1.00
SO2 Emission rate =(%S/100)x(64/32)*1x106)/HHV =
Elevation Factor (ELEVF) =14.7 psia/P =1.17
Atmospheric pressure at sea level (P) =2116 x [(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)* =12.6 psia
Retrofit Factor (RF)Retrofit to existing boiler 1.15
Catalyst Data:
Parameter Equation Calculated Value Units
Future worth factor (FWF) =(interest rate)(1/((1+ interest rate)Y -1), where Y = Hcatalyts/(tSCR x
24 hours) rounded to the nearest integer 0.0029 Fraction
Catalyst volume (Volcatalyst) =
2.81 x QB x EF adj x Slipadj x NOxadj x Sadj x (Tadj/Nscr)12,520.88 Cubic feet
Cross sectional area of the catalyst (Acatalyst) =qflue gas /(16ft/sec x 60 sec/min)157 ft2
Height of each catalyst layer (Hlayer) =(Volcatalyst/(Rlayer x Acatalyst)) + 1 (rounded to next highest
integer)28 feet
SCR Reactor Data:
Parameter Equation Calculated Value Units
Cross sectional area of the reactor (ASCR) =1.15 x Acatalyst 180 ft2
Reactor length and width dimensions for a square
reactor =(ASCR)0.5 13.4 feet
Reactor height =(Rlayer + Rempty) x (7ft + hlayer) + 9ft 148 feet
SCR Design Parameters Unit 1
The following design parameters for the SCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate tab.
Not applicable; factor applies only to
coal-fired boilers
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Reagent Data:
Type of reagent used Ammonia 17.03 g/mole
Density =56 lb/ft3
Parameter Equation Calculated Value
Reagent consumption rate (mreagent) =(NOxin x QB x EF x SRF x MWR)/MWNOx =17
Reagent Usage Rate (msol) =mreagent/Csol =59
(msol x 7.4805)/Reagent Density 8
Estimated tank volume for reagent storage =(msol x 7.4805 x tstorage x 24)/Reagent Density =2,700
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) =i (1+ i)n/(1+ i)n - 1 =0.0931
Where n = Equipment Life and i= Interest Rate
Other parameters Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) =A x 1,000 x 0.0056 x (CoalF x HRF)0.43 =334.23 kW
where A = Bmw for utility boilers
Units
lb/hour
lb/hour
gal/hour
gallons (storage needed to store a 14 day reagent supply rounded to the nearest 100 gallons)
Molecular Weight of Reagent (MW) =
For Oil-Fired Industrial Boilers between 275 and 5,500 MMBTU/hour :
For Natural Gas-Fired Industrial Boilers between 205 and 4,100 MMBTU/hour :
Total Capital Investment (TCI) =$16,360,223 in 2023 dollars
TCI = 86,380 x (200/BMW )0.35 x BMW x ELEVF x RF
SCR Cost Estimate Unit 1
Total Capital Investment (TCI)
TCI for Oil and Natural Gas Boilers
For Oil and Natural Gas-Fired Utility Boilers >500 MW:
TCI = 62,680 x BMW x ELEVF x RF
For Oil-Fired Industrial Boilers >5,500 MMBtu/hour:
For Natural Gas-Fired Industrial Boilers >4,100 MMBtu/hour:
TCI = 7,640 x QB x ELEVF x RF
TCI = 5,700 x QB x ELEVF x RF
TCI = 10,530 x (1,640/QB )0.35 x QB x ELEVF x RF
For Oil and Natural Gas-Fired Utility Boilers between 25MW and 500 MW:
TCI = 7,850 x (2,200/QB )0.35 x QB x ELEVF x RF
Direct Annual Costs (DAC) =$88,163 in 2023 dollars
Indirect Annual Costs (IDAC) =$1,524,291 in 2023 dollars
Total annual costs (TAC) = DAC + IDAC $1,612,455 in 2023 dollars
Annual Maintenance Cost =0.005 x TCI =$81,801 in 2023 dollars
Annual Reagent Cost =msol x Costreag x top =$314 in 2023 dollars
Annual Electricity Cost =P x Costelect x top =$3,301 in 2023 dollars
Annual Catalyst Replacement Cost =$2,747 in 2023 dollars
nscr x Volcat x (CCreplace/Rlayer) x FWF
Direct Annual Cost =$88,163 in 2023 dollars
Administrative Charges (AC) =0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost) =$1,154 in 2023 dollars
Capital Recovery Costs (CR)=CRF x TCI =$1,523,137 in 2023 dollars
Indirect Annual Cost (IDAC) =AC + CR =$1,524,291 in 2023 dollars
Total Annual Cost (TAC) =$1,612,455
NOx Removed =3 tons/year
Cost Effectiveness =$538,814 per ton of NOx removed in 2023 dollars
Total Annual Cost (TAC)
per year in 2023 dollars
Annual Costs
IDAC = Administrative Charges + Capital Recovery Costs
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Catalyst Cost)
Indirect Annual Cost (IDAC)
TAC = Direct Annual Costs + Indirect Annual Costs
(1)
(2)
(3)
(4)
Fuel oil- and natural gas-fired utility boilers with full load capacities greater than or equal to 25 MW.
Coal-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Fuel oil- and natural gas-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Step 2: Select the type of combustion unit (utility or industrial) using the pull down menu. Indicate whether the SCR is for new construction or retrofit of an
existing boiler. If the SCR will be installed on an existing boiler, enter a retrofit factor between 0.8 and 1.5. Use 1 for retrofits with an average level of difficulty.
For more difficult retrofits, you may use a retrofit factor greater than 1; however, you must document why the value used is appropriate.
Step 3:Select the type of fuel burned (coal, fuel oil, and natural gas) using the pull down menu. If you select fuel oil or natural gas, the HHV and NPHR fields will
be prepopulated with default values. If you select coal, then you must complete the coal input box by first selecting the type of coal burned from the drop down
menu. The weight percent sulfur content, HHV, and NPHR will be pre-populated with default factors based on the type of coal selected. However, we encourage
you to enter your own values for these parameters, if they are known, since the actual fuel parameters may vary from the default values provided. Method 1 is
pre-selected as the default method for calculating the catalyst replacement cost. For coal-fired units, you choose either method 1 or method 2 for calculating the
catalyst replacement cost by selecting appropriate radio button.
Step 4: Complete all of the cells highlighted in yellow. If you do not know the catalyst volume (Volcatalyst) or flue gas flow rate (Qflue gas), please enter "UNK" and
these values will be calculated for you. As noted in step 1 above, some of the highlighted cells are pre-populated with default values based on 2014 data. Users
should document the source of all values entered in accordance with what is recommended in the Control Cost Manual, and the use of actual values other than
the default values in this spreadsheet, if appropriately documented, is acceptable. You may also adjust the maintenance and administrative charges cost factors
(cells highlighted in blue) from their default values of 0.005 and 0.03, respectively. The default values for these two factors were developed for the CAMD
Integrated Planning Model (IPM). If you elect to adjust these factors, you must document why the alternative values used are appropriate.
Step 5: Once all of the data fields are complete, select the SCR Design Parameters tab to see the calculated design parameters and the Cost Estimate tab to view
the calculated cost data for the installation and operation of the SCR.
Air Pollution Control Cost Estimation Spreadsheet
For Selective Catalytic Reduction (SCR)
This spreadsheet allows users to estimate the capital and annualized costs for installing and operating a Selective Catalytic Reduction (SCR) control device. SCR is a
post-combustion control technology for reducing NOx emissions that employs a metal-based catalyst and an ammonia-based reducing reagent (urea or ammonia).
The reagent reacts selectively with the flue gas NOx within a specific temperature range to produce N2 and water vapor.
The calculation methodologies used in this spreadsheet are those presented in the U.S. EPA's Air Pollution Control Cost Manual. This spreadsheet is intended to
be used in combination with the SCR chapter and cost estimation methodology in the Control Cost Manual. For a detailed description of the SCR control
technology and the cost methodologies, see Section 4, Chapter 2 of the Air Pollution Control Cost Manual (as updated March 2019). A copy of the Control Cost
Manual is available on the U.S. EPA's "Technology Transfer Network" website at: http://www3.epa.gov/ttn/catc/products.html#cccinfo.
Step 1:Please select on the Data Inputs tab and click on the Reset Form button. This will clear many of the input cells and reset others to default values.
U.S. Environmental Protection Agency
Air Economics Group
Health and Environmental Impacts Division
Office of Air Quality Planning and Standards
(June 2019)
Instructions
The size and costs of the SCR are based primarily on five parameters: the boiler size or heat input, the type of fuel burned, the required level of NOx reduction,
reagent consumption rate, and catalyst costs. The equations for utility boilers are identical to those used in the IPM. However, the equations for industrial boilers
were developed based on the IPM equations for utility boilers. This approach provides study-level estimates (±30%) of SCR capital and annual costs. Default data
in the spreadsheet is taken from the SCR Control Cost Manual and other sources such as the U.S. Energy Information Administration (EIA). The actual costs may
vary from those calculated here due to site-specific conditions. Selection of the most cost-effective control option should be based on a detailed engineering
study and cost quotations from system suppliers. The methodology used in this spreadsheet is based on the U.S. EPA Clean Air Markets Division (CAMD)'s
Integrated Planning Model (IPM) (version 6). For additional information regarding the IPM, see the EPA Clean Air Markets webpage at
http://www.epa.gov/airmarkets/power-sector-modeling. The Agency wishes to note that all spreadsheet data inputs other than default data are merely available
to show an example calculation.
The spreadsheet can be used to estimate capital and annualized costs for applying SCR, and particularly to the following types of combustion units:
Coal-fired utility boilers with full load capacities greater than or equal to 25 MW.
Is the combustion unit a utility or industrial boiler?What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
1.15
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)?80 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel?
1,045 Btu/scf
What is the estimated actual annual MWhs output?11,675 MWhs
Enter the net plant heat input rate (NPHR)8.20 MMBtu/MW
Fraction in
Coal Blend %S HHV (Btu/lb)
If the NPHR is not known, use the default NPHR value:Fuel Type Default NPHR 0 1.84 11,841
Coal 10 MMBtu/MW 0 0.41 8,826
Fuel Oil 11 MMBtu/MW 0 0.82 6,685
Natural Gas 8.2 MMBtu/MW
Plant Elevation 4240 Feet above sea level
Enter the following design parameters for the proposed SCR:
Number of days the SCR operates (tSCR)29 days Number of SCR reactor chambers (nscr)1
Number of days the boiler operates (tplant)29 days Number of catalyst layers (Rlayer)3
Inlet NOx Emissions (NOxin) to SCR 0.082 lb/MMBtu Number of empty catalyst layers (Rempty)1
Outlet NOx Emissions (NOxout) from SCR 0.01 lb/MMBtu Ammonia Slip (Slip) provided by vendor 2 ppm
Stoichiometric Ratio Factor (SRF)1.050 UNK
*The SRF value of 1.05 is a default value. User should enter actual value, if known.
UNK
Estimated operating life of the catalyst (Hcatalyst)24,000 hours
Estimated SCR equipment life 30 Years*
Gas temperature at the SCR inlet (T)258
* For utility boilers, the typical equipment life of an SCR is at least 30 years.455.5
Concentration of reagent as stored (Cstored)29 percent*
Density of reagent as stored (ρstored)56 lb/cubic feet*
Number of days reagent is stored (tstorage)14 days Densities of typical SCR reagents:
50% urea solution 71 lbs/ft3
29.4% aqueous NH3 56 lbs/ft3
Select the reagent used
Enter the cost data for the proposed SCR:
Desired dollar-year 2023
CEPCI for 2023 793.5 Enter the CEPCI value for 2023 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index September 2023
Annual Interest Rate (i)8.5 Percent
Reagent (Costreag)0.293 $/gallon for 29% ammonia*
Electricity (Costelect)0.0730 $/kWh
Catalyst cost (CC replace)227.00
Operator Labor Rate 60.00 $/hour (including benefits)*
Operator Hours/Day 4.00 hours/day*
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) =0.005
Administrative Charges Factor (ACF) =0.03
Data Sources for Default Values Used in Calculations:
Data Element Default Value
Recommended data sources for site-specific
information
Reagent Cost ($/gallon)-Check with reagent vendors for current prices.
Electricity Cost ($/kWh)-Plant's utility bill or use U.S. Energy Information
Administration (EIA) data for most recent year.
Available at
https://www.eia.gov/electricity/monthly/epm_table_
grapher.php?t=epmt_5_6_a.
Percent sulfur content for Coal (% weight)Check with fuel supplier or use U.S. Energy
Information Administration (EIA) data for most
recent year." Available at
http://www.eia.gov/electricity/data/eia923/.
* $60/hour is a default value for the operator labor rate. User should enter actual value, if known.
Sources for Default Value
U.S. Geological Survey, Minerals Commodity Summaries, January 2017
(https://minerals.usgs.gov/minerals/pubs/commodity/nitrogen/mcs-2017-nitro.pdf
U.S. Energy Information Administration. Electric Power Annual 2016. Table 8.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
0.073 EIA data for October 2023
http://www.eia.gov/electricity/data.cfm#sales.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet
users. Use of other well-known cost indexes (e.g., M&S) is acceptable.
* 4 hours/day is a default value for the operator labor. User should enter actual value, if known.
* $0.293/gallon is a default value for 29% ammonia. User should enter actual value, if known.
Data for October 2023
* $227/cf is a default value for the catalyst cost based on 2016 prices. User should enter actual value, if
known.
$/cubic foot (includes removal and disposal/regeneration of existing
catalyst and installation of new catalyst
Current Bank Prime Rate October 2023
oF
ft3/min-MMBtu/hourBase case fuel gas volumetric flow rate factor (Qfuel)
*The reagent concentration of 29% and density of 56 lbs/cft are default
values for ammonia reagent. User should enter actual values for reagent, if
different from the default values provided.
Not applicable to units burning fuel oil or natural gas
If you used your own site-specific values, please enter the value
used and the reference source . . .
Volume of the catalyst layers (Volcatalyst)
(Enter "UNK" if value is not known)
Flue gas flow rate (Qfluegas)
(Enter "UNK" if value is not known)
Cubic feet
acfm
Lignite
Please click the calculate button to calculate weighted average
values based on the data in the table above.
For coal-fired boilers, you may use either Method 1 or Method 2 to calculate the
catalyst replacement cost. The equations for both methods are shown on rows 85
and 86 on the Cost Estimate tab. Please select your preferred method:
Data Inputs
Enter the following data for your combustion unit:
Bituminous
Sub-Bituminous
Enter the sulfur content (%S) =percent by weight
Please enter a retrofit factor between 0.8 and 1.5 based on the level of difficulty. Enter 1 for
projects of average retrofit difficulty.
Coal Type
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV and %S. Please enter the actual values for
these parameters in the table below. If the actual value for any parameter is not known, you may use the
default values provided.
* NOTE: You must document why a retrofit factor of 1.15 is appropriate for
the proposed project.
Method 1
Method 2
Not applicable
Higher Heating Value (HHV) (Btu/lb)1,033 Fuel supplier or use U.S. Energy Information
Administration (EIA) data for most recent year."
Available at
http://www.eia.gov/electricity/data/eia923/.
Catalyst Cost ($/cubic foot)227 Check with vendors for current prices.
Operator Labor Rate ($/hour)$60.00 Use payroll data, if available, or check current edition
of the Bureau of Labor Statistics, National
Occupational Employment and Wage Estimates –
United States
(https://www.bls.gov/oes/current/oes_nat.htm).
Interest Rate (Percent)5.5 Use known interest rate or use bank prime rate,
available at
https://www.federalreserve.gov/releases/h15/.
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.
1044.8 Fuel sampling data provided by Gadsby for Unit 2 in 2017
Annual Emission Inventory.
8.5% Bank prime rate - October 2023 rate from
https://www.federalreserve.gov/releases/h15/
Default bank prime rate
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.
2016 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics, U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-923, Power
Plant Operations Report. Available at http://www.eia.gov/electricity/data/eia923/.
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) =Bmw x NPHR =656 MMBtu/hour
Maximum Annual MW Output (Bmw) =Bmw x 8760 =700,800 MWhs
Estimated Actual Annual MWhs Output (Boutput)
=11,675 MWhs
Heat Rate Factor (HRF) =NPHR/10 =0.82
Total System Capacity Factor (CFtotal) =(Boutput/Bmw)*(tscr/tplant) =0.017 fraction
Total operating time for the SCR (top) =CFtotal x 8760 =146 hours
NOx Removal Efficiency (EF) =(NOxin - NOxout)/NOxin =87.8 percent
NOx removed per hour =NOxin x EF x QB =47.23 lb/hour
Total NOx removed per year =(NOxin x EF x QB x top)/2000 =3.45 tons/year
NOx removal factor (NRF) =EF/80 =1.10
Volumetric flue gas flow rate (qflue gas) =Qfuel x QB x (460 + T)/(460 + 700)nscr =184,952 acfm
Space velocity (Vspace) =qflue gas/Volcatalyst =12.20 /hour
Residence Time 1/Vspace 0.08 hour
Coal Factor (CoalF) =
1 for oil and natural gas; 1 for bituminous; 1.05 for sub-
bituminous; 1.07 for lignite (weighted average is used for
coal blends)
1.00
SO2 Emission rate =(%S/100)x(64/32)*1x106)/HHV =
Elevation Factor (ELEVF) =14.7 psia/P =1.17
Atmospheric pressure at sea level (P) =2116 x [(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)* =12.6 psia
Retrofit Factor (RF)Retrofit to existing boiler 1.15
Catalyst Data:
Parameter Equation Calculated Value Units
Future worth factor (FWF) =(interest rate)(1/((1+ interest rate)Y -1), where Y = Hcatalyts/(tSCR x
24 hours) rounded to the nearest integer 0.0057 Fraction
Catalyst volume (Volcatalyst) =
2.81 x QB x EF adj x Slipadj x NOxadj x Sadj x (Tadj/Nscr)15,158.42 Cubic feet
Cross sectional area of the catalyst (Acatalyst) =qflue gas /(16ft/sec x 60 sec/min)193 ft2
Height of each catalyst layer (Hlayer) =(Volcatalyst/(Rlayer x Acatalyst)) + 1 (rounded to next highest
integer)27 feet
SCR Reactor Data:
Parameter Equation Calculated Value Units
Cross sectional area of the reactor (ASCR) =1.15 x Acatalyst 222 ft2
Reactor length and width dimensions for a square
reactor =(ASCR)0.5 14.9 feet
Reactor height =(Rlayer + Rempty) x (7ft + hlayer) + 9ft 146 feet
Not applicable; factor applies only to
coal-fired boilers
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
SCR Design Parameters
The following design parameters for the SCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate tab.
Reagent Data:
Type of reagent used Ammonia 17.03 g/mole
Density =56 lb/ft3
Parameter Equation Calculated Value
Reagent consumption rate (mreagent) =(NOxin x QB x EF x SRF x MWR)/MWNOx =18
Reagent Usage Rate (msol) =mreagent/Csol =63
(msol x 7.4805)/Reagent Density 8
Estimated tank volume for reagent storage =(msol x 7.4805 x tstorage x 24)/Reagent Density =2,900
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) =i (1+ i)n/(1+ i)n - 1 =0.0931
Where n = Equipment Life and i= Interest Rate
Other parameters Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) =A x 1,000 x 0.0056 x (CoalF x HRF)0.43 =411.36 kW
where A = Bmw for utility boilers
lb/hour
gal/hour
gallons (storage needed to store a 14 day reagent supply rounded to the nearest 100 gallons)
Molecular Weight of Reagent (MW) =
Units
lb/hour
For Oil-Fired Industrial Boilers between 275 and 5,500 MMBTU/hour :
For Natural Gas-Fired Industrial Boilers between 205 and 4,100 MMBTU/hour :
Total Capital Investment (TCI) =$18,724,233 in 2023 dollars
TCI = 7,850 x (2,200/QB )0.35 x QB x ELEVF x RF
Cost Estimate
Total Capital Investment (TCI)
TCI for Oil and Natural Gas Boilers
For Oil and Natural Gas-Fired Utility Boilers >500 MW:
TCI = 62,680 x BMW x ELEVF x RF
For Oil-Fired Industrial Boilers >5,500 MMBtu/hour:
For Natural Gas-Fired Industrial Boilers >4,100 MMBtu/hour:
TCI = 7,640 x QB x ELEVF x RF
TCI = 5,700 x QB x ELEVF x RF
TCI = 10,530 x (1,640/QB )0.35 x QB x ELEVF x RF
For Oil and Natural Gas-Fired Utility Boilers between 25MW and 500 MW:
TCI = 86,380 x (200/BMW )0.35 x BMW x ELEVF x RF
Direct Annual Costs (DAC) =$104,903 in 2023 dollars
Indirect Annual Costs (IDAC) =$1,744,558 in 2023 dollars
Total annual costs (TAC) = DAC + IDAC $1,849,461 in 2023 dollars
Annual Maintenance Cost =0.005 x TCI =$93,621 in 2023 dollars
Annual Reagent Cost =msol x Costreag x top =$362 in 2023 dollars
Annual Electricity Cost =P x Costelect x top =$4,382 in 2023 dollars
Annual Catalyst Replacement Cost =$6,538 in 2023 dollars
nscr x Volcat x (CCreplace/Rlayer) x FWF
Direct Annual Cost =$104,903 in 2023 dollars
Administrative Charges (AC) =0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost) =$1,332 in 2023 dollars
Capital Recovery Costs (CR)=CRF x TCI =$1,743,226 in 2023 dollars
Indirect Annual Cost (IDAC) =AC + CR =$1,744,558 in 2023 dollars
Total Annual Cost (TAC) =$1,849,461
NOx Removed =3 tons/year
Cost Effectiveness =$536,646 per ton of NOx removed in 2023 dollars
Total Annual Cost (TAC)
per year in 2023 dollars
Annual Costs
IDAC = Administrative Charges + Capital Recovery Costs
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Catalyst Cost)
Indirect Annual Cost (IDAC)
TAC = Direct Annual Costs + Indirect Annual Costs
(1)
(2)
(3)
(4)
Fuel oil- and natural gas-fired utility boilers with full load capacities greater than or equal to 25 MW.
Coal-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Fuel oil- and natural gas-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Step 2: Select the type of combustion unit (utility or industrial) using the pull down menu. Indicate whether the SCR is for new construction or retrofit of an
existing boiler. If the SCR will be installed on an existing boiler, enter a retrofit factor between 0.8 and 1.5. Use 1 for retrofits with an average level of difficulty.
For more difficult retrofits, you may use a retrofit factor greater than 1; however, you must document why the value used is appropriate.
Step 3:Select the type of fuel burned (coal, fuel oil, and natural gas) using the pull down menu. If you select fuel oil or natural gas, the HHV and NPHR fields will
be prepopulated with default values. If you select coal, then you must complete the coal input box by first selecting the type of coal burned from the drop down
menu. The weight percent sulfur content, HHV, and NPHR will be pre-populated with default factors based on the type of coal selected. However, we encourage
you to enter your own values for these parameters, if they are known, since the actual fuel parameters may vary from the default values provided. Method 1 is
pre-selected as the default method for calculating the catalyst replacement cost. For coal-fired units, you choose either method 1 or method 2 for calculating the
catalyst replacement cost by selecting appropriate radio button.
Step 4: Complete all of the cells highlighted in yellow. If you do not know the catalyst volume (Volcatalyst) or flue gas flow rate (Qflue gas), please enter "UNK" and
these values will be calculated for you. As noted in step 1 above, some of the highlighted cells are pre-populated with default values based on 2014 data. Users
should document the source of all values entered in accordance with what is recommended in the Control Cost Manual, and the use of actual values other than
the default values in this spreadsheet, if appropriately documented, is acceptable. You may also adjust the maintenance and administrative charges cost factors
(cells highlighted in blue) from their default values of 0.005 and 0.03, respectively. The default values for these two factors were developed for the CAMD
Integrated Planning Model (IPM). If you elect to adjust these factors, you must document why the alternative values used are appropriate.
Step 5: Once all of the data fields are complete, select the SCR Design Parameters tab to see the calculated design parameters and the Cost Estimate tab to view
the calculated cost data for the installation and operation of the SCR.
Air Pollution Control Cost Estimation Spreadsheet
For Selective Catalytic Reduction (SCR)
This spreadsheet allows users to estimate the capital and annualized costs for installing and operating a Selective Catalytic Reduction (SCR) control device. SCR is a
post-combustion control technology for reducing NOx emissions that employs a metal-based catalyst and an ammonia-based reducing reagent (urea or ammonia).
The reagent reacts selectively with the flue gas NOx within a specific temperature range to produce N2 and water vapor.
The calculation methodologies used in this spreadsheet are those presented in the U.S. EPA's Air Pollution Control Cost Manual. This spreadsheet is intended to
be used in combination with the SCR chapter and cost estimation methodology in the Control Cost Manual. For a detailed description of the SCR control
technology and the cost methodologies, see Section 4, Chapter 2 of the Air Pollution Control Cost Manual (as updated March 2019). A copy of the Control Cost
Manual is available on the U.S. EPA's "Technology Transfer Network" website at: http://www3.epa.gov/ttn/catc/products.html#cccinfo.
Step 1:Please select on the Data Inputs tab and click on the Reset Form button. This will clear many of the input cells and reset others to default values.
U.S. Environmental Protection Agency
Air Economics Group
Health and Environmental Impacts Division
Office of Air Quality Planning and Standards
(June 2019)
Instructions
The size and costs of the SCR are based primarily on five parameters: the boiler size or heat input, the type of fuel burned, the required level of NOx reduction,
reagent consumption rate, and catalyst costs. The equations for utility boilers are identical to those used in the IPM. However, the equations for industrial boilers
were developed based on the IPM equations for utility boilers. This approach provides study-level estimates (±30%) of SCR capital and annual costs. Default data
in the spreadsheet is taken from the SCR Control Cost Manual and other sources such as the U.S. Energy Information Administration (EIA). The actual costs may
vary from those calculated here due to site-specific conditions. Selection of the most cost-effective control option should be based on a detailed engineering
study and cost quotations from system suppliers. The methodology used in this spreadsheet is based on the U.S. EPA Clean Air Markets Division (CAMD)'s
Integrated Planning Model (IPM) (version 6). For additional information regarding the IPM, see the EPA Clean Air Markets webpage at
http://www.epa.gov/airmarkets/power-sector-modeling. The Agency wishes to note that all spreadsheet data inputs other than default data are merely available
to show an example calculation.
The spreadsheet can be used to estimate capital and annualized costs for applying SCR, and particularly to the following types of combustion units:
Coal-fired utility boilers with full load capacities greater than or equal to 25 MW.
Is the combustion unit a utility or industrial boiler?What type of fuel does the unit burn?
Is the SCR for a new boiler or retrofit of an existing boiler?
1.15
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)?105 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel?
1,044 Btu/scf
What is the estimated actual annual MWhs output?22,554 MWhs
Enter the net plant heat input rate (NPHR)8.20 MMBtu/MW
Fraction in
Coal Blend %S HHV (Btu/lb)
If the NPHR is not known, use the default NPHR value:Fuel Type Default NPHR 0 1.84 11,841
Coal 10 MMBtu/MW 0 0.41 8,826
Fuel Oil 11 MMBtu/MW 0 0.82 6,685
Natural Gas 8.2 MMBtu/MW
Plant Elevation 4240 Feet above sea level
Enter the following design parameters for the proposed SCR:
Lignite
Please click the calculate button to calculate weighted average
values based on the data in the table above.
For coal-fired boilers, you may use either Method 1 or Method 2 to calculate the
catalyst replacement cost. The equations for both methods are shown on rows 85
and 86 on the Cost Estimate tab. Please select your preferred method:
Data Inputs
Enter the following data for your combustion unit:
Bituminous
Sub-Bituminous
Enter the sulfur content (%S) =percent by weight
Please enter a retrofit factor between 0.8 and 1.5 based on the level of difficulty. Enter 1 for
projects of average retrofit difficulty.
Coal Type
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV and %S. Please enter the actual values for
these parameters in the table below. If the actual value for any parameter is not known, you may use the
default values provided.
* NOTE: You must document why a retrofit factor of 1.15 is appropriate for
the proposed project.
Method 1
Method 2
Not applicable
Number of days the SCR operates (tSCR)33 days Number of SCR reactor chambers (nscr)1
Number of days the boiler operates (tplant)33 days Number of catalyst layers (Rlayer)3
Inlet NOx Emissions (NOxin) to SCR 0.0911 lb/MMBtu Number of empty catalyst layers (Rempty)1
Outlet NOx Emissions (NOxout) from SCR 0.01 lb/MMBtu Ammonia Slip (Slip) provided by vendor 2 ppm
Stoichiometric Ratio Factor (SRF)1.050 UNK
*The SRF value of 1.05 is a default value. User should enter actual value, if known.
UNK
Estimated operating life of the catalyst (Hcatalyst)24,000 hours
Estimated SCR equipment life 30 Years*
Gas temperature at the SCR inlet (T)258
* For utility boilers, the typical equipment life of an SCR is at least 30 years.455.5
Concentration of reagent as stored (Cstored)29 percent*
Density of reagent as stored (ρstored)56 lb/cubic feet*
Number of days reagent is stored (tstorage)14 days Densities of typical SCR reagents:
50% urea solution 71 lbs/ft3
29.4% aqueous NH3 56 lbs/ft3
Select the reagent used
Enter the cost data for the proposed SCR:
Desired dollar-year 2023
CEPCI for 2023 793.5 Enter the CEPCI value for 2023 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index September 2023
Annual Interest Rate (i)8.5 Percent
Reagent (Costreag)0.293 $/gallon for 29% ammonia*
Electricity (Costelect)0.0730 $/kWh
Catalyst cost (CC replace)227.00
Operator Labor Rate 60.00 $/hour (including benefits)*
Operator Hours/Day 4.00 hours/day*
Maintenance and Administrative Charges Cost Factors:
0.015
Maintenance Cost Factor (MCF) =0.005
Administrative Charges Factor (ACF) =0.03
* $60/hour is a default value for the operator labor rate. User should enter actual value, if known.
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet
users. Use of other well-known cost indexes (e.g., M&S) is acceptable.
* 4 hours/day is a default value for the operator labor. User should enter actual value, if known.
* $0.293/gallon is a default value for 29% ammonia. User should enter actual value, if known.
Data for October 2023
* $227/cf is a default value for the catalyst cost based on 2016 prices. User should enter actual value, if
known.
$/cubic foot (includes removal and disposal/regeneration of existing
catalyst and installation of new catalyst
Current Bank Prime Rate October 2023
oF
ft3/min-MMBtu/hourBase case fuel gas volumetric flow rate factor (Qfuel)
*The reagent concentration of 29% and density of 56 lbs/cft are default
values for ammonia reagent. User should enter actual values for reagent, if
different from the default values provided.
Volume of the catalyst layers (Volcatalyst)
(Enter "UNK" if value is not known)
Flue gas flow rate (Qfluegas)
(Enter "UNK" if value is not known)
Cubic feet
acfm
Data Sources for Default Values Used in Calculations:
Data Element Default Value
Recommended data sources for site-specific
information
Reagent Cost ($/gallon)-Check with reagent vendors for current prices.
Electricity Cost ($/kWh)-Plant's utility bill or use U.S. Energy Information
Administration (EIA) data for most recent year.
Available at
https://www.eia.gov/electricity/monthly/epm_table_
grapher.php?t=epmt_5_6_a.
Percent sulfur content for Coal (% weight)Check with fuel supplier or use U.S. Energy
Information Administration (EIA) data for most
recent year." Available at
http://www.eia.gov/electricity/data/eia923/.
Higher Heating Value (HHV) (Btu/lb)1,033 Fuel supplier or use U.S. Energy Information
Administration (EIA) data for most recent year."
Available at
http://www.eia.gov/electricity/data/eia923/.
Catalyst Cost ($/cubic foot)227 Check with vendors for current prices.
Operator Labor Rate ($/hour)$60.00 Use payroll data, if available, or check current edition
of the Bureau of Labor Statistics, National
Occupational Employment and Wage Estimates –
United States
(https://www.bls.gov/oes/current/oes_nat.htm).
Interest Rate (Percent)5.5 Use known interest rate or use bank prime rate,
available at
https://www.federalreserve.gov/releases/h15/.
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.
Sources for Default Value
U.S. Geological Survey, Minerals Commodity Summaries, January 2017
(https://minerals.usgs.gov/minerals/pubs/commodity/nitrogen/mcs-2017-nitro.pdf
U.S. Energy Information Administration. Electric Power Annual 2016. Table 8.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
0.073 EIA data for October 2023
http://www.eia.gov/electricity/data.cfm#sales.
1043.7 Fuel sampling data provided by Gadsby for Unit 3 in 2017
Annual Emission Inventory.
8.5% Bank prime rate - October 2023 rate from
https://www.federalreserve.gov/releases/h15/
Default bank prime rate
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.
Not applicable to units burning fuel oil or natural gas
2016 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics, U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-923, Power
Plant Operations Report. Available at http://www.eia.gov/electricity/data/eia923/.
If you used your own site-specific values, please enter the value
used and the reference source . . .
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) =Bmw x NPHR =861 MMBtu/hour
Maximum Annual MW Output (Bmw) =Bmw x 8760 =919,800 MWhs
Estimated Actual Annual MWhs Output (Boutput)
=22,554 MWhs
Heat Rate Factor (HRF) =NPHR/10 =0.82
Total System Capacity Factor (CFtotal) =(Boutput/Bmw)*(tscr/tplant) =0.025 fraction
Total operating time for the SCR (top) =CFtotal x 8760 =215 hours
NOx Removal Efficiency (EF) =(NOxin - NOxout)/NOxin =89.0 percent
NOx removed per hour =NOxin x EF x QB =69.83 lb/hour
Total NOx removed per year =(NOxin x EF x QB x top)/2000 =7.50 tons/year
NOx removal factor (NRF) =EF/80 =1.11
Volumetric flue gas flow rate (qflue gas) =Qfuel x QB x (460 + T)/(460 + 700)nscr =242,749 acfm
Space velocity (Vspace) =qflue gas/Volcatalyst =12.03 /hour
Residence Time 1/Vspace 0.08 hour
Coal Factor (CoalF) =
1 for oil and natural gas; 1 for bituminous; 1.05 for sub-
bituminous; 1.07 for lignite (weighted average is used for
coal blends)
1.00
SO2 Emission rate =(%S/100)x(64/32)*1x106)/HHV =
Elevation Factor (ELEVF) =14.7 psia/P =1.17
Atmospheric pressure at sea level (P) =2116 x [(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)* =12.6 psia
Retrofit Factor (RF)Retrofit to existing boiler 1.15
Catalyst Data:
Parameter Equation Calculated Value Units
Future worth factor (FWF) =(interest rate)(1/((1+ interest rate)Y -1), where Y = Hcatalyts/(tSCR x
24 hours) rounded to the nearest integer 0.0081 Fraction
Catalyst volume (Volcatalyst) =
2.81 x QB x EF adj x Slipadj x NOxadj x Sadj x (Tadj/Nscr)20,173.11 Cubic feet
Cross sectional area of the catalyst (Acatalyst) =qflue gas /(16ft/sec x 60 sec/min)253 ft2
Height of each catalyst layer (Hlayer) =(Volcatalyst/(Rlayer x Acatalyst)) + 1 (rounded to next highest
integer)28 feet
SCR Reactor Data:
Parameter Equation Calculated Value Units
Cross sectional area of the reactor (ASCR) =1.15 x Acatalyst 291 ft2
Reactor length and width dimensions for a square
reactor =(ASCR)0.5 17.1 feet
Reactor height =(Rlayer + Rempty) x (7ft + hlayer) + 9ft 147 feet
Not applicable; factor applies only to
coal-fired boilers
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
SCR Design Parameters
The following design parameters for the SCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate tab.
Reagent Data:
Type of reagent used Ammonia 17.03 g/mole
Density =56 lb/ft3
Parameter Equation Calculated Value
Reagent consumption rate (mreagent) =(NOxin x QB x EF x SRF x MWR)/MWNOx =27
Reagent Usage Rate (msol) =mreagent/Csol =94
(msol x 7.4805)/Reagent Density 13
Estimated tank volume for reagent storage =(msol x 7.4805 x tstorage x 24)/Reagent Density =4,300
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) =i (1+ i)n/(1+ i)n - 1 =0.0931
Where n = Equipment Life and i= Interest Rate
Other parameters Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) =A x 1,000 x 0.0056 x (CoalF x HRF)0.43 =539.90 kW
where A = Bmw for utility boilers
lb/hour
gal/hour
gallons (storage needed to store a 14 day reagent supply rounded to the nearest 100 gallons)
Molecular Weight of Reagent (MW) =
Units
lb/hour
For Oil-Fired Industrial Boilers between 275 and 5,500 MMBTU/hour :
For Natural Gas-Fired Industrial Boilers between 205 and 4,100 MMBTU/hour :
Total Capital Investment (TCI) =$22,344,395 in 2023 dollars
TCI = 7,850 x (2,200/QB )0.35 x QB x ELEVF x RF
Cost Estimate
Total Capital Investment (TCI)
TCI for Oil and Natural Gas Boilers
For Oil and Natural Gas-Fired Utility Boilers >500 MW:
TCI = 62,680 x BMW x ELEVF x RF
For Oil-Fired Industrial Boilers >5,500 MMBtu/hour:
For Natural Gas-Fired Industrial Boilers >4,100 MMBtu/hour:
TCI = 7,640 x QB x ELEVF x RF
TCI = 5,700 x QB x ELEVF x RF
TCI = 10,530 x (1,640/QB )0.35 x QB x ELEVF x RF
For Oil and Natural Gas-Fired Utility Boilers between 25MW and 500 MW:
TCI = 86,380 x (200/BMW )0.35 x BMW x ELEVF x RF
Direct Annual Costs (DAC) =$133,339 in 2023 dollars
Indirect Annual Costs (IDAC) =$2,081,841 in 2023 dollars
Total annual costs (TAC) = DAC + IDAC $2,215,180 in 2023 dollars
Annual Maintenance Cost =0.005 x TCI =$111,722 in 2023 dollars
Annual Reagent Cost =msol x Costreag x top =$787 in 2023 dollars
Annual Electricity Cost =P x Costelect x top =$8,466 in 2023 dollars
Annual Catalyst Replacement Cost =$12,364 in 2023 dollars
nscr x Volcat x (CCreplace/Rlayer) x FWF
Direct Annual Cost =$133,339 in 2023 dollars
Administrative Charges (AC) =0.03 x (Operator Cost + 0.4 x Annual Maintenance Cost) =$1,578 in 2023 dollars
Capital Recovery Costs (CR)=CRF x TCI =$2,080,263 in 2023 dollars
Indirect Annual Cost (IDAC) =AC + CR =$2,081,841 in 2023 dollars
Total Annual Cost (TAC) =$2,215,180
NOx Removed =7 tons/year
Cost Effectiveness =$295,377 per ton of NOx removed in 2023 dollars
Total Annual Cost (TAC)
per year in 2023 dollars
Annual Costs
IDAC = Administrative Charges + Capital Recovery Costs
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Catalyst Cost)
Indirect Annual Cost (IDAC)
TAC = Direct Annual Costs + Indirect Annual Costs
(1)
(2)
(3)
(4)
Step 4: Complete all of the cells highlighted in yellow. As noted in step 1 above, some of the highlighted cells are pre-populated with default values based on 2016
data. Users should document the source of all values entered in accordance with what is recommended in the Control Cost Manual, and the use of actual values
other than the default values in this spreadsheet, if appropriately documented, is acceptable. You may also adjust the maintenance and administrative charges
cost factors (cells highlighted in blue) from their default values of 0.015 and 0.03, respectively. The default values for these two factors were developed for the
CAMD Integrated Planning Model (IPM). If you elect to adjust these factors, you must document why the alternative values used are appropriate.
Step 5: Once all of the data fields are complete, select the SNCR Design Parameters tab to see the calculated design parameters and the Cost Estimate tab to
view the calculated cost data for the installation and operation of the SNCR.
Air Pollution Control Cost Estimation Spreadsheet
For Selective Non-Catalytic Reduction (SNCR)
This spreadsheet allows users to estimate the capital and annualized costs for installing and operating a Selective Non-Catalytic Reduction (SNCR) control device.
SNCR is a post-combustion control technology for reducing NOx emissions by injecting an ammonia-base reagent (urea or ammonia) into the furnace at a location
where the temperature is in the appropriate range for ammonia radicals to react with NOx to form nitrogen and water.
The calculation methodologies used in this spreadsheet are those presented in the U.S. EPA's Air Pollution Control Cost Manual. This spreadsheet is intended to
be used in combination with the SNCR chapter and cost estimation methodology in the Control Cost Manual. For a detailed description of the SNCR control
technology and the cost methodologies, see Section 4, Chapter 1 of the Air Pollution Control Cost Manual (as updated April 2019). A copy of the Control Cost
Manual is available on the U.S. EPA's "Technology Transfer Network" website at: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-
reports-and-guidance-air-pollution.
Step 1:Please select on the Data Inputs tab and click on the Reset Form button. This will reset the NSR, plant elevation, estimated equipment life, desired dollar
year, cost index (to match desired dollar year), annual interest rate, unit costs for fuel, electricity, reagent, water and ash disposal, and the cost factors for
maintenance cost and administrative charges. All other data entry fields will be blank.
U.S. Environmental Protection Agency
Air Economics Group
Health and Environmental Impacts Division
Office of Air Quality Planning and Standards
(March 2021)
Instructions
The methodology used in this spreadsheet is based on the U.S. EPA Clean Air Markets Division (CAMD)'s Integrated Planning Model (IPM version 6). The size and
costs of the SNCR are based primarily on four parameters: the boiler size or heat input, the type of fuel burned, the required level of NOx reduction, and the
reagent consumption. This approach provides study-level estimates (±30%) of SNCR capital and annual costs. Default data in the spreadsheet is taken from the
SNCR Control Cost Manual and other sources such as the U.S. Energy Information Administration (EIA). The actual costs may vary from those calculated here due
to site-specific conditions, such as the boiler configuration and fuel type. Selection of the most cost-effective control option should be based on a detailed
engineering study and cost quotations from system suppliers. For additional information regarding the IPM, see the EPA Clean Air Markets webpage at
http://www.epa.gov/airmarkets/power-sector-modeling. The Agency wishes to note that all spreadsheet data inputs other than default data are merely available
to show an example calculation.
The spreadsheet can be used to estimate capital and annualized costs for applying SNCR, and particularly to the following types of combustion units:
Coal-fired utility boilers with full load capacities greater than or equal to 25 MW.
Fuel oil- and natural gas-fired utility boilers with full load capacities greater than or equal to 25 MW.
Coal-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Fuel oil- and natural gas-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Step 2: Select the type of combustion unit (utility or industrial) using the pull down menu. Indicate whether the SNCR is for new construction or retrofit of an
existing boiler. If the SNCR will be installed on an existing boiler, enter a retrofit factor equal to or greater than 0.84. Use 1 for retrofits with an average level of
difficulty. For more difficult retrofits, you may use a retrofit factor greater than 1; however, you must document why the value used is appropriate.
Step 3:Select the type of fuel burned (coal, fuel oil, and natural gas) using the pull down menu. If you selected coal, select the type of coal burned from the drop
down menu. The NOx emissions rate, weight percent coal ash and NPHR will be pre-populated with default factors based on the type of coal selected. However,
we encourage you to enter your own values for these parameters, if they are known, since the actual fuel parameters may vary from the default values provided.
Is the combustion unit a utility or industrial boiler?What type of fuel does the unit burn?
Is the SNCR for a new boiler or retrofit of an existing boiler?
1.15
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)?65 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel?1,045 Btu/scf
What is the estimated actual annual MWh output?8,794 MWh
Is the boiler a fluid-bed boiler?
Enter the net plant heat input rate (NPHR)8.2 MMBtu/MW
Fraction in
Coal Blend %S %Ash HHV (Btu/lb)
Fuel Cost
($/MMBtu)
If the NPHR is not known, use the default NPHR value:Fuel Type Default NPHR 0 1.84 9.23 12,000 2.4
Coal 10 MMBtu/MW 0 0.41 5.84 9,000 1.89
Fuel Oil 11 MMBtu/MW 0 0.82 13.6 6,626 1.74
Natural Gas 8.2 MMBtu/MW
SNCR Data Inputs Unit 1 (2017 Operating Data)
Enter the following data for your combustion unit:
Bituminous
Sub-Bituminous
Lignite
Please click the calculate button to calculate weighted
values based on the data in the table above.
Please enter a retrofit factor equal to or greater than 0.84 based on the level of difficulty.
Enter 1 for projects of average retrofit difficulty.* NOTE: You must document why a retrofit factor of 1.15 is appropriate
for the proposed project.
Ash content (%Ash):
Enter the sulfur content (%S) =
or
Select the appropriate SO2 emission rate:
percent by weight
percent by weight
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV, %S, %Ash and cost. Please enter
the actual values for these parameters in the table below. If the actual value for any parameter is
not known, you may use the default values provided.
Coal Blend Composition Table
Number of days the SNCR operates (tSNCR)24 days 250
Number of days the boiler operates (tplant)24 days
Inlet NOx Emissions (NOxin) to SNCR 0.093 lb/MMBtu
Oulet NOx Emissions (NOxout) from SNCR 0.07 lb/MMBtu Assumes 25% Control Efficiency
Estimated Normalized Stoichiometric Ratio (NSR)1.05 *The NSR for a urea system may be calculated using equation 1.17 in Section 4, Chapter 1 of the Air Pollution Control Cost Manual (as updated April 2019).
Concentration of reagent as stored (Cstored)50 Percent
Density of reagent as stored (ρstored)71 lb/ft3
Concentration of reagent injected (Cinj)10 percent Densities of typical SNCR reagents:
Number of days reagent is stored (tstorage)14 days 71 lbs/ft3
Estimated equipment life 20 Years 56 lbs/ft3
Select the reagent used
Desired dollar-year 2023
CEPCI for 2023 793.5 Enter the CEPCI value for 2023 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index September 2023
Annual Interest Rate (i)8.5 Percent
Fuel (Costfuel)7.21 $/MMBtu 2022 NG avg cost
Reagent (Costreag)1.66 $/gallon for a 50 percent solution of urea*
Water (Costwater)0.0042 $/gallon*
Electricity (Costelect)0.0730 $/kWh Data for October 2023
Ash Disposal (for coal-fired boilers only) (Costash)$/ton
0.015
Maintenance Cost Factor (MCF) =0.015
Administrative Charges Factor (ACF) =0.03
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet users. Use of other well-known cost indexes (e.g., M&S) is
acceptable.
Plant Elevation Feet above sea level
29.4% aqueous NH3
50% urea solution
Maintenance and Administrative Charges Cost Factors:
Enter the cost data for the proposed SNCR:
Enter the following design parameters for the proposed SNCR:
Current Bank Prime Rate October 2023
Data Element Default Value
Reagent Cost $1.66/gallon of
50% urea
solution
Water Cost ($/gallon)0.00417
Electricity Cost ($/kWh)0.0361
Fuel Cost ($/MMBtu)2.87
Ash Disposal Cost ($/ton)Not Applicable
Percent sulfur content for Coal (% weight)Not Applicable
Percent ash content for Coal (% weight)Not Applicable
Higher Heating Value (HHV) (Btu/lb)1,033 1044.6 Fuel sampling data provided by Gadsby for Unit 1 in 2017 Annual
Emission Inventory.
Sources for Default Value
U.S. Environmental Protection Agency (EPA). Documentation for EPA's Power Sector
Modeling Platform v6 Using the Integrated Planning Model, Updates to the Cost and
Performance for APC Technologies, SNCR Cost Development Methodology, Chapter 5,
Attachment 5-4, January 2017. Available at:
https://www.epa.gov/sites/production/files/2018-05/documents/attachment_5-
4_sncr_cost_development_methodology.pdf.
Average water rates for industrial facilities in 2013 compiled by Black & Veatch. (see
2012/2013 "50 Largest Cities Water/Wastewater Rate Survey." Available at
http://www.saws.org/who_we_are/community/RAC/docs/2014/50-largest-cities-
brochure-water-wastewater-rate-survey.pdf.
U.S. Energy Information Administration. Electric Power Annual 2016. Table 8.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
U.S. Energy Information Administration. Electric Power Annual 2016. Table 7.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
Not Applicable
Not Applicable
Not Applicable
2016 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics, U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-923, Power
Plant Operations Report. Available at http://www.eia.gov/electricity/data/eia923/.
0.073 EIA data for October 2023
http://www.eia.gov/electricity/data.cfm#sales.
$7.21/MMBtu - 2022 NG avg cost
https://www.eia.gov/electricity/annual/pdf/epa.pdf.
Not Applicable
Not Applicable
If you used your own site-specific values, please enter the value used
and the reference source . . .
Data Sources for Default Values Used in Calculations:
Not Applicable
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) =Bmw x NPHR =533 MMBtu/hour
Maximum Annual MWh Output =Bmw x 8760 =569,400 MWh
Estimated Actual Annual MWh Output (Boutput) =8,794 MWh
Heat Rate Factor (HRF) =NPHR/10 =0.82
Total System Capacity Factor (CFtotal) =(Boutput/Bmw)*(tsncr/tplant) =0.015 fraction
Total operating time for the SNCR (top) =CFtotal x 8760 =135 hours
NOx Removal Efficiency (EF) =(NOxin - NOxout)/NOxin =25 percent
NOx removed per hour =NOxin x EF x QB =12.39 lb/hour
Total NOx removed per year =(NOxin x EF x QB x top)/2000 =0.84 tons/year
Coal Factor (CoalF) =1 for bituminous; 1.05 for sub-bituminous; 1.07 for
lignite (weighted average is used for coal blends)
SO2 Emission rate =(%S/100)x(64/32)*(1x106)/HHV =#VALUE!
Elevation Factor (ELEVF) =14.7 psia/P =
Atmospheric pressure at 250 feet above sea level (P)
=
2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)*
=14.6 psia
Retrofit Factor (RF) =Retrofit to existing boiler 1.15
SNCR Design Parameters Unit 1
The following design parameters for the SNCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate
tab.
Not applicable; factor applies only to coal-
fired boilers
Not applicable; factor applies only to coal-
fired boilers
Not applicable; elevation factor does not
apply to plants located at elevations below
500 feet.
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Reagent Data:
Type of reagent used Urea 60.06 g/mole
Density =71 lb/gallon
Parameter Equation Calculated Value
Reagent consumption rate (mreagent) =(NOxin x QB x NSR x MWR)/(MWNOx x SR) =34
(whre SR = 1 for NH3; 2 for Urea)
Reagent Usage Rate (msol) =mreagent/Csol =68
(msol x 7.4805)/Reagent Density =7.2
Estimated tank volume for reagent storage =(msol x 7.4805 x tstorage x 24 hours/day)/Reagent
Density =2,500
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) =i (1+ i)n/(1+ i)n - 1 =0.1057
Where n = Equipment Life and i= Interest Rate
Parameter Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) =(0.47 x NOxin x NSR x QB)/NPHR =3.0 kW/hour
Water Usage:
Water consumption (qw) =(msol/Density of water) x ((Cstored/Cinj) - 1) =33 gallons/hour
Fuel Data:
Additional Fuel required to evaporate water in
injected reagent (ΔFuel) =Hv x mreagent x ((1/Cinj)-1) =0.28 MMBtu/hour
Ash Disposal:
Additional ash produced due to increased fuel
consumption (Δash) =(Δfuel x %Ash x 1x106)/HHV =0.0 lb/hour Not applicable - Ash disposal cost applies only
to coal-fired boilers
Units
lb/hour
lb/hour
gal/hour
gallons (storage needed to store a 14 day reagent supply
rounded up to the nearest 100 gallons)
Molecular Weight of Reagent (MW) =
For Fuel Oil and Natural Gas-Fired Boilers:
Capital costs for the SNCR (SNCRcost) =$1,315,312 in 2023 dollars
Air Pre-Heater Costs (APHcost)* =$0 in 2023 dollars
Balance of Plant Costs (BOPcost) =$1,924,443 in 2023 dollars
Total Capital Investment (TCI) =$4,211,681 in 2023 dollars
SNCR Capital Costs (SNCRcost) =$1,315,312 in 2023 dollars
Air Pre-Heater Costs (APHcost) =$0 in 2023 dollars
For Coal-Fired Industrial Boilers:
Balance of Plant Costs (BOPcost) =$1,924,443 in 2023 dollars
#VALUE!
Air Pre-Heater Costs (APHcost)*
For Coal-Fired Utility Boilers:
APHcost = 69,000 x (BMW x HRF x CoalF)0.78 x AHF x RF
For Coal-Fired Industrial Boilers:
APHcost = 69,000 x (0.1 x QB x HRF x CoalF)0.78 x AHF x RF
Balance of Plant Costs (BOPcost)
For Coal-Fired Utility Boilers:
BOPcost = 320,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
BOPcost = 213,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x RF
SNCR Cost Estimate Unit 1
SNCRcost = 147,000 x ((QB/NPHR)x HRF)0.42 x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
Total Capital Investment (TCI)
For Coal-Fired Boilers:
TCI = 1.3 x (SNCRcost + APHcost + BOPcost)
TCI = 1.3 x (SNCRcost + BOPcost)
SNCRcost = 220,000 x (BMW x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
SNCRcost = 147,000 x (BMW x HRF)0.42 x ELEVF x RF
For Coal-Fired Industrial Boilers:
SNCRcost = 220,000 x (0.1 x QB x HRF)0.42 x CoalF x BTF x ELEVF x RF
SNCR Capital Costs (SNCRcost)
For Coal-Fired Utility Boilers:
#VALUE!
BOPcost = 320,000 x (0.1 x QB)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
BOPcost = 213,000 x (QB/NPHR)0.33 x (NOxRemoved/hr)0.12 x RF
Direct Annual Costs (DAC) =$65,099 in 2023 dollars
Indirect Annual Costs (IDAC) =$447,070 in 2023 dollars
Total annual costs (TAC) = DAC + IDAC $512,169 in 2023 dollars
Annual Maintenance Cost =0.015 x TCI =$63,175 in 2023 dollars
Annual Reagent Cost =qsol x Costreag x top =$1,608 in 2023 dollars
Annual Electricity Cost =P x Costelect x top =$29 in 2023 dollars
Annual Water Cost =qwater x Costwater x top =$18 in 2023 dollars
Additional Fuel Cost =ΔFuel x Costfuel x top =$268 in 2023 dollars
Additional Ash Cost =ΔAsh x Costash x top x (1/2000) =$0 in 2023 dollars
Direct Annual Cost =$65,099 in 2023 dollars
Administrative Charges (AC) =0.03 x Annual Maintenance Cost =$1,895 in 2023 dollars
Capital Recovery Costs (CR)=CRF x TCI =$445,175 in 2023 dollars
Indirect Annual Cost (IDAC) =AC + CR =$447,070 in 2023 dollars
Total Annual Cost (TAC) =$512,169
NOx Removed =1 tons/year
Cost Effectiveness =$610,970 per ton of NOx removed in 2023 dollars
per year in 2023 dollars
Annual Costs
IDAC = Administrative Charges + Capital Recovery Costs
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Water Cost) + (Annual Fuel Cost) +
(Annual Ash Cost)
Indirect Annual Cost (IDAC)
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
(1)
(2)
(3)
(4)
Step 4: Complete all of the cells highlighted in yellow. As noted in step 1 above, some of the highlighted cells are pre-populated with default values based on 2016
data. Users should document the source of all values entered in accordance with what is recommended in the Control Cost Manual, and the use of actual values
other than the default values in this spreadsheet, if appropriately documented, is acceptable. You may also adjust the maintenance and administrative charges
cost factors (cells highlighted in blue) from their default values of 0.015 and 0.03, respectively. The default values for these two factors were developed for the
CAMD Integrated Planning Model (IPM). If you elect to adjust these factors, you must document why the alternative values used are appropriate.
Step 5: Once all of the data fields are complete, select the SNCR Design Parameters tab to see the calculated design parameters and the Cost Estimate tab to
view the calculated cost data for the installation and operation of the SNCR.
Air Pollution Control Cost Estimation Spreadsheet
For Selective Non-Catalytic Reduction (SNCR)
This spreadsheet allows users to estimate the capital and annualized costs for installing and operating a Selective Non-Catalytic Reduction (SNCR) control device.
SNCR is a post-combustion control technology for reducing NOx emissions by injecting an ammonia-base reagent (urea or ammonia) into the furnace at a location
where the temperature is in the appropriate range for ammonia radicals to react with NOx to form nitrogen and water.
The calculation methodologies used in this spreadsheet are those presented in the U.S. EPA's Air Pollution Control Cost Manual. This spreadsheet is intended to
be used in combination with the SNCR chapter and cost estimation methodology in the Control Cost Manual. For a detailed description of the SNCR control
technology and the cost methodologies, see Section 4, Chapter 1 of the Air Pollution Control Cost Manual (as updated April 2019). A copy of the Control Cost
Manual is available on the U.S. EPA's "Technology Transfer Network" website at: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-
reports-and-guidance-air-pollution.
Step 1:Please select on the Data Inputs tab and click on the Reset Form button. This will reset the NSR, plant elevation, estimated equipment life, desired dollar
year, cost index (to match desired dollar year), annual interest rate, unit costs for fuel, electricity, reagent, water and ash disposal, and the cost factors for
maintenance cost and administrative charges. All other data entry fields will be blank.
U.S. Environmental Protection Agency
Air Economics Group
Health and Environmental Impacts Division
Office of Air Quality Planning and Standards
(March 2021)
Instructions
The methodology used in this spreadsheet is based on the U.S. EPA Clean Air Markets Division (CAMD)'s Integrated Planning Model (IPM version 6). The size and
costs of the SNCR are based primarily on four parameters: the boiler size or heat input, the type of fuel burned, the required level of NOx reduction, and the
reagent consumption. This approach provides study-level estimates (±30%) of SNCR capital and annual costs. Default data in the spreadsheet is taken from the
SNCR Control Cost Manual and other sources such as the U.S. Energy Information Administration (EIA). The actual costs may vary from those calculated here due
to site-specific conditions, such as the boiler configuration and fuel type. Selection of the most cost-effective control option should be based on a detailed
engineering study and cost quotations from system suppliers. For additional information regarding the IPM, see the EPA Clean Air Markets webpage at
http://www.epa.gov/airmarkets/power-sector-modeling. The Agency wishes to note that all spreadsheet data inputs other than default data are merely available
to show an example calculation.
The spreadsheet can be used to estimate capital and annualized costs for applying SNCR, and particularly to the following types of combustion units:
Coal-fired utility boilers with full load capacities greater than or equal to 25 MW.
Fuel oil- and natural gas-fired utility boilers with full load capacities greater than or equal to 25 MW.
Coal-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Fuel oil- and natural gas-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Step 2: Select the type of combustion unit (utility or industrial) using the pull down menu. Indicate whether the SNCR is for new construction or retrofit of an
existing boiler. If the SNCR will be installed on an existing boiler, enter a retrofit factor equal to or greater than 0.84. Use 1 for retrofits with an average level of
difficulty. For more difficult retrofits, you may use a retrofit factor greater than 1; however, you must document why the value used is appropriate.
Step 3:Select the type of fuel burned (coal, fuel oil, and natural gas) using the pull down menu. If you selected coal, select the type of coal burned from the drop
down menu. The NOx emissions rate, weight percent coal ash and NPHR will be pre-populated with default factors based on the type of coal selected. However,
we encourage you to enter your own values for these parameters, if they are known, since the actual fuel parameters may vary from the default values provided.
Is the combustion unit a utility or industrial boiler?What type of fuel does the unit burn?
Is the SNCR for a new boiler or retrofit of an existing boiler?
1.15
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)?80 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel?1,045 Btu/scf
What is the estimated actual annual MWh output?11,675 MWh
Is the boiler a fluid-bed boiler?
Enter the net plant heat input rate (NPHR)8.20 MMBtu/MW
Fraction in
Coal Blend %S %Ash HHV (Btu/lb)
Fuel Cost
($/MMBtu)
If the NPHR is not known, use the default NPHR value:Fuel Type Default NPHR 0 1.84 9.23 12,000 2.4
Coal 10 MMBtu/MW 0 0.41 5.84 9,000 1.89
Fuel Oil 11 MMBtu/MW 0 0.82 13.6 6,626 1.74
Natural Gas 8.2 MMBtu/MW
SNCR Data Inputs Unit 2 (2017 Operating Data)
Enter the following data for your combustion unit:
Bituminous
Sub-Bituminous
Lignite
Please click the calculate button to calculate weighted
values based on the data in the table above.
Please enter a retrofit factor equal to or greater than 0.84 based on the level of difficulty.
Enter 1 for projects of average retrofit difficulty.* NOTE: You must document why a retrofit factor of 1.15 is appropriate
for the proposed project.
Ash content (%Ash):
Enter the sulfur content (%S) =
or
Select the appropriate SO2 emission rate:
percent by weight
percent by weight
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV, %S, %Ash and cost. Please enter
the actual values for these parameters in the table below. If the actual value for any parameter is
not known, you may use the default values provided.
Coal Blend Composition Table
Number of days the SNCR operates (tSNCR)28 days 250
Number of days the boiler operates (tplant)28 days
Inlet NOx Emissions (NOxin) to SNCR 0.082 lb/MMBtu
Oulet NOx Emissions (NOxout) from SNCR 0.06 lb/MMBtu Assumes 25% Control Efficiency
Estimated Normalized Stoichiometric Ratio (NSR)1.05 *The NSR for a urea system may be calculated using equation 1.17 in Section 4, Chapter 1 of the Air Pollution Control Cost Manual (as updated April 2019).
Concentration of reagent as stored (Cstored)50 Percent
Density of reagent as stored (ρstored)71 lb/ft3
Concentration of reagent injected (Cinj)10 percent Densities of typical SNCR reagents:
Number of days reagent is stored (tstorage)14 days 71 lbs/ft3
Estimated equipment life 20 Years 56 lbs/ft3
Select the reagent used
Desired dollar-year 2023
CEPCI for 2023 793.5 Enter the CEPCI value for 2023 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index September 2023
Annual Interest Rate (i)8.5 Percent
Fuel (Costfuel)7.21 $/MMBtu 2022 NG avg cost
Reagent (Costreag)1.66 $/gallon for a 50 percent solution of urea*
Water (Costwater)0.0042 $/gallon*
Electricity (Costelect)0.0730 $/kWh Data for October 2023
Ash Disposal (for coal-fired boilers only) (Costash)$/ton
0.015
Maintenance Cost Factor (MCF) =0.015
Administrative Charges Factor (ACF) =0.03
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet users. Use of other well-known cost indexes (e.g., M&S) is
acceptable.
Plant Elevation Feet above sea level
29.4% aqueous NH3
50% urea solution
Maintenance and Administrative Charges Cost Factors:
Enter the cost data for the proposed SNCR:
Enter the following design parameters for the proposed SNCR:
Current Bank Prime Rate October 2023
Data Element Default Value
Reagent Cost $1.66/gallon of
50% urea
solution
Water Cost ($/gallon)0.00417
Electricity Cost ($/kWh)0.0361
Fuel Cost ($/MMBtu)2.87
Ash Disposal Cost ($/ton)Not Applicable
Percent sulfur content for Coal (% weight)Not Applicable
Percent ash content for Coal (% weight)Not Applicable
Higher Heating Value (HHV) (Btu/lb)1,033 1044.6 Fuel sampling data provided by Gadsby for Unit 1 in 2017 Annual
Emission Inventory.
Sources for Default Value
U.S. Environmental Protection Agency (EPA). Documentation for EPA's Power Sector
Modeling Platform v6 Using the Integrated Planning Model, Updates to the Cost and
Performance for APC Technologies, SNCR Cost Development Methodology, Chapter 5,
Attachment 5-4, January 2017. Available at:
https://www.epa.gov/sites/production/files/2018-05/documents/attachment_5-
4_sncr_cost_development_methodology.pdf.
Average water rates for industrial facilities in 2013 compiled by Black & Veatch. (see
2012/2013 "50 Largest Cities Water/Wastewater Rate Survey." Available at
http://www.saws.org/who_we_are/community/RAC/docs/2014/50-largest-cities-
brochure-water-wastewater-rate-survey.pdf.
U.S. Energy Information Administration. Electric Power Annual 2016. Table 8.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
U.S. Energy Information Administration. Electric Power Annual 2016. Table 7.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
Not Applicable
Not Applicable
Not Applicable
2016 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics, U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-923, Power
Plant Operations Report. Available at http://www.eia.gov/electricity/data/eia923/.
0.073 EIA data for October 2023
http://www.eia.gov/electricity/data.cfm#sales.
$7.21/MMBtu - 2022 NG avg cost
https://www.eia.gov/electricity/annual/pdf/epa.pdf.
Not Applicable
Not Applicable
If you used your own site-specific values, please enter the value used
and the reference source . . .
Data Sources for Default Values Used in Calculations:
Not Applicable
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) =Bmw x NPHR =656 MMBtu/hour
Maximum Annual MWh Output =Bmw x 8760 =700,800 MWh
Estimated Actual Annual MWh Output (Boutput) =11,675 MWh
Heat Rate Factor (HRF) =NPHR/10 =0.82
Total System Capacity Factor (CFtotal) =(Boutput/Bmw)*(tsncr/tplant) =0.017 fraction
Total operating time for the SNCR (top) =CFtotal x 8760 =146 hours
NOx Removal Efficiency (EF) =(NOxin - NOxout)/NOxin =25 percent
NOx removed per hour =NOxin x EF x QB =13.45 lb/hour
Total NOx removed per year =(NOxin x EF x QB x top)/2000 =0.98 tons/year
Coal Factor (CoalF) =1 for bituminous; 1.05 for sub-bituminous; 1.07 for
lignite (weighted average is used for coal blends)
SO2 Emission rate =(%S/100)x(64/32)*(1x106)/HHV =#VALUE!
Elevation Factor (ELEVF) =14.7 psia/P =
Atmospheric pressure at 250 feet above sea level (P)
=
2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)*
=14.6 psia
Retrofit Factor (RF) =Retrofit to existing boiler 1.15
SNCR Design Parameters Unit 2
The following design parameters for the SNCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate
tab.
Not applicable; factor applies only to coal-
fired boilers
Not applicable; factor applies only to coal-
fired boilers
Not applicable; elevation factor does not
apply to plants located at elevations below
500 feet.
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Reagent Data:
Type of reagent used Urea 60.06 g/mole
Density =71 lb/gallon
Parameter Equation Calculated Value
Reagent consumption rate (mreagent) =(NOxin x QB x NSR x MWR)/(MWNOx x SR) =37
(whre SR = 1 for NH3; 2 for Urea)
Reagent Usage Rate (msol) =mreagent/Csol =74
(msol x 7.4805)/Reagent Density =7.8
Estimated tank volume for reagent storage =(msol x 7.4805 x tstorage x 24 hours/day)/Reagent
Density =2,700
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) =i (1+ i)n/(1+ i)n - 1 =0.1057
Where n = Equipment Life and i= Interest Rate
Parameter Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) =(0.47 x NOxin x NSR x QB)/NPHR =3.2 kW/hour
Water Usage:
Water consumption (qw) =(msol/Density of water) x ((Cstored/Cinj) - 1) =35 gallons/hour
Fuel Data:
Additional Fuel required to evaporate water in
injected reagent (ΔFuel) =Hv x mreagent x ((1/Cinj)-1) =0.30 MMBtu/hour
Ash Disposal:
Additional ash produced due to increased fuel
consumption (Δash) =(Δfuel x %Ash x 1x106)/HHV =0.0 lb/hour Not applicable - Ash disposal cost applies only
to coal-fired boilers
Units
lb/hour
lb/hour
gal/hour
gallons (storage needed to store a 14 day reagent supply
rounded up to the nearest 100 gallons)
Molecular Weight of Reagent (MW) =
For Fuel Oil and Natural Gas-Fired Boilers:
Capital costs for the SNCR (SNCRcost) =$1,435,168 in 2023 dollars
Air Pre-Heater Costs (APHcost)* =$0 in 2023 dollars
Balance of Plant Costs (BOPcost) =$2,081,250 in 2023 dollars
Total Capital Investment (TCI) =$4,571,343 in 2023 dollars
SNCR Capital Costs (SNCRcost) =$1,435,168 in 2023 dollars
Air Pre-Heater Costs (APHcost) =$0 in 2023 dollars
For Coal-Fired Industrial Boilers:
Balance of Plant Costs (BOPcost) =$2,081,250 in 2023 dollars
#VALUE!
Air Pre-Heater Costs (APHcost)*
For Coal-Fired Utility Boilers:
APHcost = 69,000 x (BMW x HRF x CoalF)0.78 x AHF x RF
For Coal-Fired Industrial Boilers:
APHcost = 69,000 x (0.1 x QB x HRF x CoalF)0.78 x AHF x RF
Balance of Plant Costs (BOPcost)
For Coal-Fired Utility Boilers:
BOPcost = 320,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
BOPcost = 213,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x RF
SNCR Cost Estimate Unit 2
SNCRcost = 147,000 x ((QB/NPHR)x HRF)0.42 x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
Total Capital Investment (TCI)
For Coal-Fired Boilers:
TCI = 1.3 x (SNCRcost + APHcost + BOPcost)
TCI = 1.3 x (SNCRcost + BOPcost)
SNCRcost = 220,000 x (BMW x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
SNCRcost = 147,000 x (BMW x HRF)0.42 x ELEVF x RF
For Coal-Fired Industrial Boilers:
SNCRcost = 220,000 x (0.1 x QB x HRF)0.42 x CoalF x BTF x ELEVF x RF
SNCR Capital Costs (SNCRcost)
For Coal-Fired Utility Boilers:
#VALUE!
BOPcost = 320,000 x (0.1 x QB)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
BOPcost = 213,000 x (QB/NPHR)0.33 x (NOxRemoved/hr)0.12 x RF
Direct Annual Costs (DAC) =$70,822 in 2023 dollars
Indirect Annual Costs (IDAC) =$485,248 in 2023 dollars
Total annual costs (TAC) = DAC + IDAC $556,070 in 2023 dollars
Annual Maintenance Cost =0.015 x TCI =$68,570 in 2023 dollars
Annual Reagent Cost =qsol x Costreag x top =$1,882 in 2023 dollars
Annual Electricity Cost =P x Costelect x top =$34 in 2023 dollars
Annual Water Cost =qwater x Costwater x top =$22 in 2023 dollars
Additional Fuel Cost =ΔFuel x Costfuel x top =$314 in 2023 dollars
Additional Ash Cost =ΔAsh x Costash x top x (1/2000) =$0 in 2023 dollars
Direct Annual Cost =$70,822 in 2023 dollars
Administrative Charges (AC) =0.03 x Annual Maintenance Cost =$2,057 in 2023 dollars
Capital Recovery Costs (CR)=CRF x TCI =$483,191 in 2023 dollars
Indirect Annual Cost (IDAC) =AC + CR =$485,248 in 2023 dollars
Total Annual Cost (TAC) =$556,070
NOx Removed =1 tons/year
Cost Effectiveness =$566,697 per ton of NOx removed in 2023 dollars
per year in 2023 dollars
Annual Costs
IDAC = Administrative Charges + Capital Recovery Costs
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Water Cost) + (Annual Fuel Cost) +
(Annual Ash Cost)
Indirect Annual Cost (IDAC)
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
(1)
(2)
(3)
(4)
Step 4: Complete all of the cells highlighted in yellow. As noted in step 1 above, some of the highlighted cells are pre-populated with default values based on 2016
data. Users should document the source of all values entered in accordance with what is recommended in the Control Cost Manual, and the use of actual values
other than the default values in this spreadsheet, if appropriately documented, is acceptable. You may also adjust the maintenance and administrative charges
cost factors (cells highlighted in blue) from their default values of 0.015 and 0.03, respectively. The default values for these two factors were developed for the
CAMD Integrated Planning Model (IPM). If you elect to adjust these factors, you must document why the alternative values used are appropriate.
Step 5: Once all of the data fields are complete, select the SNCR Design Parameters tab to see the calculated design parameters and the Cost Estimate tab to
view the calculated cost data for the installation and operation of the SNCR.
Air Pollution Control Cost Estimation Spreadsheet
For Selective Non-Catalytic Reduction (SNCR)
This spreadsheet allows users to estimate the capital and annualized costs for installing and operating a Selective Non-Catalytic Reduction (SNCR) control device.
SNCR is a post-combustion control technology for reducing NOx emissions by injecting an ammonia-base reagent (urea or ammonia) into the furnace at a location
where the temperature is in the appropriate range for ammonia radicals to react with NOx to form nitrogen and water.
The calculation methodologies used in this spreadsheet are those presented in the U.S. EPA's Air Pollution Control Cost Manual. This spreadsheet is intended to
be used in combination with the SNCR chapter and cost estimation methodology in the Control Cost Manual. For a detailed description of the SNCR control
technology and the cost methodologies, see Section 4, Chapter 1 of the Air Pollution Control Cost Manual (as updated April 2019). A copy of the Control Cost
Manual is available on the U.S. EPA's "Technology Transfer Network" website at: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-
reports-and-guidance-air-pollution.
Step 1:Please select on the Data Inputs tab and click on the Reset Form button. This will reset the NSR, plant elevation, estimated equipment life, desired dollar
year, cost index (to match desired dollar year), annual interest rate, unit costs for fuel, electricity, reagent, water and ash disposal, and the cost factors for
maintenance cost and administrative charges. All other data entry fields will be blank.
U.S. Environmental Protection Agency
Air Economics Group
Health and Environmental Impacts Division
Office of Air Quality Planning and Standards
(March 2021)
Instructions
The methodology used in this spreadsheet is based on the U.S. EPA Clean Air Markets Division (CAMD)'s Integrated Planning Model (IPM version 6). The size and
costs of the SNCR are based primarily on four parameters: the boiler size or heat input, the type of fuel burned, the required level of NOx reduction, and the
reagent consumption. This approach provides study-level estimates (±30%) of SNCR capital and annual costs. Default data in the spreadsheet is taken from the
SNCR Control Cost Manual and other sources such as the U.S. Energy Information Administration (EIA). The actual costs may vary from those calculated here due
to site-specific conditions, such as the boiler configuration and fuel type. Selection of the most cost-effective control option should be based on a detailed
engineering study and cost quotations from system suppliers. For additional information regarding the IPM, see the EPA Clean Air Markets webpage at
http://www.epa.gov/airmarkets/power-sector-modeling. The Agency wishes to note that all spreadsheet data inputs other than default data are merely available
to show an example calculation.
The spreadsheet can be used to estimate capital and annualized costs for applying SNCR, and particularly to the following types of combustion units:
Coal-fired utility boilers with full load capacities greater than or equal to 25 MW.
Fuel oil- and natural gas-fired utility boilers with full load capacities greater than or equal to 25 MW.
Coal-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Fuel oil- and natural gas-fired industrial boilers with maximum heat input capacities greater than or equal to 250 MMBtu/hour.
Step 2: Select the type of combustion unit (utility or industrial) using the pull down menu. Indicate whether the SNCR is for new construction or retrofit of an
existing boiler. If the SNCR will be installed on an existing boiler, enter a retrofit factor equal to or greater than 0.84. Use 1 for retrofits with an average level of
difficulty. For more difficult retrofits, you may use a retrofit factor greater than 1; however, you must document why the value used is appropriate.
Step 3:Select the type of fuel burned (coal, fuel oil, and natural gas) using the pull down menu. If you selected coal, select the type of coal burned from the drop
down menu. The NOx emissions rate, weight percent coal ash and NPHR will be pre-populated with default factors based on the type of coal selected. However,
we encourage you to enter your own values for these parameters, if they are known, since the actual fuel parameters may vary from the default values provided.
Is the combustion unit a utility or industrial boiler?What type of fuel does the unit burn?
Is the SNCR for a new boiler or retrofit of an existing boiler?
1.15
Complete all of the highlighted data fields:
Not applicable to units burning fuel oil or natural gas
What is the MW rating at full load capacity (Bmw)?105 MW Type of coal burned:
What is the higher heating value (HHV) of the fuel?1,044 Btu/scf
What is the estimated actual annual MWh output?22,554 MWh
Is the boiler a fluid-bed boiler?
Enter the net plant heat input rate (NPHR)8.20 MMBtu/MW
Fraction in
Coal Blend %S %Ash HHV (Btu/lb)
Fuel Cost
($/MMBtu)
If the NPHR is not known, use the default NPHR value:Fuel Type Default NPHR 0 1.84 9.23 12,000 2.4
Coal 10 MMBtu/MW 0 0.41 5.84 9,000 1.89
Fuel Oil 11 MMBtu/MW 0 0.82 13.6 6,626 1.74
Natural Gas 8.2 MMBtu/MW
SNCR Data Inputs Unit 3 (2017 Operating Data)
Enter the following data for your combustion unit:
Bituminous
Sub-Bituminous
Lignite
Please click the calculate button to calculate weighted
values based on the data in the table above.
Please enter a retrofit factor equal to or greater than 0.84 based on the level of difficulty.
Enter 1 for projects of average retrofit difficulty.* NOTE: You must document why a retrofit factor of 1.15 is appropriate
for the proposed project.
Ash content (%Ash):
Enter the sulfur content (%S) =
or
Select the appropriate SO2 emission rate:
percent by weight
percent by weight
Not applicable to units buring fuel oil or natural gas
Note: The table below is pre-populated with default values for HHV, %S, %Ash and cost. Please enter
the actual values for these parameters in the table below. If the actual value for any parameter is
not known, you may use the default values provided.
Coal Blend Composition Table
Number of days the SNCR operates (tSNCR)33 days 250
Number of days the boiler operates (tplant)33 days
Inlet NOx Emissions (NOxin) to SNCR 0.0911 lb/MMBtu
Oulet NOx Emissions (NOxout) from SNCR 0.07 lb/MMBtu Assumes 25% Control Efficiency
Estimated Normalized Stoichiometric Ratio (NSR)1.05 *The NSR for a urea system may be calculated using equation 1.17 in Section 4, Chapter 1 of the Air Pollution Control Cost Manual (as updated April 2019).
Concentration of reagent as stored (Cstored)50 Percent
Density of reagent as stored (ρstored)71 lb/ft3
Concentration of reagent injected (Cinj)10 percent Densities of typical SNCR reagents:
Number of days reagent is stored (tstorage)14 days 71 lbs/ft3
Estimated equipment life 20 Years 56 lbs/ft3
Select the reagent used
Desired dollar-year 2023
CEPCI for 2023 793.5 Enter the CEPCI value for 2023 541.7 2016 CEPCI CEPCI = Chemical Engineering Plant Cost Index September 2023
Annual Interest Rate (i)8.5 Percent
Fuel (Costfuel)7.21 $/MMBtu 2022 NG avg cost
Reagent (Costreag)1.66 $/gallon for a 50 percent solution of urea*
Water (Costwater)0.0042 $/gallon*
Electricity (Costelect)0.0730 $/kWh Data for October 2023
Ash Disposal (for coal-fired boilers only) (Costash)$/ton
0.015
Maintenance Cost Factor (MCF) =0.015
Administrative Charges Factor (ACF) =0.03
Note: The use of CEPCI in this spreadsheet is not an endorsement of the index, but is there merely to allow for availability of a well-known cost index to spreadsheet users. Use of other well-known cost indexes (e.g., M&S) is
acceptable.
Plant Elevation Feet above sea level
29.4% aqueous NH3
50% urea solution
Maintenance and Administrative Charges Cost Factors:
Enter the cost data for the proposed SNCR:
Enter the following design parameters for the proposed SNCR:
Current Bank Prime Rate October 2023
Data Element Default Value
Reagent Cost $1.66/gallon of
50% urea
solution
Water Cost ($/gallon)0.00417
Electricity Cost ($/kWh)0.0361
Fuel Cost ($/MMBtu)2.87
Ash Disposal Cost ($/ton)Not Applicable
Percent sulfur content for Coal (% weight)Not Applicable
Percent ash content for Coal (% weight)Not Applicable
Higher Heating Value (HHV) (Btu/lb)1,033 1043.7 Fuel sampling data provided by Gadsby for Unit 3 in 2017 Annual
Emission Inventory.
Sources for Default Value
U.S. Environmental Protection Agency (EPA). Documentation for EPA's Power Sector
Modeling Platform v6 Using the Integrated Planning Model, Updates to the Cost and
Performance for APC Technologies, SNCR Cost Development Methodology, Chapter 5,
Attachment 5-4, January 2017. Available at:
https://www.epa.gov/sites/production/files/2018-05/documents/attachment_5-
4_sncr_cost_development_methodology.pdf.
Average water rates for industrial facilities in 2013 compiled by Black & Veatch. (see
2012/2013 "50 Largest Cities Water/Wastewater Rate Survey." Available at
http://www.saws.org/who_we_are/community/RAC/docs/2014/50-largest-cities-
brochure-water-wastewater-rate-survey.pdf.
U.S. Energy Information Administration. Electric Power Annual 2016. Table 8.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
U.S. Energy Information Administration. Electric Power Annual 2016. Table 7.4. Published
December 2017. Available at: https://www.eia.gov/electricity/annual/pdf/epa.pdf.
Not Applicable
Not Applicable
Not Applicable
2016 natural gas data compiled by the Office of Oil, Gas, and Coal Supply Statistics, U.S.
Energy Information Administration (EIA) from data reported on EIA Form EIA-923, Power
Plant Operations Report. Available at http://www.eia.gov/electricity/data/eia923/.
0.073 EIA data for October 2023
http://www.eia.gov/electricity/data.cfm#sales.
$7.21/MMBtu - 2022 NG avg cost
https://www.eia.gov/electricity/annual/pdf/epa.pdf.
Not Applicable
Not Applicable
If you used your own site-specific values, please enter the value used
and the reference source . . .
Data Sources for Default Values Used in Calculations:
Not Applicable
Parameter Equation Calculated Value Units
Maximum Annual Heat Input Rate (QB) =Bmw x NPHR =861 MMBtu/hour
Maximum Annual MWh Output =Bmw x 8760 =919,800 MWh
Estimated Actual Annual MWh Output (Boutput) =22,554 MWh
Heat Rate Factor (HRF) =NPHR/10 =0.82
Total System Capacity Factor (CFtotal) =(Boutput/Bmw)*(tsncr/tplant) =0.025 fraction
Total operating time for the SNCR (top) =CFtotal x 8760 =215 hours
NOx Removal Efficiency (EF) =(NOxin - NOxout)/NOxin =25 percent
NOx removed per hour =NOxin x EF x QB =19.61 lb/hour
Total NOx removed per year =(NOxin x EF x QB x top)/2000 =2.11 tons/year
Coal Factor (CoalF) =1 for bituminous; 1.05 for sub-bituminous; 1.07 for
lignite (weighted average is used for coal blends)
SO2 Emission rate =(%S/100)x(64/32)*(1x106)/HHV =#VALUE!
Elevation Factor (ELEVF) =14.7 psia/P =
Atmospheric pressure at 250 feet above sea level (P)
=
2116x[(59-(0.00356xh)+459.7)/518.6]5.256 x (1/144)*
=14.6 psia
Retrofit Factor (RF) =Retrofit to existing boiler 1.15
SNCR Design Parameters Unit 3
The following design parameters for the SNCR were calculated based on the values entered on the Data Inputs tab. These values were used to prepare the costs shown on the Cost Estimate
tab.
Not applicable; factor applies only to coal-
fired boilers
Not applicable; factor applies only to coal-
fired boilers
Not applicable; elevation factor does not
apply to plants located at elevations below
500 feet.
* Equation is from the National Aeronautics and Space Administration (NASA), Earth Atmosphere Model. Available at
https://spaceflightsystems.grc.nasa.gov/education/rocket/atmos.html.
Reagent Data:
Type of reagent used Urea 60.06 g/mole
Density =71 lb/gallon
Parameter Equation Calculated Value
Reagent consumption rate (mreagent) =(NOxin x QB x NSR x MWR)/(MWNOx x SR) =54
(whre SR = 1 for NH3; 2 for Urea)
Reagent Usage Rate (msol) =mreagent/Csol =108
(msol x 7.4805)/Reagent Density =11.3
Estimated tank volume for reagent storage =(msol x 7.4805 x tstorage x 24 hours/day)/Reagent
Density =3,900
Capital Recovery Factor:
Parameter Equation Calculated Value
Capital Recovery Factor (CRF) =i (1+ i)n/(1+ i)n - 1 =0.1057
Where n = Equipment Life and i= Interest Rate
Parameter Equation Calculated Value Units
Electricity Usage:
Electricity Consumption (P) =(0.47 x NOxin x NSR x QB)/NPHR =4.7 kW/hour
Water Usage:
Water consumption (qw) =(msol/Density of water) x ((Cstored/Cinj) - 1) =52 gallons/hour
Fuel Data:
Additional Fuel required to evaporate water in
injected reagent (ΔFuel) =Hv x mreagent x ((1/Cinj)-1) =0.44 MMBtu/hour
Ash Disposal:
Additional ash produced due to increased fuel
consumption (Δash) =(Δfuel x %Ash x 1x106)/HHV =0.0 lb/hour Not applicable - Ash disposal cost applies only
to coal-fired boilers
Units
lb/hour
lb/hour
gal/hour
gallons (storage needed to store a 14 day reagent supply
rounded up to the nearest 100 gallons)
Molecular Weight of Reagent (MW) =
For Fuel Oil and Natural Gas-Fired Boilers:
Capital costs for the SNCR (SNCRcost) =$1,608,809 in 2023 dollars
Air Pre-Heater Costs (APHcost)* =$0 in 2023 dollars
Balance of Plant Costs (BOPcost) =$2,382,064 in 2023 dollars
Total Capital Investment (TCI) =$5,188,135 in 2023 dollars
SNCR Capital Costs (SNCRcost) =$1,608,809 in 2023 dollars
Air Pre-Heater Costs (APHcost) =$0 in 2023 dollars
For Coal-Fired Industrial Boilers:
Balance of Plant Costs (BOPcost) =$2,382,064 in 2023 dollars
#VALUE!
Air Pre-Heater Costs (APHcost)*
For Coal-Fired Utility Boilers:
APHcost = 69,000 x (BMW x HRF x CoalF)0.78 x AHF x RF
For Coal-Fired Industrial Boilers:
APHcost = 69,000 x (0.1 x QB x HRF x CoalF)0.78 x AHF x RF
Balance of Plant Costs (BOPcost)
For Coal-Fired Utility Boilers:
BOPcost = 320,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
BOPcost = 213,000 x (BMW)0.33 x (NOxRemoved/hr)0.12 x RF
SNCR Cost Estimate Unit 3
SNCRcost = 147,000 x ((QB/NPHR)x HRF)0.42 x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
Total Capital Investment (TCI)
For Coal-Fired Boilers:
TCI = 1.3 x (SNCRcost + APHcost + BOPcost)
TCI = 1.3 x (SNCRcost + BOPcost)
SNCRcost = 220,000 x (BMW x HRF)0.42 x CoalF x BTF x ELEVF x RF
For Fuel Oil and Natural Gas-Fired Utility Boilers:
SNCRcost = 147,000 x (BMW x HRF)0.42 x ELEVF x RF
For Coal-Fired Industrial Boilers:
SNCRcost = 220,000 x (0.1 x QB x HRF)0.42 x CoalF x BTF x ELEVF x RF
SNCR Capital Costs (SNCRcost)
For Coal-Fired Utility Boilers:
#VALUE!
BOPcost = 320,000 x (0.1 x QB)0.33 x (NOxRemoved/hr)0.12 x BTF x RF
For Fuel Oil and Natural Gas-Fired Industrial Boilers:
BOPcost = 213,000 x (QB/NPHR)0.33 x (NOxRemoved/hr)0.12 x RF
Direct Annual Costs (DAC) =$82,655 in 2023 dollars
Indirect Annual Costs (IDAC) =$550,721 in 2023 dollars
Total annual costs (TAC) = DAC + IDAC $633,376 in 2023 dollars
Annual Maintenance Cost =0.015 x TCI =$77,822 in 2023 dollars
Annual Reagent Cost =qsol x Costreag x top =$4,039 in 2023 dollars
Annual Electricity Cost =P x Costelect x top =$74 in 2023 dollars
Annual Water Cost =qwater x Costwater x top =$46 in 2023 dollars
Additional Fuel Cost =ΔFuel x Costfuel x top =$674 in 2023 dollars
Additional Ash Cost =ΔAsh x Costash x top x (1/2000) =$0 in 2023 dollars
Direct Annual Cost =$82,655 in 2023 dollars
Administrative Charges (AC) =0.03 x Annual Maintenance Cost =$2,335 in 2023 dollars
Capital Recovery Costs (CR)=CRF x TCI =$548,386 in 2023 dollars
Indirect Annual Cost (IDAC) =AC + CR =$550,721 in 2023 dollars
Total Annual Cost (TAC) =$633,376
NOx Removed =2 tons/year
Cost Effectiveness =$300,741 per ton of NOx removed in 2023 dollars
per year in 2023 dollars
Annual Costs
IDAC = Administrative Charges + Capital Recovery Costs
Cost Effectiveness
Cost Effectiveness = Total Annual Cost/ NOx Removed/year
Direct Annual Costs (DAC)
DAC = (Annual Maintenance Cost) + (Annual Reagent Cost) + (Annual Electricity Cost) + (Annual Water Cost) + (Annual Fuel Cost) +
(Annual Ash Cost)
Indirect Annual Cost (IDAC)
Total Annual Cost (TAC)
TAC = Direct Annual Costs + Indirect Annual Costs
NOx Cost Analysis to Upgrade Units #3 with Low NOx Burners
PacifiCorp Gadsby Power Plant
Unit #3 Factor Basis for Cost
and Factor
Direct Costs:
Puchased Equipment:
Primary and Auxiliary Equipment (PE)
Sales Tax 6% of PE OTC-LADCO 2008
Freight 5% of PE OTC-LADCO 2008
Total Purchased Equipment Cost (PEC)2016 Dollars
Direct Installation
Electrical, Piping, Insulation and Ductwork 40% of PEC OTC-LADCO 2008
Total Direct Cost (DC)
Indirect Installation Costs
Engineering and Project Management,
Construction and Field Expenses, Contractor
Fees, Startup Expenses, Performance Tests,
Contingencies 61% of PEC OTC-LADCO 2008
Total Indirect Cost
Total Installed Cost (TIC)
NOx Emissions Before Control, lb/MMBtu #
#NOx Emissions Before Control, tn/yr 13.25
NOx Emissions After Control, lb/MMBtu 0.04
Control Efficiency (%)55
NOx Emissions After Control, tn/yr 5.96
NOx Emission Reduction, tn/yr 7.29
Annual Costs, $/year (Direct + Indirect)
Direct Costs
Operating Labor
Replacement Parts
Total Direct Costs, $/year
Indirect Costs
Overhead
Taxes, Insurance, and Administration
Capital Recovery
Total Indirect Costs, $/year
Total Annual Cost
Cost Effectiveness, $ per ton NOx reduction
$4,109,415.67
$176,998.40
$5,309.95
$235,997.87
$899,151.89
$1,140,459.71
$1,760,935.52
$241,637.81
$5,899,946.78
60% of labor costs
4% of total installed cost
8.5%, 30 years
$176,998.40
3% of Capital cost
$620,475.81
3% of Capital cost
$1,790,531.11
$1,790,531.11
$1,174,118.76
LNB Upgrade
$1,805,265.00
2023 dollars, 541.7 CEPCI 2016/793.5 2023$2,935,296.90
Estimate - $1563/MMBtu (2016)
$108,315.90
$90,263.25
$2,003,844.15
NOx Cost Analysis to Upgrade Units #1 and #2 with Flue Gas Recirculation
PacifiCorp Gadsby Power Plant
Factor Basis for Cost
and Factor
Direct Costs:
Puchased Equipment:
Primary and Auxiliary Equipment (PE)
Sales Tax 6% of PE OTC-LADCO 2008
Freight 5% of PE OTC-LADCO 2008
Total Purchased Equipment Cost (PEC)2016 Dollars
Direct Installation (DI)
Electrical, Piping, Insulation and Ductwork 40% of PEC OTC-LADCO 2008
Total Direct Cost (DC)
Indirect Installation Costs
Engineering and Project Management,
Construction and Field Expenses, Contractor
Fees, Startup Expenses, Performance Tests,
Contingencies 61% of PEC OTC-LADCO 2008
Total Indirect Cost
Total Installed Cost (TIC)
NOx Emissions Before Control, lb/MMBtu 0.093 0.082
NOx Emissions Before Control, tn/yr 7.47 7.68
NOx Emissions After Control, lb/MMBtu 0.074 0.066
Control Efficiency (%)20 20
NOx Emissions After Control, tn/yr 5.98 6.14
NOx Emission Reduction, tn/yr 1.49 1.54
Annual Costs, $/year (Direct + Indirect)
Direct Costs
Operating Labor
Replacement Parts
Total Direct Costs, $/year
Indirect Costs
Overhead
Taxes, Insurance, and Administration
Capital Recovery
Total Indirect Costs, $/year
Total Annual Cost
Cost Effectiveness, $ per ton NOx reduction
Unit #1 Unit #2
FGR Upgrade FGR Upgrade
$325,000 $400,000 Estimate - $5/kW (2016)
$360,750 $444,000
$211,375 $260,154
$1,422,911 $1,751,276
$1,100,564 $1,354,540
$42,687 $52,538
$42,687 $52,538
$56,916 $70,051
$216,852 $266,894
$299,381 $368,468
$257,534 $308,297
$19,500 $24,000
$16,250 $20,000
$322,347 $396,735
$322,347 $396,735
2023 dollars, 541.7 CEPCI 2016/793.5 2023$528,438 $650,386
$384,755 $473,545
60% of labor costs
4% of total installed cost
8.5%, 30 years
$25,612 $31,523
3% of Capital cost
3% of Capital cost
$85,375 $105,077
VOC Cost Analysis to Upgrade Units #1 - #3 with Oxidation Catalyst
PacifiCorp Gadsby Power Plant
Unit #1 Factor Basis for Cost
Upgrade and Factor
MMBtu/hr 726 825 1155
scfm 105,391 119,763 167,668 8710 Fd factor.
Direct Costs:
Total Installed Cost (TIC)
Total Installed Cost (TIC)
VOC Emissions Before Control, lb/MMBtu 0.0053 0.0053 0.0053
VOC Emissions Before Control, tn/yr 0.42 0.49 0.76
VOC Emissions After Control, lb/MMBtu 0.0037 0.0037 0.0037
Control Efficiency (%)50 50 50
VOC Emissions After Control, tn/yr 0.21 0.25 0.38
VOC Emission Reduction, tn/yr 0.21 0.25 0.38
Annual Costs, $/year (Direct + Indirect)
Direct Costs
O&M Costs
Total Direct Costs, $/year
Total Direct Costs, $/year
Indirect Costs
Capital Recovery $708,764.28 $805,413.95 $1,127,579.53
Total Indirect Costs, $/year $708,764.28 $805,413.95 $1,127,579.53
Total Annual Cost $2,399,922.19 $2,727,184.30 $3,818,058.02
Cost Effectiveness, $ per ton VOC reduction $11,428,200.88 $11,131,364.50 $10,047,521.11
8.5%, 30 years,
2023 Dollars
$843,128 $958,100 $1,341,340
Costs range from $4 to $25 per cfm.$843,128 $958,100 $1,341,340
$4/scfm [EPA-452/F-03-021], 2002 dollars
$22/scfm [EPA-452/F-03-018], 2002 dollars
Costs range from $22 to $90 per cfm.
2017 EI
$4,650,684
$2,318,602 $2,634,775 $3,688,685
Unit #2 Unit #2
Upgrade Upgrade
AP-42 5.5 lb/mmcf; 2017 avg heating value per boiler
$5,284,868 $7,398,816 2023 dollars, 395.6 CEPCI 2002/793.5 2023
2002 dollars
$1,691,158 $1,921,770 $2,690,478