EPE NSR Permit Application V1.17-Min

EL PASO ELECTRIC COMPANY
NEWMAN GENERATING STATION

APPLICATION FOR A PSD/NNSR AIR QUALITY
PERMIT AMENDMENT
TCEQ CN600352819; TCEQ RN100211309
OCTOBER 2019
PREPARED FOR
El Paso Electric Company
PREPARED BY
SWCA Environmental Consultants
EL PASO ELECTRIC COMPANY
NEWMAN GENERATING STATION
APPLICATION FOR A PSD/NNSR AIR QUALITY PERMIT
AMENDMENT
Prepared for
P.O. Box 982
El Paso, Texas 79960
Prepared by
SWCA Environmental Consultants
200 West 22nd Street, Suite 200
Lombard, Illinois 60148
800.828.8517
www.swca.com
SWCA Project No. 55480
October 2019
Application for a PSD/NNSR Air Quality Permit Amendment
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CONTENTS
1 Introduction .......................................................................................................................................... 1
2 Project Description ............................................................................................................................... 3

2.1 General Site Information.................................................................................................................. 3
2.2 Proposed Project .............................................................................................................................. 6
2.2.1 Project Summary................................................................................................................. 6
2.2.2 Process Description............................................................................................................. 6
3 Project Emissions ................................................................................................................................. 9

3.1 Emission Calculation Methodology ................................................................................................. 9
3.1.1 Simple Cycle Turbine ......................................................................................................... 9
3.1.2 Firewater Pump Engine .................................................................................................... 10
3.1.3 Line Heater ....................................................................................................................... 10
3.1.4 Fugitive Emissions ............................................................................................................ 10
3.2 Emission Summary ........................................................................................................................ 11
4 Air Quality Regulatory Review ......................................................................................................... 13

4.1 Federal Regulations ....................................................................................................................... 13
4.1.1 Prevention of Significant Deterioration ............................................................................ 13
4.1.2 Nonattainment New Source Review ................................................................................. 14
4.1.3 New Source Performance Standards ................................................................................. 14
4.1.4 National Emission Standards for Hazardous Air Pollutants ............................................. 16
4.1.5 Federal Operating Permitting Programs ........................................................................... 17
4.1.6 Acid Rain Program ........................................................................................................... 18
4.1.7 Stratospheric Ozone Protection......................................................................................... 18
4.1.8 Clean Air Interstate Rule .................................................................................................. 18
4.1.9 Cross-State Air Pollution Rule.......................................................................................... 18
4.1.10 Mandatory Greenhouse Gas Reporting ............................................................................. 18
4.2 State Regulations ........................................................................................................................... 19
4.2.1 Texas Administrative Code, Title 30 ................................................................................ 19
5 Air Pollution Control Evaluation ...................................................................................................... 22

5.1 PSD BACT Review ....................................................................................................................... 22
5.1.1 Simple Cycle Turbine ....................................................................................................... 23
5.1.3 Line Heater ....................................................................................................................... 32
5.1.4 Fugitive Emissions ............................................................................................................ 36
5.2 NNSR LAER Analysis .................................................................................................................. 39
5.2.1 Simple Cycle Turbine ....................................................................................................... 39
5.2.3 Line Heater ....................................................................................................................... 40
6 Air Quality Impacts Analysis ............................................................................................................ 41
7 Nonattainment New Source Review.................................................................................................. 42

7.1.1 Offsets ............................................................................................................................... 42
7.1.2 Alternative Site Analysis .................................................................................................. 42
ii
7.1.3 Compliance History Review ............................................................................................. 42
Appendices
Appendix A. Emission Calculations
Appendix B. Manufacturer’s Specifications
Appendix C. BACT Analysis Support
Appendix D. PI-1 General Application Workbook
Appendix E. Texas Professional Engineer (P.E.) certification statement
Figures
Figure 1. Area Map
Figure 2. Plot Plan
Figure 3. Process Flow Diagram
Tables
Table 1. Proposed Site Location
Table 2. Existing Emission Unit Authorizations
Table 3. Proposed Project Emission Units
Table 4. Criteria Pollutant and GHG Potential to Emit in Tons per Year
Table 5. Hazardous Air Pollutant Potential to Emit in Tons per Year
Table 6. Summary of Potential to Emit in Tons per Year for Compounds Subject to MERA
Table 7. 40 CFR Part 60 Applicable Subparts
Table 8. 40 CFR Part 60 Subparts Not Applicable to the Project.
Table 10. 40 CFR Part 63 Subparts Not Applicable to the Project
Table 11. Applicable TCEQ Air Quality Regulations
Table 12. TCEQ Air Quality Regulations Determined Inapplicable
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1 INTRODUCTION
El Paso Electric Company (EPE) owns and operates an electric generating plant called the Newman
Generating Station located at 4900 Stan Roberts Sr Avenue in El Paso, El Paso County, Texas. EPE has
been assigned Texas Commission on Environmental Quality (TCEQ) Customer Number CN600352819.
The Newman Generating Station has been assigned TCEQ Regulated Entity Number RN100211309 and
Air Account No. EE-0029-T.
El Paso County is currently classified as being in attainment or unclassified with respect to the National
Ambient Air Quality Standards (NAAQS) for carbon monoxide (CO), nitrogen dioxide (NO2), sulfur
dioxide (SO2), ozone (O3), particulate matter less than 2.5 microns in diameter (PM2.5), and lead (Pb).1
The City of El Paso in El Paso County is designated as a moderate nonattainment for particulate matter
less than 10 microns in diameter (PM10). The Newman Generating Station is located within this PM10
Nonattainment Area.
The Newman Generating Station is classified as an existing major source under the Prevention of
Significant
Deterioration (PSD) and Nonattainment New Source Review (NNSR) programs. Existing emission
sources located at the Newman Generating Station are currently authorized by PSD Permit No.
PSDTX1090 and TCEQ NSR Permit No. 1467, TCEQ Standard Permit No. 114528, and TCEQ
Voluntary Emission Reduction Permit No. 45606. Additionally, the site is a major source under the Title
V Operating Permits Program and operates pursuant to Site Operating Permit (SOP) and Acid Rain
Permit No. O80. The Newman Generating Station will be a major source of hazardous air pollutant
(HAP) emissions.
With this application, EPE is proposing to modify the existing Newman Generating Station by
constructing a new Mitsubishi 501G series natural gas 230 Megawatt (MW) simple cycle combustion
turbine fired by pipeline quality natural gas along with ancillary equipment (the Project). The new unit
will provide additional generating capacity at the Newman Generating Station to meet projections of
future demand and will operate as a simple cycle unit. Ancillary equipment includes a diesel-fired
firewater pump engine and a natural gas-fired line heater. The turbine will be equipped with dry low-NOx
burners, Selective Catalytic Reduction (SCR), and catalytic oxidation technology to control emissions
from combustion. EPE is seeking to authorize the emissions associated with the Project by applying for a
major modification to PSDTX1090 and NSR Permit 1467. An application for a significant revision to
SOP and Acid Rain Permit No. O80 for the Project will be submitted under separate cover.
Air emission increases associated with the proposed Project will consist primarily of products of
combustion from the gas-fired turbine. The construction of the new equipment qualifies as a major
modification at an existing major source and is subject to Major New Source Review under the PSD and
NNSR Programs. Based on the potential to emit (PTE) estimates provided in Section 3, the Project is
subject to PSD review for emissions of NOx, CO, VOC, PM, PM2.5, and Greenhouse Gases (regulated as
carbon dioxide equivalent [CO2e]). NNSR review is required for emission increases of PM10.
This document is intended to be a supplement to the TCEQ Form PI-1 General Application Workbook
which is being submitted concurrently in Appendix D. This submittal has been prepared in accordance
with 30 Texas Administrative Code (TAC) Chapter 116, Subchapter B, New Source Review Permits. To
1
Per EPA’s Green Book. Available online: https://www.epa.gov/green-book. Accessed September 12, 2019.
1
assist in the review of this submittal, the following list provides the individual section summary of the
application:
 Section 2.0 of this application provides general project and site information including an area
map and plot plans that show the approximate location of the project and the property lines.
 Section 3.0 provides a detailed description of the operations and a discussion of the emission
sources associated at this proposed project and control devices proposed, including process flow
diagrams. It also describes the methodology used for the emission calculations,
 Section 4.0 includes a discussion of applicable and potentially applicable state and federal
regulations.
 Section 5.0 provides the PSD Best Available Control Technology (BACT) and NNSR Lowest
Achievable Emission Rate (LAER) analysis.
 Section 6.0 includes a summary of the Air Quality Impacts Analysis. Please note that the air
dispersion modeling protocol and modeling report for the project are submitted under separate
cover.
 Section 7.0 provides a review of NNSR elements.
 Appendix A provides emission calculations.
 Appendix B contains equipment specifications for various units at the project.
 Appendix C contains BACT/LAER analysis support documents
 Appendix D includes a printout of the PI-1 General Application Workbook
 Appendix E provides the Texas Professional Engineer (P.E.) certification statement.
2
2 PROJECT DESCRIPTION
2.1 General Site Information

EPE plans to construct new equipment at the Newman Generating Station in El Paso County, Texas. The
site address is 4900 Stan Roberts Sr. Avenue, El Paso, Texas 79934. The County of El Paso is currently
classified as being in attainment or unclassified with respect to the NAAQS for CO, NO2, SO2, PM2.5, Pb,
and the 8-hour ozone standard.2 The City of El Paso is a moderate nonattainment area for PM10.
Table 1 provides the location and elevation of the Newman Generating Station.
Table 1. Site Location

County Nearest City Latitude Longitude Elevation
El Paso El Paso 31.98342 -106.42824 4,056 feet
Figure 1 shows a current area map with a 3,000-foot radius from the property boundary which shows that
there are no receptors within 3,000 feet of the project. The area map also includes a zoomed-out view to
show the closest non-industrial receptors.
Figure 2 shows a plot plan including the proposed location of the Project equipment along with the
currently authorized emission sources. EPE does not propose to modify these existing sources as part of
the Project. For reference, Table 2 lists these existing sources and includes the authorization information
for these sources. 3
Table 2. Existing Emission Unit Authorizations

New Source Review
Unit ID Emission Unit Name/Description
Authorization
B1 Unit 1 Boiler 45606
B4CA Unit 4, Combustion Turbine GT-1 1467,PSDTX1090
B4CB Unit 5, Combustion Turbine GT-2 1467,PSDTX1090
B4DA Unit 4, GT-1 Duct Burner and HRSG 1467,PSDTX1090
B4DB Unit 4, GT-2 Duct Burner and HRSG 1467,PSDTX1090
CT-1467-4 Cooling Tower 1467,PSDTX1090
CT-1467-6 Cooling Tower 1467,PSDTX1090
CT-1 Cooling Tower 45606
2
Per EPA’s Green Book. Available online: https://www.epa.gov/green-book. Accessed September 12, 2019.
3
Existing Emission Unit Authorization as presented in the New Source Review Authorization Reference by Emission Unit table
in SOP No. 080 dated July 20, 2016.
3
New Source Review

Unit ID Emission Unit Name/Description
Authorization
DB-6A Duct Burner 6A 1467,PSDTX1090
DB-6B Duct Burner 6B 1467,PSDTX1090
DB-S4-1 Duct Burners Unit S4-1 114528
DB-S4-2 Duct Burners Unit S4-2 114528
FIRE Firewater Pump Engine 1467,PSDTX1090
FUG Piping Fugitives 1467,PSDTX1090
GEN Emergency Generator Engine 1467,PSDTX1090
GT-6A Combustion Turbine GT-6A 1467,PSDTX1090
GT-6B Combustion Turbine GT-6B 1467,PSDTX1090
LO-1 Gas Turbine GT-6A Lube Oil Vent 1467,PSDTX1090
LO-2 Gas Turbine GT-6B Lube Oil Vent 1467,PSDTX1090
LO-3 Steam Turbine Lube Oil Vent 1467,PSDTX1090
OT-1 Fuel Storage Tank 1 (TK1) 45606
OT2 Fuel Storage Tank 2 (TK2) 45606
OT6 Residual Oil Tank (Old TK1) 45606
OTD-1 Diesel Storage Tank 1 1467,PSDTX1090
S1 Stack, Unit 1 Boiler 45606
S4-1 Stack, Unit 4, Combustion Turbine and HRSG, GT-1 1467,PSDTX1090
S4-2 Stack, Unit 4, Combustion Turbine and HRSG, GT-2 1467,PSDTX1090
UL-1 Tank Truck Unloading Station for Diesel Fuel 45606
4
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Project Number: 55480
Date: 8/21/2019
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2.2 Proposed Project

2.2.1 Project Summary
The purpose of the proposed project is to provide additional generation capacity based on EPE forecasts
for energy and demand needs for future operating years. EPE proposes to install a new Mitsubishi Model
M501GAC Simple Cycle gas turbine rated 230 MW which will be fired by pipeline quality natural gas.
The turbine will be used to provide new power generation capacity, especially during EPE’s summer peak
hours. The M501GAC model turbine was selected due to benefits such as efficiency, cycling capability
without impacting maintenance intervals, ramping capability to follow load, sufficient turndown, and low
mass emissions. The unit will be equipped with dry low-NOx burners, a Hot SCR, and an oxidation
catalyst to further reduce emission rates. Additional equipment associated with the project includes piping
and components which will be a source of fugitive emissions and a natural gas fired line heater which will
be used to ensure that natural gas fueling the turbine is at an acceptable temperature for combustion. An
emergency use firewater pump will also be installed as part of this project for safety purposes. Table 3
lists the new emission sources that will result from Project implementation. The proposed location for
these sources is shown in Figure 2 and a process flow diagram is shown in Figure 3.
Table 3. Proposed Project Emission Units

FIN* EPN* Emission Unit Name/Description
SC-7 SC-7 Unit 7 Simple Cycle Turbine
LH-1 LH-1 Line Heater
FIRE-2 FIRE-2 Firewater Pump Engine
FUG-7 FUG-7 Piping Fugitives

* FIN denotes the TCEQ Facility Identification Number. EPN denotes the TCEQ Emission Point Number.
2.2.2 Process Description

The following description pertains to the equipment constructed as part of the proposed Project. As
previously noted, the existing equipment at the Newman Generating Station will not be modified as part
of the project.
The natural gas fuel enters the facility from the natural gas supplier’s pipeline and is routed through the
line heater (FIN LH-1) to increase the fuel temperature (as necessary) before being routed to the turbine.
Some of the natural gas is also used by the line heater as fuel during this process which results in
combustion emissions (EPN LH-1). The natural gas-fired line heater is equipped with a low NOx burner.
The simple cycle turbine (FIN SC-7) operates by drawing air into the unit which is compressed and fed
into the combustion chamber at high pressure. In the combustion chamber, natural gas fuel is introduced
into the stream and the mixture is combusted. The high temperature, high-pressure gas stream leaves the
combustion chamber and expands through the turbine, rotating the turbines blades in order to continue
drawing in air into the combustion chamber as well as to spin a generator to produce power. The exhaust
gas stream is then vented through the turbine’s exhaust stack (EPN SC-7). The turbine will be equipped
with a dry low-NOx burner will be used to reduce thermal NOx formation. An SCR system will be used to
reduce NOx emissions in the exhaust gas stream via vaporization and injection of a 19% solution of
aqueous ammonia to the exhaust stream prior to the catalyst bed. The exhaust gas stream also passes
6
through an oxidation catalyst to reduce emissions of other products of incomplete combustion such as CO
and VOC.
During times of startup and shut down of the unit, the exhaust gas stream may not be within the
temperature range necessary for effective catalytic control or at too low a temperature for ammonia
injection. During start up, the electric motor spins the main shaft until enough air is blowing through the
combustion chamber, at which point, natural gas fuel starts flowing and ignition occurs. After ignition,
the gas turbine will accelerate to synchronization speed, and upon synchronization, the turbine will begin
increasing the load until it reaches the selected load. The M501GAC model turbine operating in simple
cycle mode is able to go from ignition to base load within thirty-five minutes and is able to shut down
completely from base load to flame out within twenty minutes. Emission rates for these startup and
shutdown periods have been provided by Mitsubishi to allow quantification of these emissions.
The emergency-use fire water pump is powered by a diesel-fired engine (FIN FIRE-2) and will be
operated for necessary maintenance and testing activities which will occur no more than one-hundred
hours per year. The diesel engine emits products of combustion from its exhaust (EPN FIRE-2).
The natural gas piping, component, and instrumentation equipment leaks (FIN FUG-7) will result in small
levels of VOC and GHG emissions. Similarly, leaks from a pressurized ammonia tank and the SCR
system piping will result in small levels of emissions of ammonia from piping (FUG-7). Lubricating oil
components, reservoirs, and lube oil vents associated with the Project are expected to have negligible
emissions due to low vapor pressure. Leaks from the circuit breakers release Sulfur Hexafluoride (SF6) –
a compound with a very high global warming potential (FIN: FUG-7) compared to other GHGs.
7

Exhaust
Fuel Input Exhaust
Diesel Driven Fire
Fuel Input Pump
Fuel Gas Heater
Exhaust
Fuel Input
Newman Unit 6 Simple Cycle
Turbine/Generator
Air Input
Electricity
Figure 3 ‐Process Flow Diagram
Unit # 6 Newman Power Station
El Paso, Texas

3 PROJECT EMISSIONS
The PTE for regulated air pollutants is estimated as described in the sections below. Proposed emission
units as part of the Project include both point and area emission sources. The emission calculation
methodology varies by emission unit type. Section 3.1 includes comprehensive discussion of the methods
used in determining emissions from each emission unit and associated EPN.
3.1 Emission Calculation Methodology

This section describes the methodologies and inputs used to calculate the Project PTE. Detailed
calculations are included in Appendix A.
3.1.1 Simple Cycle Turbine

3.2.1.1 Maximum hourly emission rates during normal operations
The simple cycle turbine (FIN SC-7; EPN: SC7) emission rates during several different operating
scenarios were provided by the manufacturer in Appendix B for most pollutants. Maximum hourly
emission rates during normal operations were determined based on the worst-case emission rate operating
conditions (Condition 19 in the in the manufacturer’s data sheet). The manufacturer’s data (Condition 19)
also includes the power output, fuel flow, heat input, exhaust flow, and exhaust temperature, as presented
in the emission calculations table. For compounds where emission rates were not directly provided by the
manufacturer, which include PM2.5 and HAP pollutants other than formaldehyde (CH2O), and nitrous
oxide (N2O), reasonable approaches, as described below, that result in conservatively high representations
of emission rates were used.
For PM species, the vendor’s rate for PM10 emissions was used as a proxy for PM2.5, meaning that it is
assumed that all PM emissions are less than or equal to 2.5 micrometers in diameter. This approach
therefore assumes PM2.5 emissions are equivalent to both the PM10 and PM total and is the most
conservative approach to assess particulate emission rates against their respective PSD significant
emission rate (SER) thresholds.
HAP emissions during normal operations (other than CH20 for which the emission rate is provided by the
manufacturer) are conservatively based on uncontrolled emission factors from AP-42 Chapter 3.1, Table
3.1-3 – Emission Factors for Hazardous Air Pollutants from Natural Gas-Fired Stationary Gas Turbines.
Note that the oxidation catalyst will control these pollutants in practice, so AP-42 uncontrolled emission
rates can be understood to be an overestimate of these emission rates, in lieu of more specific emission
rate guarantees of catalyst control.
N2O emissions during normal operations were calculated based on the default emission factor in Table C-
2 of 40 CFR Part 98 Subpart C for natural gas combustion.
3.2.1.2 Maximum hourly emission rates during Planned MSS activities
Additionally, planned maintenance, startup and shutdown (MSS) hourly maximum emission rates are
calculated based on worst case operating conditions with respect to emission rates during these activities
for NOx, CO, VOC, CO2, methane (CH4), and N2O. These values are based on the pounds per event
emission rates during minimum ambient temperature startup conditions which were the highest short-term
emission rates provided by the manufacturer of the turbine. PM, PM10, PM2.5, SO2, NH3, and H2SO4 mist
9
emissions rates during startup and shutdown activities are calculated based on worst-case base load
scenario emission rate for these compounds (Case 19 emission rates). This is a conservative
representation of PTE during these during MSS activities since these pollutants will likely have lower
emission rates during startup and shutdown events than the worst-case steady state operating condition.
To estimate HAP emissions during start up and shut down, it is assumed that the emissions of HAP
pollutants are uncontrolled throughout the startup period while the engine exhaust stack temperature
increases to a point where the oxidation catalyst reaches the target temperature. To estimate HAP
emission rates including CH2O, uncontrolled emission factors from AP-42 Chapter 3.1, Table 3.1-3 were
used.
3.2.1.3 Maximum annual emission rates
The total annual emission rates for the unit includes the steady state emissions estimated assuming 8,760
hours of operation, plus the contribution of the additional MSS event emissions (i.e., calculated by adding
only the additional emissions from these MSS events above the steady state hourly rate to avoid double-
counting emissions).
3.1.2 Firewater Pump Engine

The diesel-fueled firewater pump engine (FIN: FIRE-2; EPN FIRE-2) rating and rating-specific emission
data were provided by the equipment manufacturer (see Appendix B). Emission rates for NOx, CO, VOC,
and PM from this manufacturer-provided data were used to calculate emission rates. The PM emission
rate was conservatively assumed to represent emissions of PM, PM10, and PM2.5. SO2 emissions were
determined using a mass balance calculation assuming 15 parts per million (ppm) sulfur content of ultra-
low sulfur diesel fuel. For the purposes of determining PTE, it is assumed that 100% of sulfur in the fuel
stream is converted to SO2. HAP emission rates were conservatively based on AP-42 Chapter 3, Section 3
– Gasoline and Diesel Industrial Engines Table 3.3.2 – Speciated Organic Compounds Emission Factors
for Uncontrolled Diesel Engines. GHG emission factors for diesel fuel combustion for CO2, CH4, and
N2O are based on Tables C-1 and C-2 of 40 CFR Part 98, Subpart C. Short term pounds per hour emission
rates were calculated, then emissions in tons per year were determined based on 100 hours per year of
operation during non-emergency scenarios.
3.1.3 Line Heater

The natural gas-fired line heater (FIN: LH-1; EPN LH-1) heat input rating and criteria pollutant emission
rates were based on the manufacturer’s provided data (see Appendix B). HAP emission rates were based
on AP-42 Chapter 1, Section 4 – External Combustion Sources: Natural Gas Combustion Table 1.4-3 –
Emission Factors for Speciated Organic Compounds from Natural Gas Combustion. GHG emission
factors for natural gas combustion for CO2, CH4, and N2O are based on Tables C-1 and C-2 of 40 CFR
Part 98, Subpart C. Short term pounds per hour emission rates were calculated, then emissions in tons per
year were determined based on a highly conservative assumption of 8,760 hours per year of operation
since the heater is not expected to operate continuously.
3.1.4 Fugitive Emissions

Component counts of valves, pressure relief valves, connectors, flanges, open-ended lines and, pumps as
well as the mass of SF6 in the circuit breakers (for GHG Emissions) were used to calculate fugitive
emissions associated with the project (FIN FUG-7; EPN FUG-7). A safety factor of 25% was applied to
each estimated set of component counts. For each component and pollutant type, the most representative
emission factors published by the appropriate state or federal agency were used as discussed in more
detail below.
10
3.2.4.1 Natural Gas VOC and HAP Fugitives
Fuel gas service component emission factors from the US EPA Protocol for Equipment Leak Emission
Estimates (EPA-453/R-95-017) were used to estimate fugitive emissions from natural gas equipment
component leaks. The non-methane, non-ethane VOC weight percentage is divided by the total
hydrocarbon weight percentages in the compositional analysis of the fuel gas stream to determine an
adjusted weight percentage of VOC for use in the emission calculation because U.S. EPA’s Protocol for
Equipment Leak Emission Estimates are based on total organic compound (TOC) emission factors and do
not consider the presence of inorganic compounds in a stream. HAP emissions are considered negligible
based on the low VOC content.
In accordance with the New Source Review Division September 19, 1996 memorandum entitled “When
should a compound be considered an air contaminant”, compounds with vapor pressures lower than 0.01
mm Hg at temperatures below 40°C do not require emission calculations. The lubricating oils that will be
used to operate the turbine will not have a vapor pressure that exceeds 0.01 mmHg at 40°C.
3.2.4.2 Ammonia Fugitives
Emissions of ammonia from leaks in the SCR system piping are estimated based on emission factors
obtained from TCEQ’s Addendum to RG-360A titled: Emission Factors for Equipment Leak Fugitive
Components. Table 3 – Average Emission Factors – SOCMI includes emission factors for light liquids
without ethylene, which are deemed the most representative emission factors for this source of fugitive
equipment leaks. The calculation also takes into account that the concentration of aqueous ammonia
which is nineteen percent by weight.
3.2.4.2 GHG Fugitives
GHG emissions of CO2 and CH4 result from natural gas fuel system component leaks. Emission factors
for total gas are based on 40 CFR Part 98, Subpart W Table W-A – Default Whole Gas Emission Factors
for Onshore Petroleum and Natural Gas Production, which is the most representative GHG emission
factor set accounting for emissions from natural gas piping leaks. Based on the whole gas emission
factors and the CO2 and CH4 content of the fuel, GHG emissions resulting from equipment leaks are
calculated.
Additionally, circuit breakers are also recognized as a potential source of fugitive emissions of GHG due
to the use of SF6, which is an especially potent greenhouse gas. The estimated leak rate from circuit
breakers is estimated to be 0.5% of the mass of SF6 on an annual basis. This estimate is based on a study
by Blackman et al. entitled: SF6 Leak Rates from High Voltage Circuit Breakers – EPA Investigates
Potential Greenhouse Gas Emission Source.
3.2 Emission Summary

A summary of the emissions from the project is included in the Tables below. The emission rates listed in
the tables below are compared against potentially applicable regulatory requirement thresholds. The
applicable requirements are discussed in Section 4.0.
Table 4 lists project criteria air pollutant and GHG potential to emit versus the applicable PSD or NNSR
(for PM10) SER for a modification located at an existing major source.
11
Table 4. Criteria Pollutant and GHG Potential to Emit in Tons per Year
Type of
Emission Source PM PM10 PM2.5 SO2 NOx VOC CO H2SO4 CO2e
Equipment
SC-7 SC-7 30.66 30.66 30.66 6.75 120.6 114.0 237.0 6.18 1,333,499
LH-1 LH-1 0.08 0.08 0.08 0.02 0.52 0.14 0.64 - 1,825
FIRE-2 FIRE-2 <0.01 <0.01 <0.01 <0.01 0.03 <0.01 0.01 - 5.67
FUG-7 FUG-7 - - - - - 0.13 - - 170
Total Sitewide 30.74 30.74 30.74 6.76 121.1 114.3 237.7 6.18 1,335,500
PSD/NNSR SER1 25 15 10 40 40 40 100 7 75,000
Exceeds SER? Yes Yes Yes No Yes Yes Yes No Yes
1
From TCEQ (APDG 6240v11, Revised 10/18) Fact Sheet - PSD and Nonattainment Significant Emissions.
Table 5 shows the site-wide potential to emit of HAPS after implementation of the proposed Project.
Table 5. Summary of Total Site-wide HAP Emissions after Project Implementation

HAP Major Source Threshold
Emission Source Tons per Year
Formaldehyde 10.81 10
Total HAP 30.61 25
Table 6 shows the emission rates of pollutants which require TCEQ Modeling and Effects Review
Applicability (MERA) analysis. MERA Evaluation does not apply to chemical species that have a state
air quality standard or NAAQS and certain activities have been pre-evaluated for impacts by the TCEQ4.
Table 6. Summary of Potential to Emit in Tons per Year for Compounds Subject to MERA
Emission Source Type of Equipment NH3
SC-7 SC-7 81.91
FUG-7 FUG-7 1.58
Total Sitewide 83.49
4
As specified in Appendix B of TCEQ’s APDG 5874 (version 5, revised on March 2018) Modeling and Effects Review
Applicability (MERA) Guidance document, emissions from combustion units fueled only by pipeline-quality natural gas and
emissions of volatile organic compounds from emergency diesel engines have been reviewed for health effects and are not
expected to cause adverse health effects.
12
4 AIR QUALITY REGULATORY REVIEW
The following section describes the potentially applicable federal and state air quality regulations as
applicable to the Project. Section 4.1 contains a discussion of federal regulations including Major New
Source Review requirements and potentially applicable New Source Performance Standards (NSPS) and
National Emissions Standards for Hazardous Air Pollutants (NESHAP), and other federal regulations.
Section 4.2 discusses the potentially applicable TCEQ air quality regulations.
4.1 Federal Regulations

4.1.1 Prevention of Significant Deterioration
The federal PSD rules are codified at 40 CFR 51, Subpart I, and 40 CFR §52.21 and are incorporated by
reference into 30 TAC §116.160 with certain exceptions noted. The NSR/PSD rules define a major source
as any source with the potential to emit 250 tpy or more of a criteria pollutant, with the exception of
categorical sources, in which case the threshold is 100 tpy. The PSD program provides specific permit
requirements for major sources and major modifications to existing major sources that are located in
unclassified areas or areas classified as being in attainment of the NAAQS.
The Newman Generating Station is considered an existing major stationary source under 40 CFR Part
52.21(b)(1)(i) and is considered a PSD-named categorical source (i.e., Fossil Fuel-Fired Steam Electric
Plants of more than 250 million Btu/hr heat input). Thus, fugitive emissions must be included when
assessing modifications at the site.
Modifications to an existing PSD major source are considered major modifications if the project will
result in a significant emission increase of a regulated NSR pollutant. Significant emission rates (SERs)
are defined in 40 CFR §52.21(b)(23). Since the site is not located within 10 kilometers of a Class I area,
52.21(b)(23)(i) establishes the emission rates that would be considered to result in a significant emissions
increase.
The following two-step process is followed to determine if PSD major review is needed for a project:
1. The project emission increase is determined by subtracting the baseline actual emission rate from
the planned emission rate on a pollutant-by-pollutant basis. Project emission decreases can be
included in this step.5 If the emissions for a given pollutant from the new or modified emission
sources equals or exceeds the PSD SER, then an applicability threshold test (netting) in step 2 is
required.
2. In this step, a netting analysis is conducted which is a summation of the emission increases from
the current project plus all creditable emission changes (both increases and decreases) within the
contemporaneous period. If the result of the netting analysis equals or exceeds the PSD
significant emission rate, then the modification is considered to be a major modification, and PSD
review is required.
Only new emission units will be installed under the Project; no existing units will be modified or affected.
Therefore, the emission increases associated with the Project have been determined based on comparing
5
In a March 13, 2018, Memorandum entitled “Project Emissions Accounting Under the New Source Review Preconstruction
Permitting Program,” EPA clarified that emission decreases associated with a project can be included under the “project
emissions accounting” performed in Step 1.
13
the new facilities’ PTEs to their baseline emission rate of zero for each pollutant.6 No netting analysis is
required.
The SER are listed in Table 4 for the regulated NSR pollutants that will be emitted as a result of this
Project and compared against the project PTE. The construction of the Project is considered a PSD major
modification since the project PTE is above the SER with respect to several regulated NSR pollutants.
Additionally, since the project results in an emission increase above the SER level for at least one
regulated NSR pollutant, GHG pollutants are subject to the regulation and thus also subject to PSD
review.
PSD review is required for the regulated NSR pollutants and GHGs (in the form of CO2e) that exceed the
significant emissions increase thresholds of 40 CFR Part 52 with the exception of PM10. The Newman
Generating Station is located in the city of El Paso, an area that has been designated moderate
nonattainment for PM10. Therefore, in accordance with 40 CFR Part 52 Section 52.21(i)(2), PM10 is not
subject to PSD review. Based on project emission rates, NOx, CO, PM, PM2.5, VOC, and CO2e are subject
to PSD review. PSD review consists of a control technology analysis (see Section 5.1), an air quality
analysis (see Section 6), and additional analysis of impacts on visibility, soils, vegetation, and growth in
the area of the project (see Section 6.8).
4.1.2 Nonattainment New Source Review

The federal pre-construction review for a new or modified major source located in a nonattainment area is
commonly referred to as Nonattainment New Source Review (NNSR) with rules codified in 40 CFR 51
and referenced in 30 TAC §116.150 – 116.151. NNSR applies on a pollutant-by-pollutant basis to new
major sources or major modifications located at existing major sources of the pollutants that are classified
as nonattainment for a criteria pollutant. Although major source and major modification thresholds are
generally lower for NNSR than for the PSD program, the general approach to determining if a project
results in a significant emission increases is the same as described in the previous section for PSD review.
The Newman Generating Station is located in an area which is considered to be in attainment or

unclassified for CO, NO2, SO2, PM2.5, Pb, and ozone. The city of El Paso and certain surrounding areas
are currently classified as moderate nonattainment with respect to the NAAQS for PM10.
As shown in Table 4, the Project is a major modification as defined in 40 CFR Part 51 since it has the
potential to emit greater than the SER for PM10 listed in 40 CFR §51.165(a)(1)(x)(A) of 15 tons per year.
Therefore, the project is subject to NNSR for PM10. NNSR requires that the project applicant install
equipment to ensure the lowest achievable control technology (LAER) from project sources, obtain
emissions offsets, conduct a compliance history review, and provide an opportunity for public
involvement. A review of these NNSR elements is provided in Section 8.
4.1.3 New Source Performance Standards

Section 111 of the Clean Air Act authorized the EPA to develop technology-based standards that apply to
specific categories of stationary sources. These standards are referred to as New Source Performance
Standards (NSPS) and are found in Title 40 CFR Part 60. NSPS applies to new, modified, and
reconstructed affected facilities in specific source categories. Pursuant to 30 TAC §116.111(a)(2)(D), the
TCEQ requires that a permit application demonstrate that emissions from a proposed project will meet the
requirements of applicable NSPS. Table 7 identifies the subparts of 40 CFR 60 that are applicable the
Project.
6
Per TCEQ (APDG 5881v7, Revised 10/18) Major New Source Review – Applicability Determination.
14
Subpart Subject Applicability
A General Provisions Yes
Standards of Performance for Stationary Compression Ignition Internal Combustion
IIII Yes
Engines
KKKK Standards of Performance for Stationary Combustion Turbines Yes
TTTT Standards of Performance for Greenhouse Gas Emissions for Electric Generating Units Yes
Subpart A contains general requirements for notification, testing, and reporting for the NSPS program.
The subpart applies to each project that has an affected source as defined under another subpart. As the
Project has units subject to one or more standards under 40 CFR 60 as discussed below, Subpart A applies
to the Project.
Subpart IIII applies to owners and operators of stationary compression ignition (CI) internal combustion
engines (ICEs). This regulation applies to the firewater pump engine (FIN: FIRE-2) which has a
displacement of less than 30 liters per cylinder and therefore must comply with the emission standards
listed in Table 4 of Subpart IIII for engines with a maximum engine power between 75 and 100
horsepower applicable to the model year of the engine. Based on the manufacturer’s specifications
provided, the firewater pump will meet these limitations.
Subpart KKKK applies to stationary combustion turbines with a heat input at peak load equal to or
greater than 10 MMBtu per hour based on the higher heating value of the fuel which commenced
construction, modification or reconstruction after February 18, 2005. Therefore, the simple cycle turbine
(FIN: SC-7) is subject emission limits for NOx and SO2 under Subpart KKKK. Per Table 1 to
Subpart KKKK a NOx emission standard of 25 ppm at 15 percent O2 (or 1.2 lb/MWh of useful output)
applies to a new turbine firing natural gas with a heat input at peak load of greater than 50 MMBtu/hr but
less than or equal to 850 MMBtu/hr. Based on the manufacturer’s specifications provided, the turbine
will meet the NOx emission standard. Per 40 CFR §60.4330(a), three options are available for SO2
compliance: an exhaust emissions standard, a fuel standard, and a biogas standard. Based on the
manufacturer’s specifications provided and the very low sulfur content of the natural gas burned, EPE
will select one of the first two options for compliance. EPE must also meet the applicable monitoring,
reporting, performance testing, and general compliance requirements listed in Subpart KKKK.
Subpart TTTT applies to stationary combustion turbines that commence construction after January 8,
2014 that have a base load rating greater than 250 MMBtu per hour of fossil fuel and serve a generator or
generators capable of selling greater than 25 MW of electricity to a utility power distribution system.
Therefore, the simple cycle turbine (FIN: SC-7) is subject to the applicable emission limitations for CO2.
The proposed unit will meet the emission standard of 120 lb CO2/MMBtu specified in Table 2 of Subpart
TTTT which is applicable to newly constructed or reconstructed stationary combustion turbines that
supply the design efficiency or fifty percent, whichever is less, times its potential electric output or less as
net-electric sales on either a 12-operating month or a 3-year rolling average basis and combusts more than
90% natural gas on a heat input basis on a 12-operating month rolling average basis. The unit must also
meet the applicable, monitoring and compliance demonstration procedures, notification, reporting,
recordkeeping, and general compliance requirements listed in Subpart TTTT.
Table 8 identifies the subparts of 40 CFR 60 that are not applicable to the Project and provides a brief
justification.
15
Reason for
Subpart Subject
inapplicability
D/Da/Db/Dc Standards of Performance for Various Types of Steam Generating No steam generating units
Units. are being installed as part
of the project
Kb Standards of Performance for Volatile Organic Liquid Storage Vessels No storage vessels with a
(Including Petroleum Liquid Storage Vessels) for which Construction, capacity greater than or
Reconstruction, or Modification Commenced After July 23, 1984 equal to 75 cubic meters
that are used to store
volatile organic liquids are
being installed as part of
the project.
GG Standards of Performance for Stationary Gas Turbines 40 CFR Part 60 Subpart
KKKK Section 60.4305(b)
states that stationary
combustion turbines
regulated under Subpart
KKKK are exempt from
the requirements of 40
CFR Part 60, Subpart GG
4.1.4 National Emission Standards for Hazardous Air Pollutants

National Emission Standards for Hazardous Air Pollutants (NESHAPs) are stationary source standards
for HAPs. The NESHAPs promulgated after the 1990 Clean Air Act Amendments are found in 40 CFR
63. These standards require application of technology-based emissions standards referred to as Maximum
Achievable Control Technology (MACT). Because of this, these post-1990 NESHAPs are also referred to
as MACT standards. Some MACT standards include requirements for area sources in addition to HAP
major sources.
NESHAPs and MACTs are incorporated by reference into 30 TAC §113 with certain exceptions noted.
Moreover, 30 TAC §116.111(a)(2)(E) – (F) requires that a permit application demonstrate that emissions
from a proposed project will meet the requirements of applicable NESHAPs and MACT standards.
Applicable citations are listed in Table 9.

Subpart Subject Applicability
A General Provisions Yes
YYYY National Emission Standards for Hazardous Air Pollutants for Stationary Combustion
Yes
Turbines
ZZZZ National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Yes/Satisfied by
Internal Combustion Engines NSPS IIII
DDDDD National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial,
Yes
Commercial, and Institutional Boilers and Process Heaters
Subpart A contains general requirements for notification, testing, and reporting for the MACT program.
The subpart applies to each project that has an affected source as defined under another subpart. As the
Project has units subject to one or more standards under 40 CFR 63 as discussed below, Subpart A applies
to the Project.
Subpart YYYY applies to existing, new, or reconstructed stationary combustion turbines located at a
major source of HAP emissions. Since the site will be a major source of HAP emissions, the new unit is
16
an affected source under MACT YYYY and must be in compliance upon startup of the unit. However,
there is currently a stay of requirements for new, lean premix gas-fired stationary combustion turbines and
diffusion flame gas-fired stationary combustion turbines pursuant to §63.6095(d). Until the EPA takes
final action to require compliance and publishes a document in the Federal Register, EPE must only
comply with the initial notification requirements set forth in §63.6145. Once the stay of requirements is
lifted, however, the new unit must comply with the applicable notification, testing, monitoring,
recordkeeping, and reporting requirements in MACT YYYY and must comply with the operational and
emission limitations therein. These requirements as currently promulgated include but are not limited to:
limiting the concentration of formaldehyde to 91 ppbvd or less at 15% O2, continuously monitoring the
catalyst inlet temperature, conducting an initial and subsequent annual emission tests for formaldehyde,
submitting semi-annual compliance reports according to the requirements of §63.6150, and complying
with the general recordkeeping, reporting, monitoring, testing, and compliance requirements in Subpart A
as specified in Table 7 of MACT YYYY.
Subpart ZZZZ applies to major and area sources of HAP that include stationary internal combustion
engines. Because the generator engine will be a new compression ignition stationary reciprocating
internal combustion engine rated less than 500 horsepower located at a major source of HAPs, the unit is
required to meet the requirements of 40 CFR 60, Subpart IIII, in accordance with 40 CFR §63.6590(c)(7),
and no other requirements under Subpart ZZZZ apply.
Subpart DDDD applies to major sources of HAP that industrial, commercial, and institutional boilers
and process heaters. The new line heater would be subject to this regulation since it is a process heater
located at a major source of HAPs. The unit is rated less than 5 MMBtu/hr and burns natural gas.
Therefore, the unit must complete a tune-up every five years, must submit compliance reports in
accordance with §63.7550 every five years, and must comply with the general requirements in Subpart A
as specified in Table 10 of Subpart DDDDD.
Table 10 identifies the subparts of 40 CFR 63 that are not applicable to the Project and provides a brief
justification.

Subpart Subject Reason for inapplicability
UUUUU National Emission Standards for Hazardous Air Pollutants: Coal-and Oil- The Proposed simple-cycle turbine
Fired Electric Utility Steam Generating Units is subject to the requirements of 40
CFR Part 63 Subpart YYYY and is
not considered a coal- or oil-fired
electric utility steam generating
unit. For these reasons the new
unit is exempt from the
requirements of this Subpart.
4.1.5 Federal Operating Permitting Programs

40 CFR Part 71 requires that major sources obtain an operating permit consistent with permitting program
requirements of Title V of the Clean Air Act (CAA). However, states may be delegated authority to
implement and enforce an operating permit program where the program has been granted approval under
40 CFR Part 70. Texas has established state air quality permitting systems consistent with the
requirements of Title V of the CAA and has delegation of authority to implement a State operating permit
program. Thus, EPE will submit a significant revision application for Permit No. O80 to the TCEQ in
accordance with the requirements of 30 TAC Chapter 122. EPE will also provide a copy of the
application to the EPA in accordance with 40 CFR Part 70, §70.8.
17
4.1.6 Acid Rain Program
40 CFR Part 72 establishes operating permit program requirements for affected sources and affected units
under the Acid Rain Program, pursuant to Title IV of the CAA. The purpose of this Part is to implement
an SO2 and NOx air pollution control and emission reduction program. These requirements supplement
the requirements under 40 CFR Part 70 and 71 for approving and implementing State operating permit
programs for affected units under the Acid Rain Program. Part 72 allows for states to adopt and enforce
the provisions of the Acid Rain Program and TCEQ has been granted this authority. The Project will
include an affected unit under the Acid Rain Program, thus, EPE will address Acid Rain Program
requirements for the simple cycle turbine (FIN: SC-7) in the SOP significant revision application to the
TCEQ in accordance with the requirements of 30 TAC Chapter 122. EPE will also provide a copy of the
application to the EPA for review.
4.1.7 Stratospheric Ozone Protection

40 CFR Part 82 establishes regulations to reduce emissions of substances that deplete the ozone layer.
EPE will comply with potentially applicable requirements for any consumption, recycling, and importing
of controlled substances, for motor vehicle servicing involving ozone-depleting substances, and for the
operation and maintenance of applicable air conditioning units. Facility personnel do not perform air
conditioning maintenance. However, EPE will be responsible for ensuring that their air conditioning
maintenance is performed by vendors in compliance with 40 CFR Part 82.
4.1.8 Clean Air Interstate Rule

The Clean Air Interstate Rule addresses power plant pollution that drifts from one state to another through
the implementation of a cap and trade system designed to reduce SO2 and NOx. TCEQ has adopted rules
to implement the federal Clean Air Interstate rule via 30 TAC Chapter 101, Subchapter H and 30 TAC
Chapter 122, Subchapter E. However, CAIR was replaced by the Cross-State Air Pollution Rule as of
January 1, 2015 and is thus not applicable to the Project.
4.1.9 Cross-State Air Pollution Rule

The Cross-State Air Pollution Rule (CSAPR) Requires states in the eastern half of the U.S. to reduce
power plant emissions that cross state lines and contribute to ground-level ozone and fine particle
pollution in other states. A cap and trade system implemented via 40 CFR Part 97 has been established to
reduce SO2 and NOx. Sources in Texas are not subject to CSAPR as of September 29, 2017, when EPA
published a final rule which withdrew Texas from the SO2 and Annual NOx programs. Therefore,
provisions of CSAPR are not be applicable to the Project.
4.1.10 Mandatory Greenhouse Gas Reporting

40 CFR Part 98 establishes GHG calculation, monitoring, and reporting requirements. The GHGs
included in the reporting rule are CO2, CH4, N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs),
SF6, and other fluorinated gases.
Subpart A contains general requirements for EPA’s Mandatory Greenhouse Gas Reporting program. The
subpart applies to each site that has an affected source as defined under another Subpart. Sites with
affected facilities subject to reporting under other Subparts of the Mandatory Reporting Rule must report
if the sum of GHG emissions from all the affected facilities are greater than the reporting thresholds in 40
CFR §98.2(a)(1), 98.2(a)(2), or 98.2(a)(3).
18
Subpart C, General Stationary Fuel Combustion Sources, requires certain stationary fuel combustion
sources that are not subject to reporting under Subpart D, to report their annual GHG emissions if the
facility meets the applicability requirements of Subpart A.
Subpart D, Electricity Generation requires electricity generating units that are subject to the requirements
of the Acid Rain Program and any other electricity generating units that are required to monitor and report
CO2 mass emissions in accordance with 40 CFR Part 75 to report annual GHG emissions if the facility
meets the applicability requirements of Subpart A. EPE will comply with the requirements of this
subpart.
4.2 State Regulations

4.2.1 Texas Administrative Code, Title 30
The TCEQ Air Quality Regulations are codified in 30 TAC Chapters 101 - 122. Table 11 identifies
regulations applicable to the Project described in this application.
Table 11. Applicable TCEQ Air Quality Regulations

Chapter,
Subchapter, Subject Applicability Compliance Explanation
Division
Chapter 101, General Rules Yes The Project operations at the site will comply with the general
Subchapter A air quality rules that apply in Subchapter A.
Chapter 101, Emissions Events and Scheduled Yes The Project operations at the site will comply with the
Subchapter F Maintenance, Startup, and notification and reporting requirements associated with
Shutdown Activities Emission Events and MSS activities.
Chapter 101, Emissions Banking and Trading Yes The applicant seeks to obtain an NNSR permit by participating
Subchapter H in the TCEQ Emission Banking and Trading Program to offset
the Project emission increase for facilities to be authorized
under the permit.
Chapter 111 Control of Air Pollution from Visible Yes The Project will not cause visible emissions from the
Emissions and Particulate Matter stationary vents associated with the project in excess of the
limitations specified in Rule §111.111(a)(1). The stationary
combustion turbine and line heater will be fired by pipeline
quality natural gas and the firewater pump engine will use low
sulfur diesel as fuel. Compliance with the opacity limitations
will be demonstrated using the appropriate method specified
in Rule §111.111(a)(1)(F). Additionally, the precautions to
achieve control of dust emissions from construction listed in
Rule §111.145 will be applied since the site is located within
the City of El Paso.
Chapter 112, Control of Sulfur Dioxide Yes The Project will not cause emissions of SO2 such that the net
Subchapter A ground level concentration of SO2 exceeds 0.4 parts per
million by volume averaged over any 30-minute period. EPE
has demonstrated compliance with the requirements of this
Subchapter by conducting a TCEQ State Property Line
Analysis.
Chapter 112, Control of Hydrogen Sulfide Yes The Project will not cause emissions of H2S such that the net
Subchapter B ground level concentration of H2S exceeds the standards
specified in Rule §112.31 or 112.32. The Project emission
sources fire pipeline quality natural gas and the firewater
pump is fueled by low sulfur diesel. Therefore, the H2S
emissions are negligible.
19
Chapter,
Division
Chapter 112, Control of Sulfuric Acid Yes The Project will not cause emissions of sulfuric acid such that
Subchapter C the net ground level concentration of sulfuric acid exceeds the
standards specified in Rule 112.41(a). EPE has demonstrated
compliance with the requirements of this Subchapter by
conducting a TCEQ State Property Line Analysis.
Chapter 113, National Emission Standards for Yes The Project will comply with the applicable Requirements of
Subchapter C Hazardous Air Pollutants for Source 40 CFR Part 63 (as specified in Table 9).
Categories (FCAA, §112, 40 CFR
PART 63)
Chapter 116, New Source Review Permits, Permit Yes Prior to beginning work on the Project construction, EPE will
Subchapter Application obtain a permit as required under Rule §116.111 of this Title.
B, Division 1 Additionally, this application includes the seal of a Texas
licensed professional Engineer since the capital cost of the
project is above $2 million.
Chapter 116, New Source Review Permits, Fees Yes EPE as included payment of a fee determined based on the
Subchapter criteria in Rule §116.141 concurrent with submittal of the
B, Division 4 permit application for the Project.
Chapter 116 New Source Review Permits, Yes The Project is subject to Rule §116.151 which is applicable to
Subchapter Nonattainment New Source Review new major modifications in nonattainment areas for pollutants
B, Division 5 Permits other than ozone. The City of El Paso is a nonattainment area
for PM10. Since Project emission of PM10 are greater than the
major modification levels in Table I of §116.12, the Project
emission units will comply with the lowest achievable emission
rates (LAER) for PM10, will be incompliance with all applicable
state and federal emission limits and standards, and will
obtain offsets for PM10 as specified in §116.12 Table I. The
application includes an analysis of alternative sites, sizes,
production processes, and control techniques for the
proposed sources and demonstrate that the benefits of the
proposed location and source configuration significantly
outweighs the environmental and social costs for the chosen
location.
Chapter 116, New Source Review Permits, Yes The Project is a major modification in an attainment or
Subchapter Prevention of Significant unclassifiable area for criteria pollutants except PM10. The
B, Division 6 Deterioration Review Project exceeds the major modification thresholds for NOx,
ozone (with respect to VOC and NOx), CO, PM, and PM2.5 and
is subject to PSD review for those pollutants. Additionally, the
Project is also a major modification with respect to GHG
emissions expressed as CO2e and is subject to PSD review
for GHG emissions. Therefore, an impacts analysis will be
conducted to verify that the Project will not cause or contribute
to a violation of any NAAQS or cause or contribute to impacts
on visibility, soils, vegetation, and growth in the area of the
project. Additionally, the emission units to be constructed for
the Project will be subject to BACT.
Chapter 116, New Source Review Permits, Yes The provisions of this division are potentially applicable
Subchapter Emission Reductions: Offsets insofar as they relate to New Major Source or Major
B, Division 7 Modifications in Nonattainment Areas Other than Ozone. This
section establishes criteria for using emission reductions as
offsets.
Chapter 116 Permit Renewals Yes EPE will comply with the renewal applications submittal,
Subchapter D public notification and comment procedures, renewal
application fee requirements, and the timelines for submitting
such documentation as applicable after issuance of the
permit. The issued permit will be subject to review every ten
years after the date of issuance.
20
Chapter,
Division
Chapter 118 Control of Air Pollution Episodes Yes In the event that an air pollution episode is declared, EPE will
comply with the requirements of the TCEQ.
Chapter 122 Federal Operating Permits Program Yes Owners and operators of a site that is a major source and a
site with an affected unit as defined in 40 CFR Part 72 subject
to the requirements of the Acid Rain Program are subject to
the requirements of this chapter. EPE will meet the
requirements of the federal operating permits program
through revision of the currently effective Federal Operating
Permit and Acid Rain Permit O80.
Sections of 30 TAC Chapters 101 - 122 that are not applicable are shown in Table 12 with rationalization
for determining negative applicability.
Table 12. TCEQ Air Quality Regulations Determined Inapplicable

Chapter ,
Subchapter, Subject Applicability Negative Determination of Applicability
Division
Chapter 101, Failure to Attain Fee No The site is not subject to the requirements of this subchapter
Subchapter B because the site is not located in the Houston-Galveston-
Brazoria one-hour ozone nonattainment area.
Chapter 106 Permits by Rule No No permits by rule are being claimed for the Project.
Chapter 112, Control of Total Reduced Sulfur No These emission limitations apply only to Kraft Pulp Mills.
Subchapter D
Chapter 115, General Volatile Organic Compound No The Project will not include a storage tank storing VOC with a
Subchapter B Sources true vapor pressure greater than or equal to 1.5 psia and is
therefore exempt from the requirements of Subchapter B,
Division 1. Additionally, the project will not result in venting of
VOCs from a process vent as specified in Subchapter B,
Division 2. No other Divisions in Subchapter B are potentially
applicable to the Project.
Chapter 115, Volatile Organic Compound Transfer No This Subchapter regulates Volatile organic compound transfer
Subchapter C Operations operations. The operations associated with the Project do not
include VOC transfer operations.
Chapter 116, New Source Review Permits, No No portable facilities are being installed as part of the Project.
Subchapter Portable Facilities
B, Division 8
Chapter 116, Plant-Wide Applicability Limits No EPE is not seeking to obtain a Plant-Wide Applicability Limit.
Subchapter C
Chapter 116, Hazardous Air Pollutants: Yes The provisions of this subchapter implement Federal Clean
Subchapter E Regulations Governing Constructed Air Act §112(g) and 40 CFR Part 63 Hazardous Air Pollutants:
or Reconstructed Major Sources Regulations Governing Constructed or Reconstructed Major
Sources, Subpart B, Requirements for Control Technology, as
amended December 27, 1996. Since the site is a major
source of Hazardous Air Pollutants, this Subchapter is
applicable.
Chapter 117 Control of Air Pollution from Nitrogen No The Project is not located in an ozone nonattainment area. In
Compounds addition, none of the requirements under this chapter for
areas outside of ozone nonattainment areas are applicable to
the Project.
21
5 AIR POLLUTION CONTROL EVALUATION
The TCEQ recently published an excel spreadsheet template labeled Form PI-1 General Application
(formerly referred to as the NSR Application Workbook). Submittal of this template is required for
various types of NSR Permit applications, including PSD and Nonattainment major modification projects.
This template includes Tier I BACT requirements for each source type and pollutant, as applicable.
With respect to pollutants not subject to Major Source BACT or LAER analysis (H2SO4, SO2, NH3, and
HAPs), the TCEQ uses a three-tiered approach to evaluate the BACT in NSR air permit applications. The
evaluation begins at the first tier and progresses in sequence to the second and third tiers only if
necessary.7 Accordingly, EPE has completed the applicable section of the Form PI-1 General Application
and proposes to accept the Tier I BACT requirements pre-populated in the TCEQ Form PI-1. For sources
or pollutant types where BACT is not prescribed, additional notes in the PI-1 form spreadsheet justify the
chosen BACT. A copy of the PI-1 General Application is included in Appendix D and includes a Table
specifying chosen BACT for each source and pollutant.
Where PSD BACT review or LAER Analysis is required for specific pollutants, additional justification
must be submitted as an attachment to the TCEQ Form PI-1 workbook to meet the more stringent
requirements for Major Source Air Pollution Control Evaluations. As such, this application includes
additional analysis with respect to PSD BACT and LAER in Section 5.1 and 5.2, respectively.
5.1 PSD BACT Review

Federal BACT review is required for pollutants emitted as a result of a major project where the emission
rate is greater than the pollutant’s SER specified in 40 CFR Part 52. Federal BACT standards require that
the maximum degree of reduction is achieved from a proposed major stationary source; However, on a
case-by-case basis, the analysis may account for energy, environmental, and economic impacts, and other
costs. Thus, alternate methodologies to reduce emissions such as design, equipment, work practice, or
operation standards may be used in lieu of emission limitations provided that these methods will achieve
equivalent results in emission reduction and will not exceed any rates allowed by applicable Standards in
40 CFR Parts 60, 61, or 63.
The proposed Project will require Federal BACT review for CO, NOX, PM, PM2.5, Ozone (VOC and
NOx), and GHG emissions. With respect to criteria pollutant emissions, the BACT analysis has been
conducted using the TCEQ’s Three-Tiered approach. This approach to the analysis satisfies both the state
and federal BACT analysis requirements when combined with a review of recently issued and approved
permits and control technologies contained within EPA’s RACT/BACT/LAER Clearinghouse (RBLC).8
Examples of recently issued permit BACT and RBLC datasets exported from the EPA database are
included in Appendix C. Each of the emission sources proposed have well established controls with
documented and proven efficiency that have been accepted as BACT. This allows the use of Tier I of the
TCEQ’s Three-Tiered approach to be used to determine BACT for all proposed sources emitting criteria
pollutants.
The BACT analysis with respect to GHG emissions9 was conducted using the EPA’s Top-Down
methodology which includes the following steps: Identify all control technologies, eliminate technically
infeasible options, ranking control technologies by effectiveness, evaluating the most effective controls,
7
Per TCEQ (APDG 6110v2 01/2011) Air Pollution Control.
8
Ibid.
9
One exception to this is that EPE is using TCEQ’s Tiered methodology to concurrently evaluate BACT for natural gas fugitive
component leaks since the BACT control methodologies for VOC would have the effect of controlling GHG as well.
22
and selecting BACT. To conduct this analysis, EPE followed guidance issued by EPA in March 2011
entitled “PSD and Title V Permitting Guidance for Greenhouse Gases”.
For each of the Project emission sources, the proposed emission reduction options are discussed below.

The simple cycle turbine unit (SC-7) will comply with BACT standards for the pollutants subject to PSD
BACT review using the following emission reduction options:
 Selective Catalytic Reduction (SCR) and oxidation catalyst technology
 Dry Low-NOx burner
 Firing pipeline quality natural gas
 Ensuring good combustion practices during unit operation
 Keeping startup and shutdown duration to a minimum.
The following subsections provide a pollutant-by-pollutant review of BACT for normal operations. Note
that the emission limits proposed as BACT for normal operations cannot necessarily be achieved during
startup or shutdown. As BACT must be applied at all times and the proposed normal operation emission
limit may not be achievable during other operating modes, a separate BACT analysis is followed for MSS
emissions.
5.1.1.1 NOx Emissions
TCEQ’s Tier I BACT for simple cycle turbines is 5.0 to 9.0 ppmvd at 15% O2 for NOx, which may be
achieved with a dry low NOx burner, water/steam injection, limiting fuel consumption, and/or SCR
technology.
Further analysis to determine BACT included a review of EPA’s RBLC database and review of NSR
permits issued by TCEQ. Review of these two information sources demonstrate that NOx outlet
concentrations of as low as 2.0 ppmvd at 15% O2 have been achieved for gas turbines rated 20 MW and
greater. However, very few simple cycle turbines permitted at this level were found, and these were
required to meet LAER rather than BACT requirements for NOx. Outlet concentrations as low as 2.5
ppmvd at 15% have been achieved by simple cycle turbines subject to PSD BACT review using a variety
of control technologies, including SCR, water injection, and dry low-NOx burners.
The simple-cycle turbine will be equipped with a dry low-NOx burner which will reduce thermal NOx
formation by reducing the combustion zone temperatures. Additionally, EPE proposes the use of SCR
technology for post-combustion control. SCR technology provides post-combustion control of NOx
emissions through the injection of NH3 which reacts to chemically reduce NOx to elemental N2. These
control technologies, along with firing solely pipeline quality natural gas will allow the unit to meet an
emission rate of 2.5 ppmvd NOx at 15% O2 as proposed BACT during normal operations. This outlet
concentration is below the range for TCEQ’s Tier I BACT and at the low end of the ranges found in
EPA’s RBLC database and recently-issued TCEQ NSR Permits..
To ensure compliance, a Continuous Emissions Monitoring Systems (CEMS) will be installed to ensure
optimal ammonia injection rates and verify that the unit is achieving the target emission reductions.
23
5.1.1.2 CO Emissions
TCEQ’s Tier I BACT for simple cycle turbines is 9.0 to 25.0 ppmvd at 15% O2 for CO which is typically
achieved with good combustion practices, an oxidation catalyst, or a combination of both.
Upon review of the EPA’s RBLC database, turbines operating in simple-cycle mode firing natural gas
typically demonstrated a CO outlet concentration between 4 and 29 ppmvd at 15% O2. Recently issued
TCEQ NSR Permits had a similar range, though there were a few turbines operating in simple cycle mode
that had a rating of 2.0 ppmvd CO at 15% O2. Therefore, EPE’s proposes to use good combustion
practices in combination with post-combustion control of CO through installing an oxidation catalyst.
Since the selected control technology and best management practices are widely considered the most
stringent CO pollutant control mechanisms, no additional control technologies were evaluated for this
pollutant. Implementing these control techniques allows the simple-cycle turbine to achieve a CO outlet
concentration of 3.0 ppmvd at 15% O2 as proposed BACT during normal operations. This outlet
concentration is below the range for TCEQ’s Tier I BACT and at the low end of the ranges found in
EPA’s RBLC database and recently issued TCEQ NSR Permits.
To ensure compliance, the unit will be operated in accordance with manufacturer’s recommended
specifications to ensure good combustion and the unit will be equipped with a CEMS to monitor CO
emissions.
5.1.1.3 VOC Emissions
TCEQ’s Tier I BACT for simple-cycle natural gas-fired turbines is 2.0 ppmvd at 15% O2 achieved
through good combustion practices.
Review of the EPA’s RBLC database and recently issued NSR permits showed that best management
practices and/or installation of a post-combustion control device are routinely accepted as BACT resulting
in authorized outlet VOC concentrations for simple-cycle natural gas turbines between 1.4 and 5 ppmvd
at 15% O2. The simple cycle turbine will be equipped with an oxidation catalyst, will burn pipeline
quality natural gas, and will be operated to ensure complete combustion. These management practices
along with equipping an oxidation catalyst will ensure the unit meets an outlet concentration of 2.0
ppmvd at 15% O2 as proposed BACT during normal operations. This outlet concentration is below the
range for TCEQ’s Tier I BACT and at the low end of the ranges found in EPA’s RBLC database and
recently issued TCEQ NSR Permits.
EPE will ensure compliance by fueling the unit solely with pipeline quality natural gas, monitoring fuel
consumption, and operating in a manner conducive to good fuel combustion by following the
manufacturer’s related instructions.
5.1.1.4 PM/PM2.5 Emissions
Since the source of emissions and emission control techniques for PM and PM2.5 are identical for the
simple-cycle turbine, the BACT analysis for these pollutants is being combined into one section. TCEQ
Tier I BACT for simple cycle turbine PM emissions includes best management practices to ensure good
fuel combustion and firing only pipeline quality natural gas. Pipeline-quality natural gas contains low ash
and sulfur content and therefore generates a lower amount of PM/PM2.5 emissions than generated by other
fuels. Complete combustion to reduce particulate emissions from partially combusted carbon compounds
also helps to reduce particulate matter emissions.
Review of the RBLC database and recently issued NSR permits verifies that exclusive use of pipeline
quality natural gas along with good combustion practices represents BACT. EPE therefore proposes as
24
BACT for PM/PM2.5 during normal operations to use solely pipeline-quality natural gas to fuel the
proposed unit, operate the unit to ensure good combustion of fuel, and complete the required quarterly
visible emission observations to ensure the unit is functioning properly and complying with opacity
standards.
5.1.1.5 MSS Emissions
Increased emissions during MSS events in comparison to steady state emission rates are largely
attributable to periods where add-on control device efficiency is limited. Operating conditions of the unit
during these periods are sub-optimal for efficient emission reductions. Therefore, TCEQ Tier I BACT for
turbine MSS activities includes minimizing the duration of MSS activities and operating the turbine in
accordance with best management and good air pollution control practices. EPE proposes implementing
the emission control recommendations of Tier I BACT.
Additionally, startup and shutdown emissions are impacted by unit-specific parameters and site-specific
conditions such as elevation, temperature, humidity, and fuel quality. The turbine vendor provided EPE
with site-specific data for the expected MSS emissions per event for the pollutants where reduced
efficiency of control equipment during MSS is a consideration. These values are conservative in that they
are based on worst-case ambient conditions. These values are used to inform the BACT analysis and
compare against similar units.
Review of RBLC database and recently issued NSR permits show that operators typically either abide by
a maximum hourly limit applicable during startups and shutdowns or limit the duration of startup and
shutdown events in accordance with the manufacturer’s information. In the case where a numeric
limitation in emissions is specified, the basis of the limitation often varies and is difficult to assess in
comparison with the limitations during start up and shut down of the Proposed unit. A brief discussion of
the RBLC database MSS limitations, where specified10, is included below.
For simple-cycle gas turbines, NOx emission limitations that are quantified in the RBLC database are
between 18.5 lb/hr for the lowest rated units up to at 86.38 lb/hr for higher rated units. Normalizing these
emission rates based on the rated capacity of the simple-cycle turbines allows a basis for comparison
since the amount of fuel combusted would be correlated with the turbines rated capacity and the fuel
combustion rate will roughly correlate with exhaust flow. Thus, it can be expected that hourly emission
rates during MSS will increase based on the rating of the unit. Based on the information in the RBLC
database, the hourly emissions during MSS events are generally higher than the Proposed unit’s emission
rate during MSS activities with respect to NOx once the rated capacity of the units are taken into
consideration. Appendix C lists the Proposed unit’s MSS emission rates in comparison to the RBLC
MSS emission rates normalized for MMBtu/hr or MW ratings. Thus, EPE proposes minimizing the
duration of events and operating the turbine in accordance with best management and good air pollution
control practices as BACT.
The Proposed unit startup emission rates for CO, normalized over MMBtu/hr rating was lower than 7 out
of 12 of the simple-cycle units where emission rate data from the RBLC database was able to be
evaluated for this analysis. Additionally, the CO emission rate during shutdown events for the Proposed
unit, was lower than 5 out of the 11 cases able to be evaluated from the RBLC database, though the
shutdown emission rate data from the database was hard to assess as there were inconsistencies between
what limitations were stated in the “Pollutant Compliance Notes” and the emission limits fields. Refer to
Appendix C for more detail. Thus, EPE proposes minimizing the duration of events and operating the
turbine in accordance with best management and good air pollution control practices as BACT.
10
Note that the data contained in the RBLC also demonstrates that in many cases simply limiting duration of startup and
shutdown events is often accepted as BACT.
25
VOC emission rates during MSS activities were rarely represented in the RBLC database, and the basis of
the few emission limitations found were difficult to assess. When MSS emissions for this contaminant
were addressed, a majority of the units stated that the time in startup or shutdown would be limited. Due
to the limited amount of data, BACT for VOC during MSS was not quantitatively assessed. However,
EPE’s proposed methods of limiting the duration of MSS events is consistent with BACT requirements
accepted in the RBLC database and other NSR permits.
Comparison of the turbines MSS emission rates to other units in the RBLC database is valuable in the
sense that it confirms that the unit is within the range of reasonable MSS emission rates. Ultimately
though, these emissions are based on the turbines design and the duration of the startup and shutdown
periods which may vary so this comparison is limited in value. The best control technique for MSS
emissions is to limit the duration of these events and to operate the unit in accordance with best
management practices.
For PM/PM2.5, minimal data was available in the RBLC dataset for MSS emissions for this pollutant.
However, based on the available data, the approach used to evaluate MSS NOx and CO emissions of
determining a normalized emission rate during MSS corrected based on the unit’s rating was again used.
Based on this approach the Proposed simple cycle unit emission rates would be on par or better than other
units in the RBLC dataset in terms of emissions during MSS activities. Therefore, EPE proposes to meet
BACT requirements by minimizing the duration of events and operating the turbine in accordance with
best management and good air pollution control practices.
EPE will ensure that startup and shutdown duration for the simple-cycle unit is minimized in order to
limit emissions from startup and shutdown events. Additionally, the simple-cycle turbine unit selected for
the Project generally performs well relative to other units represented in the RBLC database in terms of
criteria pollutant emissions during MSS events.
5.1.1.6 GHG Emissions
TCEQ has not specified a Tier 1 BACT for GHG emissions. Review of the RBLC database showed that
BACT for simple cycle units are typically in the range of 118-120 lb/MMBtu for CO2 and in the range of
1,300-1,700 lb/MWh. The emission rates for the proposed turbine are generally around 119 lb/MMBtu
and the emission rate of CO2 ranges from 1,150 – 1,200 lb/MWh at full load operation, which are both at
the lower end of the ranges found in the RBLC database. In the RBLC database, the mechanisms to
achieve BACT are primarily installing energy efficient units, operating and maintaining the unit in
accordance with manufacturer’s recommendations, good combustion practices, and using pipeline quality
natural gas. Examples of NSR permits that have been recently issued generally require that turbines meet
the CO2 emission limitations specified in 40 CFR Part 60, Subpart TTTT. The proposed unit will comply
with the CO2 emission limitations of NSPS TTTT.
Since TCEQ has not established BACT for GHG emissions, an EPA top-down approach to evaluating
BACT for GHG has been completed.
Step 1: Identify Control Options

 Energy Efficient Design
 Burning low-carbon intensity fuels
 Operation and Maintenance Procedures
 Good combustion Practices
 Carbon Capture and Storage
 Alternative Fuels
 Oxidation catalyst (to control CH4)
26
Efficient design of equipment is one of the foremost techniques to ensure that reduction in GHG
emissions. An efficiently designed unit has a high rate of electricity generation per unit of fuel burned.
The efficiency of the simple-cycle unit is approximately 40%. Energy efficiency reduces CO2, CH4, and
N2O since less fuel is required to produce each unit of energy. Another option to increase energy
efficiency would include combined heat and power generation.
Of the fossil fuels, natural gas is the lowest carbon intensity, meaning that per unit of fuel burned, less
CO2 emissions result when compared with other fossil fuels such as coal.
Operation and maintenance (O&M) procedures such as tuning and maintenance can increase the
performance of a unit and reduce degradation of the unit efficiency over time.
Good combustion practices would limit emissions of CH4 which has a higher global warming potential
than CO2, which is the product of complete CH4 combustion. Good combustion of methane can be
ensured by tuning the unit and ensuring adequate air fuel ratio, high combustion temperatures, and longer
residence time.
Installing an oxidation catalyst can reduce total hydrocarbon emissions from a unit through catalytic
oxidation and would also reduce uncombusted hydrocarbon emissions, including, to a certain degree,
methane emissions.
Using an alternative fuel such as biomass fuel is considered an alternative to natural gas that may help
reduce overall greenhouse gas emissions since it is a renewable fuel source and have a lower caloric value
than traditional fossil fuels.
Carbon capture and storage is the process by which CO2 is removed from exhaust gas streams and is
captured and stored in a manner that will not allow the CO2 to be emitted to the atmosphere. The most
widely demonstrated technique involves an amine absorption process which involves flue gas
compressions and refrigeration. The CO2 vent gas stream resulting from this process is then injected into
long-term storage in geologic formations via pipeline.
Step 2: Eliminate technically infeasible options
Of the above-mentioned control strategies, carbon capture and storage is, in this case, technically
infeasible given the additional processing requirements for the flue gas stream and construction of a CO2
pipeline injection system. Exhaust CO2 concentrations from natural gas streams are low and the efficiency
of capture of CO2 would be low as well. The additional processing equipment would also require energy
to run, which would have the effect of reducing the energy efficiency of the Project as a whole. The
required timeframe to implement this control strategy would vastly exceed the desired timeframe for
construction of the facility. Additionally, as there is not currently a CO2 injection pipeline associated with
the facility, this would need to be constructed and would create significant amounts of fugitive dust and
off-road equipment exhaust emissions in an area that is already in nonattainment for PM10. This option is
therefore eliminated.
Combustion of biomass fuel is considered infeasible due to the infrastructure changes required to
transport biomethane fuel to the site since there is not an existing nearby option and the additional PM10
emissions construction of the additional infrastructure would cause. Biomass fuel also has potential
drawbacks when considering emissions of other criteria pollutants. Given that the unit will be located in a
PM10 nonattainment area it is desirable that fuel combustion be as efficient and clean as possible. Biogas
initially contain impurities unless routed through a processing facility. In short, biomass fuel combustion
would not be a feasible option unless biogas is processed and routed to the same natural gas pipeline
already serving the plant (which is not under EPE’s control). This option is therefore eliminated.
27
Step 3: Rank remaining control technologies
1. Eliminate unnecessary GHG emissions
Ensuring efficient design and operation is the best method to reduce GHG emissions. Purchasing and
properly maintaining a unit to achieve maximum power generation per unit of fuel reduces unnecessary
fuel combustion and associated products of combustion including GHG. Also, using low-carbon intensity
natural gas is an effective way of limiting the emissions of CO2 per MMBtu. Natural gas is the lowest
carbon intensity fossil fuel.
2. Post-combustion control
Oxidation catalyst will reduce methane emissions by converting the methane to CO2 which has a lower
global warming potential.
3. Tuning unit operation to reduce GHG emissions
Increasing the temperature, residence time, and oxygen content of the combustion chamber may reduce
emissions of CH4, However, this type of environment would lead to an increase in NOx emission rates and
the incremental decrease of CH4 emissions which will be combusted fairly efficiently already would not
be worth the increase in NOx emissions that would result. Note also that the CH4 emissions after
accounting for the global warming potential are a small contributor (<0.01%) to the overall CO2e
emissions from the turbine
4. Combined Heat and Power Generation
While this method can reduce GHG emissions by supplying necessary heat to the overall facility, this is
not a feasible solution in this instance as a primary purpose of the proposed unit is to produce
supplemental power during peak demand. Combined cycle units have very long startup cycles, whereas a
simple cycle unit like the one proposed can start up in less than one hour. Therefore, though combined
heat and power generation is an energy efficient way to produce power, in this case it would defeat the
purpose of the Project.
5. Eliminate the SCR
N2O emissions are another greenhouse gas that may be emitted as an intermediary product of combustion.
SCR catalyst systems can, under certain conditions, increase N2O emissions due to partial oxidation of
ammonia. However, the SCR system also drastically reduces NOx emissions so the reduction in the trace
amounts of N2O is not particularly desirable given the additional NOx emissions that would result.
Additionally, NOx emissions may also ultimately be converted to N2O through chemical reactions once
emitted, so any incremental decrease in N2O through removal of the SCR could be offset by conversion of
additional NOx emissions to N2O. Note also that the N2O emissions after accounting for the global
warming potential are a very small contributor (<0.01%) to the overall CO2e emissions.
Step 4: Evaluate most effective controls and document results
The best approach to limit GHG emissions is to ensure efficient performance of the unit via purchasing a
unit with efficient design (e.g. good power generation efficiency), properly maintain the unit. Ensuring
good combustion efficiency of the fuel to limit higher global warming potential gas emissions is also
important. However, it is important to balance the combustion zone characteristics to also maximize
reductions in other criteria pollutant emissions. The efficiency of the proposed unit can also be maintained
through operational and maintenance procedures to minimize any degradation in unit efficiency.
28
The unit will also be equipped with an oxidation catalyst mainly because an oxidation catalyst was chosen
as an effective post-combustion control of CO and VOC emissions. The oxidation catalyst will have the
co-benefit of reducing uncombusted methane emissions.
Step 5: Select BACT
EPE proposes a multi-tiered approach to eliminate unnecessary GHG emissions which includes
purchasing and properly maintaining a unit that is inherently efficient at achieving the intended purpose
and fires low-carbon intensity natural gas. EPE will also install an oxidation catalyst to reduce
hydrocarbon emissions, including methane. This proposed BACT is consistent with results found in the
RBLC database and recently issued NSR permits covering GHG emissions.

The firewater pump engine will be operated only during emergency events and required maintenance and
readiness checks. Therefore, when evaluating BACT requirements, the limited operating time of the unit
should be taken into consideration. The proposed firewater pump unit is powered by a diesel engine.
Emissions from diesel fuel combustion will be limited in the following ways:
 Using only ultra-low sulfur diesel fuel

 Selecting a unit from engine family that is EPA certified to applicable model year standards
specified in NSPS regulations and adhering to manufacturer’s maintenance recommendations.
 Limit the hours of operation during non-emergency events to maintenance and readiness checks
and install a non-resettable hour meter to verify compliance.
To further analyze potential BACT, data in the RBLC database for Process Type 17.2111 and recently
issued permits were reviewed. TCEQ Tier 1 BACT for emergency use diesel engines for NOx, CO, VOC,
and PM is specified below:
TCEQ Tier 1 BACT for NOx emissions from emergency use diesel engines include meeting the
requirements of 40 CFR Part 60 Subpart IIII, firing ultra-low sulfur diesel, having a non-resettable hour
meter and limit the hours of operation to 100 hours per year for non-emergency operation. Additionally,
no visible emissions shall leave the property and visible emissions should not be present exceeding 30
seconds in duration in any six-minute period. For each of these pollutants the unit will meet TCEQ’s
Tier 1 BACT. The following subsections expand the BACT Analysis discussion to include the
information in the EPA’s RBLC database and recently issued permits. EPE is not proposing to permit
MSS emissions separately from normal emissions for the firewater pump and has thus not included
discussion of MSS BACT for this unit.
For NOx emissions, the most common control methodologies implemented for similar diesel-fired units in
EPA’s RBLC database and recently issued NSR permits are purchasing a certified engine and adhering to
vendor specified maintenance procedures, complying with NSPS IIII, firing ultra-low sulfur diesel fuel,
adhering to good combustion practices, and limiting hours of operation (for emergency generators and
firewater pumps). The lowest emission rates of NOx for the units in the RBLC database on a grams per
horsepower-hour (g/hp-hr) basis is 2.6. The unit to be installed for the Project has an emission rate that is
slightly below this emission rate. Since the emission reduction strategies proposed are capable of meeting
11
Small Internal Combustion Engines < 500 hp firing fuel Oil (including diesel).
29
a low NOx emission rate and use similar control techniques to other units shown in the RBLC database,
this is proposed as BACT for NOx emissions from the firewater pump.
The control method descriptions in the RBLC database and recently issued NSR permits for CO
emissions are the same as for NOx. The range of CO emission rates represented in the RBLC dataset for
units less than 500 horsepower is 0.447 g/hp-hr to 3.7 g/hp-hr. The CO emission rating for the Proposed
unit provided by the manufacturer is 0.6 g/hp-hr. Therefore, since the emission rate is on the low end of
rates represented in the RBLC database and the planned control techniques are in line with the other
sources listed therein, EPE proposes that the emission reduction strategies proposed for the firewater
pump be accepted as BACT for CO emissions from the firewater pump.
The control method descriptions in the RBLC database and recently issued NSR permits for VOC
emissions are the same as for NOx and CO. The vendor data provided shows only total hydrocarbon
emissions rather than a specific VOC emission factor. However, even using the conservative assumption
that total hydrocarbon emissions are equal to VOC emissions, the g/hp-hr emission rate is in the lower
portion of the range of VOC emission rates represented in the RBLC dataset for units less than 500
horsepower. Therefore, EPE proposes that the emission reduction strategies proposed for the firewater
pump be accepted as BACT for VOC emissions from the firewater pump.
For diesel fired internal combustion engines rated at 500 hp or less, control methods selected as BACT in
the RBLC database for particulate emissions are the use of ultra-low sulfur diesel fuel, good combustion
practices, and emission certification. The PM emission rating for the Proposed unit provided by the
manufacturer is 0.16 g/hp-hr, which is on the low end of rates represented in the RBLC database The
Proposed unit is in the range of emission rates accepted as BACT and as such, proposed emission control
strategies should be considered BACT for PM/PM2.5 emissions from the firewater pump.
TCEQ has not specified a Tier 1 BACT for GHG emissions. Review of the RBLC database and recently
issued NSR permits showed that for small, diesel-fired emergency use units, typical control methods for
GHG emissions include purchasing an efficient unit, good combustion practices and proper operation and
maintenance. Additionally, annual operating limitations are typically implemented as well to eliminate
unnecessary emissions except during times of maintenance and testing.
The proposed unit is a 99-horsepower diesel-fired engine which drives an emergency-use firewater pump.
The unit will be limited to no more than 100 hours of operation per year during non-emergency
maintenance and testing activities. Compliance with the operating limitations will be achieved by tracking
unit runtime. Additionally, manufacturer’s recommended maintenance will be completed to ensure the
unit operates efficiently.
BACT for GHG has been completed.

30
 Limit operating hours
The proposed unit will be a newer model unit and will be maintained and operated in accordance with
manufacturer’s recommendations. Purchasing a modern, more fuel-efficient engine reduces GHG
emissions due to increased fuel efficiency.
O&M Procedures ensure that performance of the unit does not degrade as rapidly over time. Similarly,
operating a unit in accordance with good combustion practices to ensure that fuel is being efficiently
combusted is important to realize maximum potential energy efficiency.
Carbon capture and storage: See discussion in Section 5.1.1.6. for the simple-cycle turbine.
An alternative, more carbon-neutral option for fuel would be the use of biodiesel.
Limiting operating hours to minimum required to ensure unit readiness is the most effective way to
reduce GHG emissions.
Oxidation catalyst controls are somewhat effective at controlling methane emissions. However, newer
diesel-fired units typically have low total hydrocarbon emissions due to more efficient combustion.
Additionally, flow through hydrocarbon emissions from diesel units are not a large source of methane
given that the diesel fuel is made up mostly of heavier hydrocarbons.
Carbon capture and storage is an emerging technology. However, there has yet to be a focus on
implementing this type of technology to small, diesel fired units and as discussed in Section 5.1.1.6, this
has been determined to be technically infeasible for the turbine unit and is also infeasible for the firewater
pump engine for the same reasons.
Ensuring efficient design and operation is the best method to reduce GHG emissions. Purchasing and
properly maintaining a unit and ensuring efficient combustion improves the unit efficiency and reduces
unnecessary fuel combustion. Reducing emissions by limiting hours of operation only as necessary for
maintenance and readiness testing is also an effective way to limit emissions.
global warming potential. However, the unit has inherently low methane emissions and is already
certified to the model year standards required by NSPS IIII in lieu of post-combustion control technology.
3. Alternative Fuels
Biodiesel is a renewable and less carbon intensive fuel than conventional diesel. However, cellulosic
biofuel conversion technologies are still being developed and the fuel quality is at times varies depending
31
on the supplier. Biodiesel can diminish engine performance, clog filters and injectors and reduce
reliability if the fuel quality is not up to par. Additionally, though biodiesel is generally considered
cleaner burning than regular diesel, increased NOx emissions have been observed.
Step 4: Evaluate most effective controls
unit with efficient design, properly maintain the unit, and ensure good combustion efficiency of the fuel to
limit higher global warming potential gas emissions.
Step 5: Select BACT
purchasing an efficient unit and ensuring proper maintenance and good fuel combustion practices. EPE
will also limit hours of operation to no more than 100 hours per year during non-emergency events. This
proposed BACT is consistent with results found in the RBLC database and recently issued NSR permits
covering GHG emissions from emergency engines.
5.1.3 Line Heater

The in-line fuel gas heater (FIN: LH-1) will comply with BACT standards for the pollutants subject to
PSD BACT review using the following emission reduction options:
 Low-NOx burner
 Firing pipeline quality natural gas
 Ensuring good combustion practices during unit operation
With respect to review of the RBLC database, this analysis is limited to heaters and boilers less than 100
MMBtu/hr. For certain pollutants where adequate data for more similar sources were available from the
Process Type 13.310 RBLC database search12, larger units and dissimilar process units were removed
from consideration so that the line heater could be compared with similar process units which better
facilitates like-kind comparisons. Similarly, the scope of review of recently issued NSR Permits was
limited to similar sized and similar types of units. EPE is not proposing to permit MSS emissions
separately from normal emissions for the line heater and has thus not included discussion of MSS BACT
for this unit.
TCEQ Tier 1 BACT for NOx emissions from heaters rated less than 40 MMBtu/hr include the use of
burners with the best NOx performance given the burner configuration and gaseous fuel used. The heater
has a nominal rating of 3.9 MMBtu/hr and is pipeline-quality natural gas-fired.
When filtering the RBLC database list to include natural gas-fired process heaters, the RBLC lists a range
of 0.01 lb/MMBtu – 0.14 lb/MMBtu NOx emission rates for all heaters rated less than 100 MMBtu/hr.
The control methods listed in the RBLC database for heaters include low-NOx and ultra-low-NOx burners,
flue-gas recirculation, and good combustion practices.
However, within the 10 MMBtu/hr rating or less range for heaters, the minimum emission rate accepted
as BACT is 0.025 lb/MMBtu, roughly equivalent to the rating of the proposed unit. For heaters less than
10 MMBtu/hr, BACT ranges from 0.025 – 0.1 lb/MMBtu. Additionally, for process heaters rated less
12
This process type, Natural Gas-fired Commercial or Industrial Sized Boilers and Furnaces less than or Equal to 100
MMBtu/hr, is the most relevant process type included in the RBLC database for this analysis.
32
than 10 MMBtu/hr, the most stringent control technology (besides good combustion practices and firing
only natural gas) included use of a low-NOx burner. There are several reasons why lower-rated process
heaters are not regularly implementing more stringent controls. For a unit with a low firing rate, flue-gas
recirculation becomes less practical. Given that the volume of flue gas is relatively low compared with a
larger combustion unit, this method of emission reduction is more effective (from both an emission
control and cost perspective) for units burning larger quantities of fuel and having higher exhaust flow
rates. Ultra-low NOx burners are not represented as a control technology for units less than 10 MMBtu/hr
for similar reasons, and even for larger units low-NOx burners combined with good design and fuel
combustion practices are routinely accepted as BACT. Furthermore, after reviewing emission rates on a
pound per hour basis, the proposed line-heater has an emission rate for NOx that is lower than all similar
units rated 100 MMBtu/hr or less within the RBLC database.
Based on the burner rating and configuration of the unit, EPE’s proposes using a low-NOx burner,
combusting only pipeline quality natural gas and ensuring good combustion practices be recognized as
BACT for NOx emissions from the line heater.
TCEQ Tier 1 BACT for CO emissions from heaters rated less than 40 MMBtu/hr is 50 ppmvd corrected
to 3% O2.
Review of the RBLC database for process heaters rated less than 100 MMBtu/hr, lists CO emission rates
between 50 and 100 ppmvd at 3% O2 for all units less than 100 MMBtu/hr. Units rated 10 MMBtu/hr or
less in the RBLC database achieved a CO outlet concentration of 100 ppmvd at 3% O2. Though the most
stringent form of control technology would include an oxidation catalyst, the emission reduction would be
minor since overall emissions of CO from the unit are less than 0.5 tons per year. Therefore, equipping
the unit with an oxidation catalyst is not economically reasonable as is evidenced by a multitude of
recently issued TCEQ and other state-issued NSR permits for small process heaters and reboilers rated
less than 10 MMBtu/hr. The review of both the RBLC database and other recently issued permits
confirms that for small process heaters, good combustion practices are routinely accepted as BACT for
CO emissions.
Based on the line heater’s equipment specifications provided by the manufacturer, the unit will meet the
TCEQ’s Tier I BACT standard and also has an hourly emission rate is 0.145 pounds per hour, which is on
the low end of the hourly emission rates represented in the RBLC database. EPE will ensure that the line
heater will limit CO emissions by operating the unit in accordance with good combustion practices to
ensure complete combustion. Therefore, based on the unit specifications and consideration of RBLC data
and recently issued NSR Permits, best management practices and firing pipeline quality natural gas is
proposed as BACT for CO emissions from the line heater.
TCEQ Tier 1 BACT for VOC emissions from heaters rated less than 40 MMBtu/hr is considered to be
met if the combustion unit fires solely pipeline quality natural gas and is operated in a consistent manner
with good combustion practices. The line heater will fire only pipeline-quality natural gas and will be
operated in conformance with good combustion practices to ensure complete combustion of VOC.
Review of the RBLC database and previous TCEQ and other recent State-issued NSR permits show that
acceptance of good combustion practices and/or firing only pipeline quality natural gas have consistently
been accepted as BACT for most heaters and boilers. Oxidation catalysts are listed in the RBLC database,
but these are typically installed on larger boiler units and this control technology is not demonstrated in
RBLC data or recently issued NSR permits to be required as BACT for small process heating equipment.
33
Additionally, flue gas recirculation is available as a control mechanism for VOC emissions from boilers,
but this technique would not be feasible for the proposed unit. The VOC emission rates in the RBLC
database range between 0.003 lb/MMBtu to 0.054 lb/MMBtu. The proposed heater will achieve an
emission rate of 0.008 lb VOC/MMBtu on a heat input basis and total annual and hourly emissions are
fairly small due to the units 3.9 MMBtu/hr rating. Thus, EPE proposes that TCEQ Tier 1 BACT
requirements be considered BACT for VOC emissions from this equipment.
TCEQ Tier 1 BACT for PM emission reductions from heaters less than 40 MMBtu/hr is to limit opacity
to 5%. The proposed will be fired by pipeline quality natural gas and the exhaust stream is not expected to
exceed 5% opacity.
Review of the RBLC database for similar units shows that good combustion practices, limiting the fuel to
natural gas with a low sulfur content such as pipeline quality natural gas are routinely accepted as BACT
for external combustion units rated 10 MMBtu/hr or less. Additionally, the proposed emission rate from
the line heater is 0.005 lb/MMBtu, which is lower than other external combustion units rated less than 10
MMBtu/hr in the RBLC database. Therefore, EPE proposes good combustion practices and firing pipeline
quality natural gas be accepted as BACT for PM/PM2.5 emissions from the line heater.
TCEQ has not specified a Tier 1 BACT for GHG emissions. Review of the RBLC database showed that
there is minimal data available for similar sized (< 10 MMBtu) external combustion units. However,
RBLC data shows that emission rates permitted for natural gas-fired heaters were between 117 lb/MMBtu
and 119 lb/MMBtu for CO2 and were 0.0022 lb/MMBtu for CH4 and 0.0002 lb/MMBtu for N2O. These
rates correspond to the default emission rates for natural gas combustion in 40 CFR Part 98, Subpart C
Tables C-1 and C-2. The line heater Project emission rates were calculated on this basis as well. The
BACT accepted in the RBLC for heaters is typically good operating practices and using natural gas as
fuel. This has also been accepted as BACT for small process heaters in numerous TCEQ and other state-
issued NSR permits.
The proposed unit is a forced draft line heater which will ensure that incoming fuel to the simple-cycle
turbine unit will be at optimal conditions for efficient combustion. The line heater burns natural gas to
heat a coil which imparts heat to a bath of water/glycol solution which in turn imparts heat to incoming
fuel gas to the turbine. The unit has six passes13 and has an 80% heat transfer efficiency. The unit is
considered a fire-tube style boiler.
BACT for GHG has been completed. Emerging technologies to limit emission rates of greenhouse gases
are discussed in EPA’s white paper “Available and Emerging Technologies for Reducing Greenhouse
Gas Emissions from Industrial, Commercial, and Institutional Boilers” and other methods and
technologies have also been demonstrated in practice. However, not all control measures listed within the
document are applicable to the type of unit being installed and some of the strategies to reduce emissions
are more applicable for operators considering retrofitting older units that were not designed as energy
efficiently as newer units.
13
Hot combustion gases travel across the boiler heat-exchange surfaces several times. Each time this occurs is called a pass.
More modern designs of fire-tube boilers typically have larger number of passes than older boilers to increase heat transfer
efficiency.
34
Efficient design of equipment is an effective mechanism to ensure reduction in GHG emissions. An

efficiently designed unit would have a high rate of heat transfer efficiency. Other than designing a unit to
combust natural gas which is the least carbon intensive fossil fuel, some design considerations are
discussed below:
 Higher numbers of passes increase the opportunity for firetubes to impart heat to the water bath
medium and thereby increases heat transfer efficiency.
 For a water bath-style heater, ensuring proper insulation to reduce heat loss from the water bath
through the shell is an important consideration
O&M procedures such as tuning and maintenance can increase the performance of a unit and reduce
degradation of the unit efficiency over time. O&M Procedures ensure that ductwork leaks or air
infiltration caused by negative pressure differences between hot combustion gases and ambient air does
not reduce combustion efficiency of a boiler and cause heat transfer efficiency loss due to imparting heat
to the infiltrating air instead of the water bath media as intended. Signs of air infiltration may include high
oxygen levels measured in exhaust gas. Additionally, boiler gas-side heat transfer surfaces are exposed to
high gas temperatures and products of combustion and which may eventually lead to the formation of soot
and deposits of uncombusted carbon. This leads to reduction in surface area for efficient heat transfer. For
pipeline-quality gas fired boilers, this is unlikely to be a major problem in the absence of boiler
malfunction, so O&M procedures are likely to be sufficient to mitigate this issue.
Good combustion practices include burner tuning and ensuring adequate air fuel ratio to achieve efficient
combustion. Efficient combustion reduces flow-through methane emissions and the formation of
intermediary products like N2O.
Installing an oxidation catalyst can reduce total hydrocarbon emissions from a unit through catalytic
oxidation and would reduce uncombusted hydrocarbon emissions, including, to a certain degree, methane
emissions.
Using an alternative fuel such as biomass fuel is considered an alternative to natural gas that may help
reduce overall greenhouse gas emissions since it is a renewable fuel source and have a lower caloric value
than traditional fossil fuels.
Carbon capture and storage is the process by which flue gas is processed to capture CO2 emissions which
is then pressurized and sent into long-term geologic storage through via pipeline.
Carbon capture and storage and GHG reducing alternative fuels are considered technically infeasible. See
Section 5.1.1.6. for the simple cycle turbine.
35
Ensuring efficient design and operation through purchasing and properly maintaining a unit to ensure
maximum heat transfer and minimizing heat loss from the transfer medium also reduces unnecessary fuel
combustion. Additionally, natural gas has a relatively low carbon intensity in relation to other fossil fuels
like coal and oil.
global warming potential. However, efficient fuel combustion is a better mechanism to achieve this goal,
especially considering that CH4 emissions are a small contributor (<0.01%) of the total CO2e emissions.
unit with efficient design (e.g. good heat transfer efficiency), properly maintain the unit, and ensure good
combustion efficiency of the fuel to limit higher global warming potential gas emissions. The efficiency
of the proposed unit is 80% and with proper maintenance and good combustion procedures, potential
degradation in the unit’s heat transfer efficiency can be minimized.
Given the relatively small amount of methane emissions (less than 0.05 tons per year), oxidation catalyst
is not considered economically reasonable due to the cost to install the unit and the engineering
challenges to ensure flue-gas temperature is within optimal range (which might have the consequence of
reducing the heat transfer efficiency of the unit).
Step 5: Select BACT
purchasing and properly maintaining a unit that is inherently efficient at achieving the intended purpose.
This proposed BACT is consistent with results found in the RBLC database and recently issued NSR
permits covering GHG emissions from similar-sized heaters.
5.1.4 Fugitive Emissions

The sources of fugitive emissions from the Project include natural gas component leaks of both VOC and
GHG compounds, ammonia injection component leaks, and SF6 leaks from circuit breakers. Since NH3
does not require PSD review, BACT for this source is addressed in the TCEQ Form PI-1 General
Application workbook and is not discussed herein. Since BACT for the natural gas component leaks
differ from the circuit breaker system SF6 leaks, these two sources are discussed below in separate
subsections.
5.1.4.1 Natural gas piping leaks
Both VOC and GHG emissions are subject to PSD review for this project and the natural gas piping leaks
have the potential to emit both of these pollutants. However, BACT control methodologies for both VOC
and GHG are the same. As such, EPE proposes using the TCEQ’s three-tier approach to evaluate BACT
for this source. Though technically BACT control for GHG emissions are not addressed directly by
TCEQ, BACT for VOC with respect to fugitive components are addressed and reduction in GHG
emissions, primarily methane, is a co-benefit of implementing BACT to control VOC.
TCEQ’s Tier 1 BACT requirements for fugitive piping and equipment leaks of VOC (and by extension,
GHG) is as follows:
36
1. Uncontrolled VOC emissions less than 10 tons per year require no control
2. Uncontrolled VOC emissions greater than 10 tons per year and less than 25 tons per year require
implementation of a 28M Leak Detection and Repair (LDAR) Program.
3. Uncontrolled VOC emissions greater than 25 tons per year require implementation of a 28VHP LDAR
Program.
Project natural gas fugitive emissions are expected to be well below 1 ton per year of VOC. Therefore,
implementation of Tier 1 BACT would not require implementation of an LDAR program. However, the
RBLC database search for SIC code 4911 (Electric Services) shows that in order to control GHG
emissions from natural gas fugitive emission sources, operators regularly implement Audio, Visual, and
Olfactory (AVO) programs. In the RBLC database, implementation of weekly AVO inspection are
regularly adopted as BACT for CO2e emission reductions. Therefore, since this emission reduction option
is the best available control for GHG emissions, it follows that this is also an effective control for VOC
emissions from natural gas pipeline leaks. Further, an AVO approach is also recommended as BACT by
the TCEQ for lower emitting natural gas leak sources in other industries.14 Thus, EPE proposes that
weekly AVO inspections be accepted as BACT to reduce VOC and GHG emissions from natural gas
component leaks. Leaks detected through AVO inspection will be documented and repaired as soon as
practicable.
5.1.4.2 Circuit Breaker SF6 leaks
TCEQ has not specified a Tier 1 BACT for GHG emissions from circuit breaker leaks. Thus, EPA’s top-
down approach was used to address BACT for circuit breaker SF6 leaks along with a review of the RBLC
dataset for SIC Code 4911 and a review of recently issued TCEQ and other state NSR permits. RBLC
database BACT involves enclosed insulation systems equipped with low pressure alarm to alert operators
of any leaks or the purchase of units with certified leak rates of less than 0.5% per year. Various NSR
permit applications include enclosed systems with leak detection alarms, and O&M or LDAR programs.
 Enclosed System with leak detection

 Alternative insulating substances
 Implementing an LDAR Program
The most likely causes of SF6 emissions from circuit breakers and gas-insulated switchboards in use at a
power generation facility result from gasket deterioration due to aging effects. These aging effects include
hardening of gaskets which can reduce effectiveness of the seal, chemical attack on gaskets from partially
decomposed SF6 compounds which are formed during to arcing due to current interruptions, and
corrosion of equipment seals from the external environment. In recent years manufacturers of circuit
breakers and gas-insulated switchboards have vastly improved leak rates stemming from these issues by
improving the design of the units. This has the effect of reducing the necessary maintenance activities
such as changing seals and gaskets. These activities often lead to escape of SF6 despite efforts to recycle
the gas, and if these maintenance procedures can be avoided it reduces this risk. Additionally, modern
circuit breakers and gas-insulated switchboard equipment are generally equipped with a pressure alarm to
alert operators of potential leaks.
14
See for example Table 9 of the TCEQ Non-rule Standard Permit Oil and Gas Handling and Production Facilities (Effective
November 8, 2012).
37
Historically, dielectric oil or compressed air circuit breakers have been used, however, these are vastly
inferior to SF6 insulated units and are undesirable from a fire-safety standpoint. There has not yet been
technically feasible alternative to SF6 that has been fully vetted and performs comparably.15
Implementing an LDAR program to check for SF6 leaks is an approach that may limit SF6 leaks if
properly implemented and staff are properly trained to repair leaks (or an experienced third-party
contractor is available to perform this service).
Of the above-mentioned control strategies, it is technically infeasible to use an alternative to SF6 which
would perform comparably. Additional research and development will still be necessary to make a
heretofore untested insulating gas or gas mixture viable. Though it is technically feasible to use dielectric
oil or compressed air it is not desirable based on the drawbacks, the safety concern, and the performance
of the equipment being compromised.
1. Enclosed system with leak detection
In the case of leak reduction, engineering controls and superior design are much superior to relying on
process management controls such as leak detection and repair due to the high level of expertise required
to successfully perform maintenance while minimizing leaks. Purchasing a modern unit is the most
effective way to minimize GHG emissions from circuit breakers and switchboards.
2. LDAR Program
Though an LDAR program can be effective in detecting and repairing leaks, this would be a less effective
measure than installation of equipment that is gas tight and has a pressure sensor and alarm capabilities.
This is because the pressure sensor and alarm operates continuously to detect leaks whereas a leak check
via an LDAR program would only occur periodically.
Over time, design improvements have drastically reduced SF6 leaks from circuit breakers and gas-
insulated switchboards. Additionally, a pressure sensor and alarm system should effectively alert staff to
potential leaks such that the issue is addressed. Purchasing a newer, well-functioning unit with monitoring
capabilities to assess unit operation and maintenance needs is much preferred to implementing a periodic
maintenance program because it is desirable to avoid unnecessary SF6 handling. Even with the best
training and administrative controls, there is an increased chance of emissions occurring from these
sources during maintenance activities.
Step 5: Select BACT
EPE proposes that purchasing new SF6-insulated technology equipped with pressure monitoring systems
and alarms be considered BACT for this source. This proposed BACT is consistent with results found in
the RBLC database and recently issued NSR permits covering GHG emissions from circuit breakers.
15
Conclusions of NIST Technical Note 1425 – Gases for Electrical Insulation and Arc Interruption: Possible Present and Future
alternatives to Pure SF6. Available online at: https://nvlpubs.nist.gov/nistpubs/Legacy/TN/nbstechnicalnote1425.pdf
38
5.2 NNSR LAER Analysis
Major Projects located in a nonattainment area for a pollutant require NNSR Review for that pollutant if
emission rates are greater than the SER specified in 40 CFR Part 51. LAER requires that emission
limitations for the nonattainment pollutant are the most stringent emission limitation (contained in TCEQs
SIP) for a class or source category unless this limitation is demonstrated to be not achievable or the most
stringent emission limitation that is achieved in practice by a class or source category. Regardless, the
LAER emission rates may not be in excess of allowable rates under applicable NSPS or NESHAP
standards.
For EPE’s proposed Project, NNSR review is required for PM10. Emissions of PM10 result from natural
gas fuel combustion in the line heater and simple-cycle turbine and diesel fuel combustion in the firewater
pump engine. For these units, a LAER Analysis for PM10 emissions is provided below.

Emission control techniques for PM and PM2.5 for the simple-cycle turbine were discussed in section
5.1.1 with respect to BACT. As discussed, the most important factor determining particulate matter
emission rates from combustion units are impurities in the fuel such as ash and sulfur. Therefore, firing
pipeline-quality natural gas inherently generates less PM10 emissions than would be generated by other
fuels. Complete combustion to reduce particulate emissions from partially combusted carbon compounds
also helps to reduce particulate matter emissions.
RBLC database and recently issued NSR permits show that exclusive use of pipeline quality natural gas
along with good combustion practices represents the most stringent control option for simple cycle
turbine units with respect to PM10 emissions. The Proposed Mitsubishi Model M501 GAC unit’s worst-
case emission rate for PM10 is 0.00275 lb/MMBtu, which is lower than all but three of the emission rates
found in the RBLC dataset. This reflects the combination of the efficient, modern design of the unit and
the use of pipeline quality natural gas fuel to achieve the lowest emission rate possible. EPE proposes to
use solely pipeline-quality natural gas to fuel the proposed unit, operate the unit to ensure good
combustion of fuel, and complete the required quarterly visible emission observations to ensure the unit is
functioning properly and complying with opacity standards. These emission limitation strategies for PM10
result in the lowest achievable emission rates for the unit and should be considered to meet the
requirements for achieving the LAER.
As previously discussed in Section 5.1.1.5 with respect to turbine MSS BACT, PM10 emissions from the
unit would be on par or better performing than other simple cycle units in the RBLC database in terms of
MSS PM10 emission rates. Thus, EPE proposes to meet LAER requirements by minimizing the duration
of events and operating the turbine in accordance with best management and good air pollution control
practices.

For diesel fired internal combustion engines rated at 500 hp or less, control methods selected as BACT or
LAER in the RBLC database for particulate emissions are the use of ultra-low sulfur diesel fuel, good
combustion practices, and emission certification. The proposed firewater pump engine rating is below 100
hp. In order to establish a like-kind comparison of achievable emission rates for this type of unit, RBLC
data was evaluated for other units that are 150 hp or below and fueled by ultra-low sulfur diesel fuel.
Based on this analysis, the proposed unit outperforms other similarly rated units in the RBLC database.
Because the unit is inherently designed to reduce particulate emissions, is certified to comply with NSPS
39
standards based on its model year rating by the EPA, and will burn solely ultra-low sulfur diesel, EPE
proposes that this unit achieves the LAER for PM10 emissions.
5.2.3 Line Heater

Review of the RBLC database for similar units shows that good combustion practices, limiting the fuel to
natural gas with a low sulfur content such as pipeline quality natural gas are the best way to achieve low
rates of particulate matter emissions for external combustion units rated 10 MMBtu/hr or less.
Additionally, the proposed emission rate from the line heater is 0.005 lb/MMBtu, which is lower than
other external combustion units rated less than 10 MMBtu/hr in the RBLC database. Therefore, EPE
proposes that good combustion practices and firing pipeline quality natural gas be recognized as the
mechanism to achieve the LAER for PM10 emissions.
40
6 AIR QUALITY IMPACTS ANALYSIS
An air quality analysis is being conducted for pollutants subject to both major source and minor source
review. For the purpose of conducting the NAAQS Preliminary Impact Determinations, only one “worst-
case” scenario was modeled for each pollutant and averaging time with scaling factors applied only as
appropriate based on the Standard. A modeling protocol is being submitted under separate cover. Once
the methodologies therein are approved, the modeling report will be submitted under separate cover.
Table 13 lists the evaluations conducted for the Air Quality Impacts Analysis for pollutants subject to
Minor NSR and PSD review:
Table 13. NSR Air Quality Analysis
Pollutant Evaluated PSD/Minor NSR Evaluation Type of Analysis
Minor NAAQS Preliminary Impact Determination,

SO2 Minor
State Property Line Analysis
H2SO4 Minor State Property Line Analysis
NH3 Minor Health Effects Analysis
NOx PSD PSD NAAQS Preliminary Impact Determination
CO PSD PSD NAAQS Preliminary Impact Determination
PM2.5 PSD PSD NAAQS Preliminary Impact Determination
Secondary Formation of PM2.5 PSD Tier 1 (MERP) demonstration
O3 PSD Tier 1 (MERP) demonstration
N/A PSD Additional Impacts Evaluation

*Note that a Class I Area Analysis was not conducted since the site is not located within 100 kilometers of a Class I Area.
In addition, since the Project is a major modification of an existing source, an analysis of the project’s
impacts to growth (with respect to residential, industrial, commercial, and/or other growth) in the area,
visibility, and soils and vegetation will be included in the modeling report.
41
7 NONATTAINMENT NEW SOURCE REVIEW
The Project is located in a moderate Nonattainment area for PM10 and is required to comply with the
requirements of Nonattainment New Source Review, pursuant to 30 TAC §116.151(c). For NNSR the
Project emissions of PM10 will meet the LAER (Discussed in section 5.2). Additionally, TCEQ requires
that the operator must purchase offsets, that all major stationary sources owned or operated by the
applicant in the state be in compliance or on a schedule for compliance with all applicable state and
federal emission limits and standards, and that an Alternative Site Analysis be conducted. These
requirements are discussed in the following subsections.
7.1.1 Offsets
EPE will purchase offsets at a rate of 1 ton of PM10 for every ton of the proposed Project increases of
PM10. which will ensure that there is no net increase in PM10 emissions in the region. Offsets will be
enforceable by permit condition language.
7.1.2 Alternative Site Analysis

Co-location of the Project at the existing Newman Generating Station has several advantages over
constructing a new site including proximity to natural gas mainlines, existing water supply, and existing
power transmission infrastructure. This proximity to existing infrastructure will minimize construction
disturbance. EPE’s two other power stations in the vicinity (Copper Station and Montana Power Station)
are also located in the El Paso Nonattainment Area.
Additional power generation after the project is completed will be a social benefit and allow EPE to better
serve the electricity needs of the regional area. Thus, the proposed location of the Project significantly
outweighs the environmental and social costs of that location.
7.1.3 Compliance History Review

With the exception of deviations reported in the Title V Permit Compliance Certification Submittals, EPE
maintains compliance with applicable air quality rules, regulations, and permit requirements. EPE has a
company Compliance Classification of “satisfactory” with a Rating of 0.53. Newman Generating Station
has a Compliance History Classification of “High” and a rating of 0. Other stations owned and operated
by EPE in Texas include Montana Power Station and Copper Station which have Compliance History
Ratings of 1.22 (Satisfactory) and 0 (High), respectively16.
16
Compliance History Ratings and Classifications are available online at: https://www2.tceq.texas.gov/oce/ch/index.cfm#gotcn.
Accessed September 18, 2019.
42
Appendix A. Emission Calculations
El Paso Electric
Newman Station
Emission Calculations
Table 1 - Vendor Data

EPN: SC-7A
Commercial Data
El Paso Electric
El Paso, TX
Mitsubishi Hitachi Power Systems Americas Inc.
Input Information
Gas Turbine Type M501GAC
Configuration and Arrangement GT Only 1x0 with Hot SCR
Scope GT Only
Fuel Type Natural Gas
Fuel Heating Value (HHV - Btu/lb) 22732
Fuel Heating Value (LHV - Btu/lb) 20501
Case# Unit 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22
Ambient Dry Bulb Temperature °F °F 105 105 105 105 105 70 70 70 70 70 35 35 35 35 26 26 26 26 -10 -10 -10 -10
Barometric Pressure psia 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693
Relative Humidity % 13 13 13 13 13 50 50 50 50 50 67 67 67 67 23.2 23.2 23.2 23.2 60 60 60 60
Inlet conditioning Evap Cooler ON OFF OFF OFF OFF ON OFF OFF OFF OFF OFF OFF OFF OFF OFF OFF OFF OFF OFF OFF OFF OFF
Gas Turbine Performance
GT Load % Base Base 80% 60% 55% Base Base 80% 60% 50% Base 80% 60% 50% Base 80% 60% 50% Base 80% 60% 50%
GT Heat Input MMBTU/h - HHV 2,298 2,060 1,736 1,440 1,366 2,373 2,303 1,887 1,552 1,392 2,507 2,033 1,654 1,487 2,535 2,064 1,675 1,509 2,519 2,261 1,793 1,609
Gross GT Power Output kW 232,800 204,200 165,400 124,100 113,700 241,800 233,900 187,100 140,300 116,900 258,400 207,500 155,600 129,700 262,600 212,200 159,200 132,600 257,600 230,900 173,200 144,300
Gross GT Power Output Megawatt 232.8 204.2 165.4 124.1 113.7 241.8 233.9 187.1 140.3 116.9 258.4 207.5 155.6 129.7 262.6 212.2 159.2 132.6 257.6 230.9 173.2 144.3
Gross GT Heat Rate Btu/kWh - HHV 9,870 10,087 10,490 11,600 12,007 9,812 9,845 10,083 11,057 11,907 9,701 9,794 10,626 11,464 9,653 9,725 10,518 11,377 9,779 9,791 10,352 11,151
MHPS GT Auxiliary Loads Kw 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000
Net GT Power Output Kw 228,800 200,200 161,400 120,100 109,700 237,800 229,900 183,100 136,300 112,900 254,400 203,500 151,600 125,700 258,600 208,200 155,200 128,600 253,600 226,900 169,200 140,300
Net GT Heat Rate Btu/kWh-HHV 10,043 10,288 10,750 11,987 12,444 9,977 10,016 10,303 11,382 12,329 9,853 9,986 10,906 11,829 9,802 9,912 10,789 11,731 9,933 9,964 10,597 11,469
Stack Emissions
Nox (abated) ppmvd 15%O2 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5
Nox (abated) lb/Mmbtu - HHV 0.00998 0.00997 0.00996 0.00995 0.00995 0.00997 0.00997 0.00997 0.00996 0.00997 0.00997 0.00997 0.00995 0.00997 0.00998 0.00997 0.00995 0.00997 0.00998 0.00997 0.00996 0.00996
CO (abated) ppmvd 15%O2 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3
CO (abated) lb/Mmbtu - HHV 0.00729 0.00728 0.00728 0.00727 0.00727 0.00728 0.00728 0.00728 0.00728 0.00728 0.00728 0.00729 0.00727 0.00728 0.00729 0.00728 0.00727 0.00728 0.00729 0.00728 0.00727 0.00728
VOC (abated) ppmvd 15%O2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2
VOC (abated) lb/Mmbtu - HHV 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278
Particulates PM10 Total lb/h 6.4 6 5.1 4.2 4 6.6 6.5 5.4 4.4 4 7 5.8 4.7 4.2 7.1 5.9 4.7 4.3 7 6.5 5 4.5
Particulates PM10 Total lb/Mmbtu - HHV 0.00279 0.00289 0.00294 0.00291 0.00295 0.00279 0.00281 0.00287 0.00283 0.00288 0.00279 0.00285 0.00281 0.00283 0.00279 0.00285 0.00281 0.00282 0.00275 0.00284 0.00279 0.00279
Ammonia Slip ppmvd 15%O2 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5
Ammonia Slip lb/Mmbtu - HHV 0.00739 0.00738 0.00737 0.00737 0.00737 0.00738 0.00738 0.00738 0.00737 0.00738 0.00738 0.00738 0.00737 0.00738 0.00739 0.00738 0.00737 0.00738 0.00739 0.00738 0.00737 0.00737
CO2 lb/h 274,300 245,900 207,100 171,900 163,000 283,200 274,900 225,200 185,200 166,200 299,300 242,600 197,400 177,500 302,600 246,400 199,900 180,100 300,700 269,900 214,100 192,100
CO2 lb/Mwhgross 1,178 1,204 1,252 1,385 1,433 1,171 1,175 1,204 1,320 1,422 1,158 1,169 1,269 1,369 1,152 1,161 1,256 1,358 1,167 1,169 1,236 1,331
El Paso Electric
Newman Station
Table 2 - Combustion Turbine (Simple Cycle) Emissions

EPN: SC-7
(Maximum Base Load Condition)

1
Parameter Value Units Case
Power Output 2,576 MW 19
Fuel Flow 111.3 klb/hr 19
GT Heat Input 2,519 MMBtu/hr 19
Exhaust Flow 6,462 klb/hr 19
o
Exhaust Temperature 825.0 F 19
Startups/Shutdowns 365.0 events/yr -
Annual Hours of Operation

8,760 hr/yr -
Base load Emissions Summary - MSS Emissions Summary - Total Annual

Single Turbine Single Turbine Emission Rate
Pollutant
1 Shutdown
Emission Factor Annual Emissions Startup emissions 2 SU/SD Emissions
emissions
ppmvd at 15% O 2 lb/MMBtu lb/hr tpy lb/event lb/event tpy tpy
NOx 2.5 0.00998 25.2 110.38 48.00 31.00 14.42 120.58
CO 3.0 0.00729 18.4 80.59 548.00 326.00 159.51 237.02
VOC 2.0 0.00278 7.0 30.66 310.00 153.00 84.50 113.99
PM/PM10/PM2.5 - 0.00275 7.0 30.66 4.08 2.33 1.17 30.66
SO2 0.20 - 1.54 6.75 0.90 0.51 0.26 6.75
3
NH3 5.0 0.00739 18.7 81.91 10.91 6.23 3.13 81.91
H2SO4 Mist 0.10 - 1.41 6.18 0.82 0.47 0.24 6.18
HAP Pollutant uncontrolled lb/MMBtu 4
ppmvd at 15% O 2 lb/hr tpy lb/event lb/event tpy tpy 5
5
Formaldehyde 7.1E-04 0.09 0.60 2.63 1.04 0.60 0.30 2.83
1,3-Butadiene 4.3E-07 - 1.1E-03 0.00 6.3E-04 3.6E-04 0.00 0.00
Acetaldehyde 4.0E-05 - 1.0E-01 0.44 5.9E-02 3.4E-02 0.02 0.44
Acrolein 6.4E-06 - 1.6E-02 0.07 9.4E-03 5.4E-03 0.00 0.07
Benzene 1.2E-05 - 3.0E-02 0.13 1.8E-02 1.0E-02 0.01 0.13
Ethylbenzene 3.2E-05 - 8.1E-02 0.35 4.7E-02 2.7E-02 0.01 0.35
Naphthalene 1.3E-06 - 3.3E-03 0.01 1.9E-03 1.1E-03 0.00 0.01
PAH 2.2E-06 - 5.5E-03 0.02 3.2E-03 1.8E-03 0.00 0.02
Propylene Oxide 2.9E-05 - 7.3E-02 0.32 4.3E-02 2.4E-02 0.01 0.32
Toluene 1.3E-04 - 3.3E-01 1.43 1.9E-01 1.1E-01 0.05 1.43
Xylenes 6.4E-05 - 1.6E-01 0.71 9.4E-02 5.4E-02 0.03 0.71
TOTAL HAP - - 1.40 6.13 1.51 0.86 0.43 6.33
El Paso Electric
Newman Station
Table 2 - Combustion Turbine (Simple Cycle) Emissions

EPN: SC-7
(Maximum Base Load Condition)

1
Parameter Value Units Case
Power Output 2,576 MW 19
Fuel Flow 111.3 klb/hr 19
GT Heat Input 2,519 MMBtu/hr 19
Exhaust Flow 6,462 klb/hr 19
o
Exhaust Temperature 825.0 F 19
Startups/Shutdowns 365.0 events/yr -
Annual Hours of Operation

8,760 hr/yr -
Base load Emissions Summary - MSS Emissions Summary - Total Annual

Single Turbine Single Turbine Emission Rate
Pollutant
1 Shutdown
Emission Factor Annual Emissions Startup emissions 2 SU/SD Emissions
emissions
GHG Pollutant ppmvd at 15% O 2 lb/hr tpy lb/event lb/event tpy tpy
CO2 - 300,700 1,317,066 75,600 51,700 23,232 1,317,066
CH4 5 17.6 77.09 1657.00 1365.00 552 625.66
6
N2O - 0.0002 0.56 2.43 1.06 0.68 0.32 2.66
TOTAL GHG (in
- 301,305 1,319,718 - - 37,115 1,333,499
CO 2 e) 7
1
NOx, CO, and VOC startup emission rates based on vendor provided emission rate at minimum ambient temperature during startup (ignition to base load). Startup emissions in lb/event for PM/PM10/PM2.5, SO2, NH3, H2SO4 Mist is based on
the hourly emission rate at worst case base load conditions adjusted based on timing to get from ignition to base load. The emissions from startup to base load at operating conditions -10°F and relative humidity 53% represent the highest hourly
emission rate from the source (Case 19).
2
NOx, CO, and VOC shutdown emission rates based on vendor provided emission rate at minimum ambient temperature during shutdown (base load to flame out).Shutdown emissions in lb/event for PM/PM10/PM2.5,
SO2, NH3, H2SO4 Mist is based on the hourly emission rate at worst case base load conditions on timing to get from (base load to flame out.
3
Ammonia injection will occur during times when the inlet temperature to the SCR is within operating range for ammonia injection, so it is a highly conservative assumption to account for ammonia slip emissions occur
during startup and shutdown times.
4
Uncontrolled HAP emission rates are based on AP-42 Table 3.1-3. Emission Factors for Hazardous Air Pollutants from Natural Gas-Fired Stationary Gas Turbines. These are conservatively used to estimate
emissions where a specific vendor-provided emission factor is not provided.
5 The turbine unit is authroized for 8760 hours per year. However, start up and shut down emissions are also authroized to occur. In order to avoid double counting emissions for the total annual emissions, the time in
start up and shut down mode is accounted for and subtracted from the normal hours of operation to get the maximum annual emissions. This is a conservatively high estimate of emissions since it assumes the
maximum permitted number os startup and shutdown events occur.
4
Formaldehyde emissions from the vendor data. Emissions during startup/shutdown operations are based on uncontrolled AP-42 emission factors. Other HAP emissions are based on uncontrolled AP-42 emission
factors to provide a basis for representation of potential emissions of HAPs. However, these values are conservatively high.
6
N2O emission rate based on the default emission factor in Table C-2 of 40 CFR Part 98 Subpart C for natural gas combustion. Startup and Shutdown event N2O emissions are estimated based on the startup
emissions of NOX in relation to steady-state emissions of NOX.
6
Source is subject to PSD permitting for its GHG emissions only when emissions of one or more non-GHGs are above major source thresholds.
El Paso Electric
Newman Station
Table 3 - Emergency Diesel Firewater Pump Engine Emissions

(EPN: FIRE-2)
Parameter Value Units Value Units

Power Output 1 99 hp
Estimated Heat Input 2 0.7 MMBtu/hr
Annual Hours of Operation (Total) 100 hrs/yr
3
Weight % of sulfur 0.0015 %
Fuel flow (volumetric basis) 4 5 gallons per hour 0.08 gpm
5
Density of fuel 876 kg/m3 7.31 lb/gal
Fuel flow (mass basis) 36.45 lb/hr
Emission Factor Potential Emissions

Criteria Pollutant 10 11
g/hp-hr lb/hp-hr kg/MMBtu lb/MMBtu lb/hr tpy
1
NOx 2.53 5.58E-03 - - 0.55 0.028
CO 1 0.60 1.32E-03 - - 0.13 0.007
VOC 1 0.24 5.29E-04 - - 0.05 0.003
1
PM/PM10/PM2.5 0.16 3.53E-04 - - 0.03 0.002
6
SO2 - - - - 1.09E-03 5.46E-05
7
GHG Pollutant g/hp-hr lb/hp-hr kg/MMBtu lb/MMBtu lb/hr 10
tpy 11
CO2 - - 73.96 - 113.02 5.65

CH4 - - 3.00E-03 - 4.58E-03 2.29E-04
N2 O - - 6.00E-04 - 9.17E-04 4.58E-05
CO 2 e 8 - - - - 113.40 5.67
HAP Pollutant 9 g/hp-hr lb/hp-hr kg/MMBtu lb/MMBtu lb/hr 10
tpy 11
1,3-Butadiene - - - 3.91E-05 2.71E-05 1.35E-06

Acetaldehyde - - - 7.67E-04 5.32E-04 2.66E-05
Acrolein - - - 9.25E-05 6.41E-05 3.21E-06
Benzene - - - 9.33E-04 6.47E-04 3.23E-05
Formaldehyde - - - 1.18E-03 8.18E-04 4.09E-05
Naphthalene - - - 8.48E-05 5.88E-05 2.94E-06
Toluene - - - 4.09E-04 2.83E-04 1.42E-05
Xylenes - - - 2.85E-04 1.98E-04 9.88E-06
TOTAL HAP 2.63E-03 1.31E-04
1
Engine emission data provided by John Deere. VOC emission factor is conservatively represented as the TOC emission factor provided by manufacturer since the VOC emission rates are not
specified. Particulate matter is assumed to equal PM10 and PM2.5.
2
Heat input calculated assuming a brake-specific fuel capacity of 7,000 Btu/hp-hr (Average brake-specific fuel consumption from AP-42 Table 3.3-1, footnote a), and calculated by the following
equation:
𝑀𝑀𝐵𝑡𝑢 𝐴𝑣𝑔 𝐵𝑟𝑎𝑘𝑒 𝑆𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑝𝑡𝑖𝑜𝑛 𝐵𝑡𝑢 ℎ𝑝 ∗ ℎ𝑟 ∗ 𝑀𝑎𝑥 𝑃𝑜𝑤𝑒𝑟 𝑂𝑢𝑡𝑝𝑢𝑡 ℎ𝑝
𝐸𝑠𝑡𝑖𝑚𝑎𝑡𝑒𝑑 𝐻𝑒𝑎𝑡 𝐼𝑛𝑝𝑢𝑡
ℎ𝑟 1,000,000 𝐵𝑡𝑢 𝑀𝑀𝐵𝑡𝑢
3
Sulfur weight percent based on the proposed sulfur content of ultra low sulfur diesel (ULSD) fuel (15 ppm).
4
The Fuel flow is estimated based on a fuel energy content of 139,000 Btu/gal for diesel fuel.
5
ASTM D 396 defines No. 2 Fuel Oil (i.e., Diesel Fuel) as having a maximum density of 876 kg/m3.
6
SO2 emission rate is calculated by assuming all sulfur in the fuel stream is converted to SO2, and is calculated as:
. .
𝑆𝑂 𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛 𝑅𝑎𝑡𝑒 𝐹𝑢𝑒𝑙 𝐹𝑙𝑜𝑤
.
7
CO2 emission factor obtained from 40 CFR 98 Subpart C, Table C-1 for diesel (Distillate Fuel Oil No. 2).
CH4 and N2O emission factors from 40 CFR 98, Subpart C, Table C-2 for diesel.
8
Global warming potentials obtained from Table A-1 to Subpart 98 - Global Warming Potentials
Equation A-1 CO2e = ∑GHGi x GWPi
Where:
CO2e = Carbon dioxide equivalent (tons/year)
GHGi = Mass emissions of each GHG (tons/year)
GWPi = Global warming potential for each GHG (1 for CO2, 25 for CH4, 298 for N2O)
9
HAP emission factors from AP-42 Chapter 3 Section 3 – Gasoline and Diesel Industrial Engines Table 3.3-2 - Speciated Organic Compounds Emission Factors for Uncontrolled Diesel Engines,
dated October 1996.
10
Hourly Potential Emissions (lb/hr) = Power Output (hp) x Emission Factor (lb/hp-hr)
or Hourly Potential Emissions (lb/hr) = Estimated Heat Input (MMBtu/hr) x Emission Factor (lb/MMBtu)
or Hourly Potential Emissions (lb/hr) = Estimated Heat Input (MMBtu/hr) x Emission Factor (kg/MMBtu) x (2.205 lb/kg)
11
Annual Potential Emissions (tpy) = Hourly Potential Emissions (lb/hr) x Annual Hours of Operation (hr/yr) / 2000 (lb/ton);
El Paso Electric
Newman Station
Table 4 - Forced Draft Line Heater Emissions

(EPN: LH-1)
Parameter Value Units

Estimated Heat Input 1 3.9 MMBtu/hr
Annual Hours of Operation (Total) 8,760 hrs/yr
Emission Factor Potential Emissions

Criteria Pollutant 5 6
lb/MMscf lb/MMBtu kg/MMBtu lb/hr tpy
1
NOx - 0.030 - 0.118 0.515
CO 1 - 0.037 - 0.145 0.635
VOC 1 - 0.008 - 0.031 0.137
PM/PM10/PM2.5 1 - 0.005 - 0.019 0.082
1
SO2 - 0.001 - 0.004 0.017
GHG Pollutant 2 lb/MMscf lb/MMBtu kg/MMBtu lb/hr 5
tpy 6
CO2 - - 53.06 458.72 1822.72

CH4 - - 1.00E-03 0.01 0.03
N2O - - 1.00E-04 0.00 0.00
3
CO 2 e - - - 459.20 1824.61
4
HAP Pollutant lb/MMscf lb/MMBtu kg/MMBtu lb/hr 5
tpy 6
2-Methylnaphthalene 2.40E-05 2.35E-08 - 9.23E-08 4.04E-07

3-Methylchloranthrene 1.80E-06 1.76E-09 - 6.92E-09 3.03E-08
7,12-Dimethylbenz(a)anthracene 1.60E-05 1.57E-08 - 6.15E-08 2.69E-07
Acenaphthene 1.80E-06 1.76E-09 - 6.92E-09 3.03E-08
Acenaphthylene 1.80E-06 1.76E-09 - 6.92E-09 3.03E-08
Anthracene 2.40E-06 2.35E-09 - 9.23E-09 4.04E-08
Benz(a)anthracene 1.80E-06 1.76E-09 - 6.92E-09 3.03E-08
Benzene 2.10E-03 2.06E-06 - 8.07E-06 3.54E-05
Benzo(a)pyrene 1.20E-06 1.18E-09 - 4.61E-09 2.02E-08
Benzo(b)fluoranthene 1.80E-06 1.76E-09 - 6.92E-09 3.03E-08
Benzo(g,h,i)perylene 1.20E-06 1.18E-09 - 4.61E-09 2.02E-08
Benzo(k)fluoranthene 1.80E-06 1.76E-09 - 6.92E-09 3.03E-08
Chrysene 1.80E-06 1.76E-09 - 6.92E-09 3.03E-08
Dibenzo(a,h)anthracene 1.20E-06 1.18E-09 - 4.61E-09 2.02E-08
Dichlorobenzene 1.20E-03 1.18E-06 - 4.61E-06 2.02E-05
Fluoranthene 3.00E-06 2.94E-09 - 1.15E-08 5.05E-08
Fluorene 2.80E-06 2.75E-09 - 1.08E-08 4.71E-08
Formaldehyde 7.50E-02 7.35E-05 - 2.88E-04 1.26E-03
n-Hexane 1.80E+00 1.76E-03 - 6.92E-03 3.03E-02
Indeno(1,2,3-cd)pyrene 1.80E-06 1.76E-09 - 6.92E-09 3.03E-08
Naphthalene 6.10E-04 5.98E-07 - 2.34E-06 1.03E-05
Phenanathrene 1.70E-05 1.67E-08 - 6.53E-08 2.86E-07
Pyrene 5.00E-06 4.90E-09 - 1.92E-08 8.42E-08
Toluene 3.40E-03 3.33E-06 - 1.31E-05 5.72E-05
TOTAL HAP 7.24E-03 3.17E-02
1
Heater Emission Data provided by equipment provider. Unit is equipped with a Low NOx Burner.
2
CO2 emission factor obtained from 40 CFR 98 Subpart C, Table C-1 for natural gas.
CH4 and N2O emission factors from 40 CFR 98, Subpart C, Table C-2 for natural gas.
3
Where:
GWPi = Global warming potential for each GHG (1 for CO2, 25 for CH4, 298 for N2O)
4
HAP emission factors from AP-42 Chapter 1 Section 4 – External Combustion Sources: Natural Gas Combustion
Table 1.4-3 - Emission Factors for Speciated Organic Compounds from Natural Gas Combustion, dated July 1998.
5
Hourly Potential Emissions (lb/hr) = Estimated Heat Input (MMBtu/hr) x Emission Factor (lb/MMBtu)
or Hourly Potential Emissions (lb/hr) = Estimated Heat Input (MMBtu/hr) x Emission Factor (kg/MMBtu) x (2.205
lb/kg)
or Hourly Potential Emissions (lb/hr) = Estimated Heat Input (MMBtu/hr) x AP-42 Emission Factor (lb/MMscf) /
1,020 Btu/scf
6
Annual Potential Emissions (tpy) = Hourly Potential Emissions (lb/hr) x Annual Hours of Operation (hr/yr) / 2000
(lb/ton);
El Paso Electric
Newman Station
Table 5a - Natural Gas GHG Fugitive Emissions (EPN: FUG-7)
Assumptions
Parameter Value Units
CH4 Content of Natural Gas 1 92.053% vol%
CO2 content of Natural Gas 1 0.1950% vol%
Density of CH4 0.04 lb/scf
Density of CO2 0.12 lb/scf
GWP for CH4 2 25
GWP for CO2 2 1
GWP for SF6 22800
Annual Hours of Operation 8,760 (hr/yr)
Total Gas Emission CH4 Emission CO2 Emission Fugitive CH4 Fugitive CO2 Total Fugitive CO2e
Factor 3 Factor Factor Component Emissions 5 Emissions 6 Emissions 7
Equipment Type
Count 4
(scf/hr/source) lb/hr/source lb/hr/source lb/hr tpy lb/hr tpy lb/hr tpy
Connector 0.017 0.001 0.000 0 0.00 0.00 0.00 0.00 0.00 0.00
Flanges 0.121 0.005 0.000 170 0.80 3.51 0.00 0.02 20.04 87.79
Open-ended lines 0.031 0.001 0.000 53 0.06 0.28 0.00 0.00 1.60 7.01
Sampling Connections 0.121 0.005 0.000 3 0.01 0.06 0.00 0.00 0.35 1.55
Pump seals 0.325 0.013 0.000 2 0.03 0.11 0.00 0.00 0.63 2.77
Pressure Relief Valve 0.193 0.008 0.000 4 0.03 0.13 0.00 0.00 0.75 3.29
Valves 0.121 0.005 0.000 124 0.58 2.56 0.00 0.01 14.62 64.03
Total - - 1.52 6.66 0.01 3.9E-02 38.00 166.45
1
Fuel quality specifications provided by EPE
2
Global warming potentials are based on 40 CFR Part 98, Table A-1.
3
All emission factors except pump seals obtained from 40 CFR part 98 subpart W, Table W-1A - Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production. The emission factor for Valves was used for
Flanges and Sampling Connections. The pump seal emission factor is obtained from EPA's Protocol for Equipment Leak Emission Estimates, Table 2-4, EPA-454/R-95-017, November 1995, but is adjusted to represent a total gas
emission factor by multiplying the factor by a ratio of the facility total gas weight percent to VOC weight percent since the EPA emission factor represents only non-methane, non-ethane hydrocarbon emissions.
4
Component count estimates for piping in both aqueous ammonia and natural gas service were estimated based on the component counts for a similar facility.
5
Total component counts include a 25% safety factor.
6
Volumetric emissions of GHG are derived from the equation in 40 CFR part 98 subpart W Equation W-1: Volume GHG scf/hr = Count x EF (Total Gas scf/hr/source) x GHG Concentration (vol%)
Mass GHG (lb/hr) = scf/hr GHG * density of GHG lb/scf (converted from kg/scf values in 40 CFR Part 98 paragraph 98.233(v))
Mass GHG (ton/yr) = GHG lb/hr * hr/yr / 2000 lb/ton.
7
Where:
GWPi = Global warming potential for each GHG
El Paso Electric
Newman Station
Table 5b - Electric Equipment Insulated with SF6 GHG Fugitive Emissions (EPN: FUG-7)
Fugitive SF6
SF6 Capacity 2 Fugitive SF6 Fugitive CO2e
Emissions 3
Breaker Type Quantity 1 Emissions 3 Emissions 4
each total
lb lb lb/yr lb/hr tpy lb/hr tpy
Generator 2 30.87 61.73 0.30865 0.00 0.00 0.80 3.52
Total 2 - 61.73 0.30865 0.00 0.00 0.80 3.52
1
Calculations assume 2 generator switches for the Project.
2
Generator circuit breakers contain approx 14 kg (30.87 lb) of SF6 gas each.
3
Circuit breaker fugitive emissions based on 0.5% annual leak rate as cited in J. Blackman, M. Averyt, and Z. Taylor, “SF6 Leak Rates from High Voltage Circuit Breakers – EPA Investigates Potential
Greenhouse Gas Emission Source,” available at: http://www.epa.gov/electricpower-sf6/documents/leakrates_circuitbreakers.pdf.
4
Where:
GWPi = Global warming potential for each GHG (22,800 for SF6)
El Paso Electric
Newman Station
Table 6a - Fugitive Ammonia Emissions (EPN: FUG-7)
Ammonia (NH3) Fugitive Emissions (EPN: FUG-7)
Emission Factor 1 Fugitive NH3 Emissions 4

Total Estimated
Equipment Type
Component Count 3
(lb/hr/source) (lb/hr) (tpy)
Compressors 0.5027 0 0.00E+00 0.00E+00
Flanges/Connectors 0.0005 73 6.94E-03 3.04E-02
Open-ended lines 0.0040 0 0.00E+00 0.00E+00
Pumps 0.0386 0 0.00E+00 0.00E+00
Relief Valve 0.2293 7 3.05E-01 1.34E+00
Sampling Connections 0.0330 0 0.00E+00 0.00E+00
Valves 0.0035 75 4.99E-02 2.18E-01
Total 0.36 1.58
1
Emission factors obtained from TCEQ's Emission Factors for Equipment Leak Fugitive Components , Addendum to RG-360A dated January
2008, Table 3 - Average Emission Factors - SOCMI (Light liquid Factors for SOCMI Without Ethylene were used).
2
Component count estimates for piping in both aqueous ammonia and natural gas service were estimated based on the component counts for
a similar facility.
3
4
Continuous operating for 8,760 hours and a 19% NH3 content of the aqueous ammonia.
El Paso Electric
Newman Station
Table 6b - Fugitive Natural Gas Emissions (EPN: FUG-7)
Natural Gas Fugitive Emissions (EPN: FUG-7)
Emission Factor 1,2 Total Estimated Fugitive VOC Emissions 4

Equipment Type
Component Count 3
(lb/hr/source) (lb/hr) (tpy)
Connector 4.40E-04 0 0.00E+00 0.00E+00
Flanges 8.60E-04 170 2.48E-03 1.09E-02
Open-ended lines 4.41E-03 53 3.97E-03 1.74E-02
Others 5 1.94E-02 7 2.31E-03 1.01E-02
Pump seals 5.29E-03 2 1.80E-04 7.87E-04
Valves 9.92E-03 124 2.09E-02 9.15E-02
Total 0.030 0.13
1
Emission factors obtained from EPA's Protocol for Equipment Leak Emission Estimates, Table 2-4, EPA-454/R-95-017, November 1995.
2
These factors are for total organic compound emission rates (including non-VOC's such as methane and ethane) and apply to light crude,
heavy crude, gas plant, gas production, and off-shore facilities. Since the emission factors are based on total organic compound (TOC)
emission rates. To determine VOC emissions, the fuel gas VOC content is divided by TOC content to get a weight percent VOC of TOC. This
value is used to convert the TOC emission factor to VOC emissions.
3
4
Based on continuous operating for 8,760 hours. Emission rates for HAPs are considered negligible due to the low overall VOC emissions and
the use of pipeline quality natural gas.
5
The "other" equipment type was derived from compressors, diaphragms, drains, dump arms, hatches, instruments, meters, pressure relief
valves, polished rods, relief valves, and vents. This "other" equipment type should be applied for any equipment type other than connectors,
flanges, open-ended line, pumps, or valves.
El Paso Electric
Newman Station
Table 7 - Fuel Gas Composition
Compositional Analysis Normalized Fuel Gas Composition 1
Molecular Weight
Species Formula MW Mol Fraction Weight %
Contribution
Hydrogen sulfide H2S 34.8 0.00000 0.000 0.0
Oxygen O2 32 0.00000 0.000 0.0
Nitrogen N2 28.01 2.24200 3.642 62.8
Carbon dioxide CO2 44.01 0.19500 0.498 8.6
Methane C1 16.04 92.05300 85.643 1476.5
Ethane C2 30.07 4.92500 8.590 148.1
Propane C3 44.1 0.47500 1.215 20.9
iso-Butane iC4 58.12 0.02000 0.067 1.2
n-Butane nC4 58.12 0.03600 0.121 2.1
iso-Pentane iC5 71.99 0.00600 0.025 0.4
n-Pentane nC5 71.99 0.04400 0.184 3.2
Hexanes C6 84 0.00300 0.015 0.3
Total: 100.00 100.000 1724.1
TOC 97.56200 95.85975
VOC 0.58400 1.62719
VOC/TOC1 0.59859 1.69747
1
Used to determine VOC emissions from natural gas fugitive emissions. The EPA Table 204 emission factors are
expressed as kg/hr/source of total organic compounds.
El Paso Electric
Newman Station
Table 8 - Emission Summary
CO NOX PM PM10 PM2.5 SO2 VOC H2SO4 Mist NH3

Emission Source (EPN)
(lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy)
SC-7 (Normal Operations) 18.40 25.20 7.00 7.00 7.00 1.54 7.00 1.41 18.70
237.02 120.58 30.66 30.66 30.66 6.75 113.99 6.18 81.91
SC-7 (MSS Operations) 555.67 58.50 7.00 7.00 7.00 1.54 312.92 1.41 18.70
FIRE-2 0.13 0.01 0.55 0.03 0.03 1.7E-03 0.03 1.7E-03 0.03 1.7E-03 1.1E-03 5.5E-05 0.05 2.6E-03 - - - -
LH-1 0.15 0.635 0.12 0.52 0.02 8.2E-02 0.02 8.2E-02 0.02 8.2E-02 3.9E-03 1.7E-02 0.031 0.14 - - - -
FUG-7 - - - - - - - - - - - - 0.03 0.13 - - 0.36 1.58
Total 1 555.94 237.66 59.17 121.12 7.05 30.74 7.05 30.74 7.05 30.74 1.55 6.76 313.03 114.26 1.41 6.18 19.06 83.49
1
Total short term emission rates reflect maximum hourly emission rates including MSS hourly emission rates. Emission rates during normal operations are lower for certain pollutants.
El Paso Electric
Newman Station
Table 9 - HAP Emission Summary
1,3 Butadiene Acetaldehyde Acrolein Benzene Ethylbenzene Formaldehyde Naphthalene PAH Propylene Oxide Toluene Xylenes Total HAP 1
Emission Source
(lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy)
SC-7 (Normal Operations) 1.1E-03 0.10 0.02 0.03 0.08 0.60 3.3E-03 0.01 0.07 0.33 0.16 1.40
4.7E-03 0.44 0.07 0.13 0.35 2.83 0.01 0.02 0.32 1.43 0.71 6.33
SC-7 (MSS Operations) 1.1E-03 0.10 0.02 0.03 0.08 1.29 3.3E-03 0.01 0.07 0.33 0.16 2.09
FIRE-2 2.7E-05 1.4E-06 5.3E-04 2.7E-05 6.4E-05 3.2E-06 6.5E-04 3.2E-05 - - 8.2E-04 4.1E-05 5.9E-05 2.9E-06 - - - - 2.8E-04 1.4E-05 2.0E-04 9.9E-06 2.6E-03 1.3E-04
LH-1 - - - - - - 8.1E-06 3.5E-05 - - 2.9E-04 1.3E-03 2.3E-06 1.0E-05 - - - - 1.3E-05 5.7E-05 - - 0.01 3.2E-02
Total 2 1.1E-03 4.7E-03 0.10 0.44 0.02 0.07 0.03 0.13 0.08 0.35 1.29 2.83 3.3E-03 1.4E-02 0.01 0.02 0.07 0.32 0.33 1.43 0.16 0.71 2.10 6.36
1
Individual HAP species with emissions less than 1.0E-5 tons per year from all sources are not included individually in this table but these emisisons are added into the Total HAP column.
2
Total short term emission rates reflect maximum hourly emission rates including MSS hourly emission rates. Emission rates during normal operations are lower for certain pollutants.
El Paso Electric
Newman Station
Table 10 - GHG Emission Summary
CO2 CH4 N 2O SF6 CO2e

Emission Source (EPN)
(lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (MT/yr)
SC-7 (Normal Operations) 300,700 18 0.56 - 301,305
1,317,066 626 2.66 - 1,333,499 1,209,731
SC-7 (MSS Operations) 252,167 1664 1.29 - 294,159
FIRE-2 113.02 5.65 4.6E-03 2.3E-04 9.2E-04 4.6E-05 - - 113.40 5.67 5.14
LH-1 458.72 1822.72 8.6E-03 3.4E-02 8.6E-04 3.4E-03 - - 459.20 1824.61 1655.26
FUG-7 0.01 0.04 1.52 6.66 - - 3.5E-05 1.5E-04 38.81 169.97 154.19
1
Total 301,272 1,318,894 1,666 632 1.3E+00 2.7E+00 3.5E-05 1.5E-04 301,917 1,335,500 1,211,545
1
Total short term emission rates reflect maximum hourly emission rates including MSS hourly emission rates. Emission rates are higher or lower for
certain GHGs depending on whether the unit is in normal operating mode or during a startup/shutdown activity.
El Paso Electric
Newman Station
Table 11 - PSD/NNSR Applicability Summary Table 12 - Major Source HAP thresholds

Newman Generating Station Major Source Status with
Major Project Located at Existing Major Source
Respect to NESHAP
Will the site
Significant Is the
Facility Site-wide Major Source become a
Emission Pollutant
Pollutant Emissions Pollutant Emissions Threshold major source
Rate above SER? 1
of HAPs?
(tpy) (tpy) (Yes/No) (tpy) (tpy) (Yes/No)
CO 237.66 100 Yes Formaldehyde 10.81 10 Yes
NOX 121.12 40 Yes Total HAP 30.61 25 Yes
PM 30.74 25 Yes
PM10 30.74 15 Yes
PM2.5 30.74 10 Yes
SO2 6.76 40 No
VOC 114.26 40 Yes
H2SO4 Mist 6.18 7 No
MT/yr MT/yr (Yes/No)
CO2e 1,211,545 75,000 Yes
1
From TCEQ (APDG 6240v11, Revised 10/18) Fact Sheet - PSD and
Nonattainment Significant Emissions
Appendix B. Manufacturer’s Specifications

Rating Specific Emissions Data
Nameplate Rating Information
Clarke Model JU4H-UFADJ2

Power Rating (BHP/kW) 99/74
Certified Speed (RPM) 2350
Refer to Rating Data section on page 2 for emissions output values

Rating Specific Emissions Data - John Deere Power Systems
Rating Data
Rating 4045HF280E
Certified Power(kW) 74
Rated Speed 2350
Vehicle Model Number OEM (Fire Pump)
Units g/kW-hr g/hp-hr
NOx 3.39 2.53
HC 0.32 0.24
NOx + HC N/A N/A
Pm 0.21 0.16
CO 0.9 0.6
Certificate Data
Engine Model Year 2019

EPA Family Name KJDXL04.5141
EPA JD Name 350HAM
EPA Certificate Number KJDXL04.5141-009
CARB Executive Order

Parent of Family 4045HFG81
Units g/kW-hr
NOx 4.18
HC 0.24
NOx + HC N/A
Pm 0.22
CO 0.6
* The emission data listed is measured from a laboratory test engine according to the test
procedures of 40 CFR 89 or 40 CFR 1039, as applicable. The test engine is intended to represent
nominal production hardware, and we do not guarantee that every production engine will have
identical test results. The family parent data represents multiple ratings and this data may have
been collected at a different engine speed and load. Emission results may vary due to engine
manufacturing tolerances, engine operating conditions, fuels used, or other conditions beyond
our control.
This information is property of Deere & Company. It is provided solely for the purpose of
obtaining certification or permits of Deere powered equipment. Unauthorized distribution of this
information is prohibited.
Emissions Results by Rating run on Feb-18-2019

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF TRANSPORTATION
2018 MODEL YEAR AND AIR QUALITY
CERTIFICATE OF CONFORMITY
WITH THE CLEAN AIR ACT ANN ARBOR, MICHIGAN 48105
Certificate Issued To: Deere & Company Effective Date: Issue Date:
(U.S. Manufacturer or Importer) 07/06/2017 07/06/2017
Certificate Number: JJDXL04.5141-007 Expiration Date:
_________________________ Revision Date:
Byron J. Bunker, Division Director
12/31/2018 Compliance Division N/A
Model Year: 2018 Mobile/Stationary Indicator: Stationary

Manufacturer Type: Original Engine Manufacturer Emissions Power Category: 56<=kW<75
Engine Family: JJDXL04.5141 Fuel Type: Diesel
After Treatment Devices: No After Treatment Devices Installed
Non-after Treatment Devices: Smoke Puff Limiter, Engine Design Modification, Non-standard
Non-After Treatment Device Installed
Pursuant to Section 111 and Section 213 of the Clean Air Act (42 U.S.C. sections 7411 and 7547) and 40 CFR Part 60, and subject to the terms and conditions prescribed in those provisions, this certificate of
conformity is hereby issued with respect to the test engines which have been found to conform to applicable requirements and which represent the following engines, by engine family, more fully described in
the documentation required by 40 CFR Part 60 and produced in the stated model year.
This certificate of conformity covers only those new compression-ignition engines which conform in all material respects to the design specifications that applied to those engines described in the
documentation required by 40 CFR Part 60 and which are produced during the model year stated on this certificate of the said manufacturer, as defined in 40 CFR Part 60.
It is a term of this certificate that the manufacturer shall consent to all inspections described in 40 CFR 1068 and authorized in a warrant or court order. Failure to comply with the requirements of such a
warrant or court order may lead to revocation or suspension of this certificate for reasons specified in 40 CFR Part 60. It is also a term of this certificate that this certificate may be revoked or suspended or
rendered void ab initio for other reasons specified in 40 CFR Part 60.
This certificate does not cover engines sold, offered for sale, or introduced, or delivered for introduction, into commerce in the U.S. prior to the effective date of the certificate.
HEATER SPECIFICATION SHEET
Forced Draft Line Heater
CUSTOMER DATE
ADDRESS CUSTOMER REFERENCE
CITY/STATE/ZIP CUSTOMER PROJECT NO.
LOCATION QUOTATION ITEM NUMBER
STATION OPERATING DATA 1290 psig 40°F / 1284 psig 80°F
ENGINEER
PURCHASING AGENT
BASIC HEATER DATA REMARKS
DIAMETER (inches) 72 BATH MEDIA VOLUME (Gal) 4,020 ETHYLENE GLYCOL 50/50
LENGTH (ft) 36' - 0" HEATER WEIGHT (DRY lbs) 22,900 HORIZONTAL -
WIDTH (ft) 8' - 0" HEATER WEIGHT (WET lbs) 59,183
HEIGHT (ft) (Shipping / Top of Stack) 9' - 0" / 13' - 0" POWER INPUT 480 VAC / 60 hz / 3 PH
NOMINAL RATING (MMBtu/hr) 3.9208
PROCESS CONDITIONS REMARKS
INLET OUTLET Forced Draft Burner
TYPE OF FLUID Natural Gas Natural Gas Blower Motor (HP) 7.5
TOTAL FLUID ENTERING SCFH 2,873,748 2,873,748 Sparging System NO
VAPOR lb/hr 135,000 135,000 Sparging System Motor (HP) NA
LIQUID lb/hr ------ ------ Safety include:
STEAM lb/hr ------ ------ Low Water Level
NON-CONDENSABLE lb/hr ------ ------ High Water Temp
FLUID VAPORIZED OR COND lb/hr ------ ------ Pilot Flame Failure
LIQUID DENSITY lbs/ft3 ------ ------ Controls Include:
LIQUID VISCOSITY cP ------ ------ Water Temp Control
LIQUID SPECIFIC HEAT Btu/lb-F ------ ------ Nat Gas Disch Temp Control
LIQUID THERMAL COND Btu/hr-ft-F ------ ------
VAPOR MOLECULAR WT lbs/lbs Mol 17.780 ------
VAPOR DENSITY lbs/ft3 5.6311 4.8105 Fluid Specific Gravity 0.615
VAPOR VISCOSITY cP 0.0137 0.0138 After Regulation (psig) 655
VAPOR SPECIFIC HEAT Btu/lb-F 0.7709 0.6919 After Regulation (F) 44
VAPOR THERMAL COND Btu/hr-ft-F 2.37E-02 2.39E-02 MINIMUM SUPPLY PRESSURE (MSP)
TEMPERATURE (IN/OUT) F 40 80 Outlet Temp at MSP (F) 80
OPERATING PRESSURE psig 1290 1284 Min Supply Press (psig) 1100
VELOCITY ft/sec ------ 34 VEL @ Min Oper Press (ft/sec) 41.0
PRESSURE DROP (ALLOW/EST) psid 10 6 Press Drop at MPS (psid) 8
FOULING RESISTANCE hr-ft2-f/Btu ------ ------
THERMAL DATA REMARKS
HEAT TRANSFERRED Btu/hr 3,920,765 Operating Bath Temperature 180.0 F
BURNER'S HEAT RELEASE (LHV) Btu/hr 4,900,956 Minimum Ambient Tempeature -41.5 F
TRANSFER RATE (FOULED/CLEAN) Btu/hr-ft2-F 62.39 Maximum Ambient Temperature 109 F
TEMPERATURE DIFF (LMTD) 119
PROCESS COIL
MAWP psig 1435 Fabrication Code ASME Section VIII Div 1
TEST PRESSURE psig 2153 Radiographic (Percentage) 100%
DESIGN TEMPERATURE F -20F to 250F National Board Stamped Yes
NUMBER OF PASS / PATH 6 Coil Material SA-106 Grade C Smls
NUMBER OF PATHS 5 Coil Hydrotest Note: 1.5 x MAWP for 4 hours Charted
TOTAL NUMBER OF TUBES 30 Shell Pressure Test: 5 psig for 1 hour
STRAIGHT TUBE LENGTH ft 668 Inlet 6 inch ANSI 900# RF 6.625
TYPE Serpentine Outlet 6 inch ANSI 900# RF 6.625
REMOVABLE Yes Inlet Header thk 0.432 in
HEAT FLUX Btu/hr-ft2 6,450 Inlet Header Velocity 45 ft/sec
TUBE SIZE inches OD 3.5 Outlet Header thk 0.432 in
TUBE WALL THICKNESS inches 0.3 Outlet Header Velocity 52 ft/sec
CORROSION ALLOWANCE inches 1/16 Surface Area Actual 612 ft2
HEATER DATA REMARKS
DESIGN CODE ASME CSD-1 Composition
SHELL DIAMETER inches 72 carbon dioxide 0.823%
SHELL LENGTH ft 24 nitrogen 1.298%
SHELL (THICK) inches 1/4 methane 89.604%
FIRETUBE DIAMETER inches OD 24 / 3 ethane 7.499%
NUMBER OF FIRETUBES 1 / 19 propane 0.541%
EACH FIRE / RETURN TUBE LENGTH ft 21.75 / 21.75 butane 0.032%
FIRE TUBE MATERIAL/THICKNESS inches 0.25 / 0.12 isobutane 0.024%
FIRE TUBE HEAT DENSITY Btu/hr-in2 11,293 pentane 0.004%
FIRE TUBE FLUX RATE Btu/hr-ft2 8,505 isopentane 0.005%
REMOVABLE No hexane 0.171%
STACK DIAMETER inches 1 / 20
STACK VELOCITY ft/sec 15.83
STACK HEIGHT (ACT / OF GRADE) ft 13 Emission Low NOx Burner lb/MMBTU
STACK MATERIAL SS304 NOx 25 PPM 0.03
WALL THICKNESS Gauge 10 (0.1406") Thick CO 50 PPM 0.037
EXPANSION TANK DIAMETER inches 24 SOx 1 PPM 0.001
EXPANSION TANK LENGTH ft 11 Hydrocarbon/VOC 20 PPM 0.008
EXPANSION TANK MATERIAL CS PM NA 0.0048
WALL THICKNESS inches 1/4
PERCENT OF NET SHELL VOL % 6

ADDITIONAL ENGINEERING INFORMATION
9.1 EXPECTED PERFORMANCE

 MAEP‐0595K, Rev. 7

NOTICE OF PROPRIETARY STATUS AND CONFIDENTIALITY
This document contains confidential and proprietary information of MITSUBISHI HITACHI POWER SYSTEMS AMERICAS,
INC. and is subject to the confidentiality provisions set forth in Section 26 of the EQUIPMENT PURCHASE AND SALE
AGREEEMENT FOR NEWMAN 6‐GT5‐M501GAC BY AND BETWEEN EL PASO ELECTRIC COMPANY AND MITSUBISHI
HITACHI POWER SYSTEMS AMERICAS, INC., dated as of [_________________________], 2019.

Company Confidential and Proprietary
© 2019, Mitsubishi Hitachi Power Systems Americas, Inc. All Rights Reserved.
Spec. No.: MHPS‐AEG19‐0595‐R2 9.1.i One (1) – M501GAC – Equipment
MAEP-0595K Rev.7
14-Jun-19
COMMERCIAL DATA
Customer El Paso Electric
Project Name El Paso, TX
Manufacturer Mitsubishi Hitachi Power Systems Americas Inc.
INPUT INFORMATION
Configuration & Arrangement GTG Only 1x0 with Hot SCR
Scope GTG Only
Fuel Heating Value HHV Btu/lb 22,732
Fuel Heating Value LHV Btu/lb 20,501
CASE # 1 2 3 4 5 6 7 8 9 10 11 12
Design Point (Indicated by *) *
°
Ambient Dry Bulb Temperature F 105.0 105.0 105.0 105.0 105.0 70.0 70.0 70.0 70.0 70.0 35.0 35.0
Barometric Pressure psia 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693
Relative Humidity % 13.0 13.0 13.0 13.0 13.0 50.0 50.0 50.0 50.0 50.0 67.0 67.0
Inlet Conditioning Evaporative Cooler On/Off ON OFF OFF OFF OFF ON OFF OFF OFF OFF OFF OFF
GT PERFORMANCE (per GT)
GT Load % Base Base 80% 60% 55% Base Base 80% 60% 50% Base 80%
GT Heat Input MMBtu/h - HHV 2,301 2,057 1,740 1,443 1,368 2,379 2,309 1,892 1,556 1,396 2,514 2,036
Gross GT Power Output kW 231,800 202,500 164,800 123,600 113,300 241,100 233,100 186,500 139,900 116,500 257,700 206,900
Gross GT Heat Rate Btu/kWh - HHV 9,926 10,155 10,557 11,669 12,073 9,866 9,904 10,144 11,122 11,977 9,752 9,837
MHPS GT Auxiliary Loads kW 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000
Net GT Power Output kW 227,800 198,500 160,800 119,600 109,300 237,100 229,100 182,500 135,900 112,500 253,700 202,900
Net GT Heat Rate Btu/kWh - HHV 10,101 10,360 10,819 12,060 12,515 10,032 10,077 10,366 11,449 12,402 9,906 10,031
Hot SCR EXHAUST CONDITIONS @ Stack (per Stack)
Hot SCR Stack Exhaust Flow kpph 6,523 6,095 Later Later 4,492 6,550 6,428 Later Later 4,369 6,694 Later
Hot SCR Stack Exhaust Volumetric Flow ACFM 4,029,414 3,752,178 Later Later 2,760,176 4,040,786 3,960,881 Later Later 2,688,871 4,113,454 Later
Hot SCR Stack Exhaust Velocity ft/s 93 87 Later Later 64 93 91 Later Later 62 95 Later
°
Hot SCR Stack Exhaust Temperature F 825 825 Later Later 825 825 825 Later Later 825 825 Later
Hot SCR Stack Exhaust Gas Composition vol% Later Later Later Later Later
O₂ 14.78 15.16 Later Later 15.72 14.66 14.77 Later Later 15.42 14.68 Later
CO₂ 2.68 2.58 Later Later 2.32 2.76 2.73 Later Later 2.43 2.86 Later
H₂O 7.02 6.08 Later Later 5.58 6.96 6.66 Later Later 6.09 6.03 Later
N₂ 74.60 75.26 Later Later 75.46 74.71 74.91 Later Later 75.13 75.51 Later
Ar 0.92 0.93 Later Later 0.93 0.92 0.93 Later Later 0.93 0.93 Later
Hot SCR Stack Exhaust Gas Mol.Weight lb/lbmol 28.44 28.53 Later Later 28.56 28.45 28.48 Later Later 28.52 28.56 Later
STACK EMISSIONS (per Stack)
NOx (abated) ppmvd@15% O₂ 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5
NOx (abated) lb/MMBtu - HHV 0.00998 0.00997 0.00996 0.00995 0.00995 0.00997 0.00997 0.00997 0.00996 0.00997 0.00997 0.00997
CO (abated) ppmvd@15% O₂ 3 3 3 3 3 3 3 3 3 3 3 3
CO (abated) lb/MMBtu - HHV 0.00729 0.00728 0.00728 0.00727 0.00727 0.00728 0.00728 0.00728 0.00728 0.00728 0.00728 0.00729
VOC (abated) ppmvd@15% O₂ 2 2 2 2 2 2 2 2 2 2 2 2
VOC (abated) lb/MMBtu - HHV 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278
Particulates (PM₁₀ Total) lb/h 6.4 6.0 5.1 4.2 4.0 6.6 6.5 5.4 4.4 4.0 7.0 5.8
Particulates (PM₁₀ Total) lb/MMBtu - HHV 0.00279 0.00289 0.00294 0.00291 0.00295 0.00279 0.00281 0.00287 0.00283 0.00288 0.00279 0.00285
Ammonia Slip (NH₃) ppmvd@15% O₂ 5 5 5 5 5 5 5 5 5 5 5 5
Ammonia Slip (NH₃) lb/MMBtu - HHV 0.00739 0.00738 0.00737 0.00737 0.00737 0.00738 0.00738 0.00738 0.00737 0.00738 0.00738 0.00738
Ammonia Feed (Aqueous 19% by weight) lb/h 489 438 Later Later 290 505 490 Later Later 296 533 Later
CO₂ lb/h 274,300 245,900 207,100 171,900 163,000 283,200 274,900 225,200 185,200 166,200 299,300 242,600
CO₂ lb/MWhgross 1,183 1,214 1,257 1,390 1,438 1,175 1,179 1,208 1,324 1,426 1,161 1,173
NOTES (Performance notes apply to all cases unless otherwise specified.):

1. All performance data are based on New & Clean conditions.
2. All supplied values are estimations and not guaranteed.
3. Fuel gas composition normalized to (mol%), 92.053% CH₄, 4.925% C₂H₆, 0.475% C₃H₈, 0.036% n-C₄H₁₀, 0.02% i-C₄H₁₀,
0.044% n-C₅H₁₂, 0.006% i-C₅H₁₂, 0.003% C₆H₁₄, 2.242% N₂, 0.195% CO₂
4. 0.2 gr/100scf of sulfur and 0% fuel bound nitrogen (FBN) are considered in the fuel.
Fuel must be in compliance with MHPS's fuel specification.
5. Gross power output is at the generator terminals minus excitation losses.
6. Design Conditions: Frequency 60 Hz, Generator Power Factor 0.85
7. N/A
8. Confer with MHPS prior to including in any air permit application.
9. VOC's are expressed as non-methane and non-ethane basis assuming equivalent molecular weight of methane.
10. At the higher and lower bounds of ambient conditions, the GT load may be restricted due to mechanical limitations. The
load percentages shown are based on the theoretical unrestricted base load performance and therefore may not be
proportional to the higher loads stated for identical ambient conditions.
© All rights reserved 2019. Confidential Proprietary

Mitsubishi Hitachi Power Systems Americas, Inc.
7a
MAEP-0595K Rev.7 MAEP-0595K Rev.7
14-Jun-19
COMMERCIAL DATA
Customer El Paso Electric
Project Name El Paso, TX
Manufacturer Mitsubishi Hitachi Power Systems Americas Inc.
INPUT INFORMATION
Configuration & Arrangement GTG Only 1x0 with Hot SCR
Scope GTG Only
Fuel Heating Value HHV Btu/lb 22,732
Fuel Heating Value LHV Btu/lb 20,501
CASE # 13 14 15 16 17 18 19 20 21 22
Design Point (Indicated by *)
°
Ambient Dry Bulb Temperature F 35.0 35.0 26.0 26.0 26.0 26.0 -10.0 -10.0 -10.0 -10.0
Barometric Pressure psia 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693 12.693
Relative Humidity % 67.0 67.0 23.2 23.2 23.2 23.2 60.0 60.0 60.0 60.0
Inlet Conditioning Evaporative Cooler On/Off OFF OFF OFF OFF OFF OFF OFF OFF OFF OFF
GT PERFORMANCE (per GT)
GT Load % 60% 50% Base 80% 60% 50% Base 80% 60% 50%
GT Heat Input MMBtu/h - HHV 1,657 1,492 2,542 2,070 1,680 1,514 2,526 2,267 1,799 1,614
Gross GT Power Output kW 155,200 129,300 261,900 211,700 158,700 132,300 257,000 230,300 172,700 143,900
Gross GT Heat Rate Btu/kWh - HHV 10,671 11,538 9,704 9,775 10,584 11,440 9,829 9,844 10,413 11,216
MHPS GT Auxiliary Loads kW 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000
Net GT Power Output kW 151,200 125,300 257,900 207,700 154,700 128,300 253,000 226,300 168,700 139,900
Net GT Heat Rate Btu/kWh - HHV 10,954 11,906 9,855 9,964 10,857 11,797 9,984 10,018 10,660 11,537
Hot SCR EXHAUST CONDITIONS @ Stack (per Stack)
Hot SCR Stack Exhaust Flow kpph Later 4,421 6,700 Later Later 4,431 6,462 Later Later 4,496
Hot SCR Stack Exhaust Volumetric Flow ACFM Later 2,713,560 4,111,283 Later Later 2,715,984 3,965,694 Later Later 2,756,772
Hot SCR Stack Exhaust Velocity ft/s Later 63 95 Later Later 63 91 Later Later 64
°
Hot SCR Stack Exhaust Temperature F Later 825 825 Later Later 825 825 Later Later 825
Hot SCR Stack Exhaust Gas Composition vol% Later Later Later Later Later
O₂ Later 15.30 14.68 Later Later 15.30 14.50 Later Later 15.04
CO₂ Later 2.57 2.89 Later Later 2.61 2.98 Later Later 2.73
H₂O Later 5.47 5.71 Later Later 5.14 5.80 Later Later 5.33
N₂ Later 75.73 75.78 Later Later 76.01 75.77 Later Later 75.95
Ar Later 0.93 0.94 Later Later 0.94 0.94 Later Later 0.94
Hot SCR Stack Exhaust Gas Mol.Weight lb/lbmol Later 28.60 28.60 Later Later 28.64 28.60 Later Later 28.63
STACK EMISSIONS (per Stack)
NOx (abated) ppmvd@15% O₂ 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5
NOx (abated) lb/MMBtu - HHV 0.00995 0.00997 0.00998 0.00997 0.00995 0.00997 0.00998 0.00997 0.00996 0.00996
CO (abated) ppmvd@15% O₂ 3 3 3 3 3 3 3 3 3 3
CO (abated) lb/MMBtu - HHV 0.00727 0.00728 0.00729 0.00728 0.00727 0.00728 0.00729 0.00728 0.00727 0.00728
VOC (abated) ppmvd@15% O₂ 2 2 2 2 2 2 2 2 2 2
VOC (abated) lb/MMBtu - HHV 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278 0.00278
Particulates (PM₁₀ Total) lb/h 4.7 4.2 7.1 5.9 4.7 4.3 7.0 6.5 5.0 4.5
Particulates (PM₁₀ Total) lb/MMBtu - HHV 0.00281 0.00283 0.00279 0.00285 0.00281 0.00282 0.00275 0.00284 0.00279 0.00279
Ammonia Slip (NH₃) ppmvd@15% O₂ 5 5 5 5 5 5 5 5 5 5
Ammonia Slip (NH₃) lb/MMBtu - HHV 0.00737 0.00738 0.00739 0.00738 0.00737 0.00738 0.00739 0.00738 0.00737 0.00737
Ammonia Feed (Aqueous 19% by weight) lb/h Later 316 540 Later Later 321 536 Later Later 341
CO₂ lb/h 197,400 177,500 302,600 246,400 199,900 180,100 300,700 269,900 214,100 192,100
CO₂ lb/MWhgross 1,272 1,373 1,156 1,164 1,260 1,361 1,170 1,172 1,239 1,335
NOTES (Performance notes apply to all cases unless otherwise specified.):

1. All performance data are based on New & Clean conditions.
2. All supplied values are estimations and not guaranteed.
3. Fuel gas composition normalized to (mol%), 92.053% CH₄, 4.925% C₂H₆, 0.475% C₃H₈, 0.036% n-C₄H₁₀, 0.02% i-C₄H₁₀,
0.044% n-C₅H₁₂, 0.006% i-C₅H₁₂, 0.003% C₆H₁₄, 2.242% N₂, 0.195% CO₂
4. 0.2 gr/100scf of sulfur and 0% fuel bound nitrogen (FBN) are considered in the fuel.
Fuel must be in compliance with MHPS's fuel specification.
5. Gross power output is at the generator terminals minus excitation losses.
6. Design Conditions: Frequency 60 Hz, Generator Power Factor 0.85
7. N/A
8. Confer with MHPS prior to including in any air permit application.
9. VOC's are expressed as non-methane and non-ethane basis assuming equivalent molecular weight of methane.
10. At the higher and lower bounds of ambient conditions, the GT load may be restricted due to mechanical limitations. The
load percentages shown are based on the theoretical unrestricted base load performance and therefore may not be
proportional to the higher loads stated for identical ambient conditions.
© All rights reserved 2019. Confidential Proprietary

Mitsubishi Hitachi Power Systems Americas, Inc.
7a
AHT - Villeurbanne
Country : USA
Tender : 20050728 Grid Solutions
Date : 1/24/2019
Rev. : 0
FKG type SF6 Generator Circuit-Breaker Cell A2
General characteristics
Electrical references standard IEC/IEEE 62271-37-013: 2015
Rated voltage (kV) 24
Rated frequency (Hz) 60
Service conditions
Rated service voltage (kV) 21
Rated normal current (A) 10000 @ 40 °C
Location Outdoor
Ambiant air temperature limits (°C) -25°C / 40 °C
IPB without forced cooling
- Busbars temperature limit (°C) 105
- Enclosure temperature limit (°C) 80
Cell description
Number of phases 3
Phase spacing (mm) 1200
Number of LV control cubicle 1
Drive mechanism location (seen from the transformer side) On the right
Protection Degrees (enclosure / cubicles) IP65 / IP55
Enclosure type (thickness) Aluminum (6 mm)
- paint color (enclosure / cover) RAL9010GL / RAL9010GL
Cubicles type (thickness) Aluminum (2 mm)
- paint color (body / cover) RAL9010GL / RAL9010GL
Reference Documentation
Outline drawing, for tender purpose VSFKGA2--GAD03D
Elementary diagram, for tender purpose VSFKG-A2-EDD01D
Inspection program DAQ 233 - DAQ 338
Interlocking diagram, for tender purpose VSFKG---RIDD22D
Typical Single Line Diagram configuration

MECHANISM Grid Solutions supply
Transformer
1a
Transformer Generator
CT1 CT3 CT4 CT6
CT2 1c 1b CT5
MECHANISM
MECHANIS
MKG/SVS
FKG
PT3 PT6
MKG SA PT1 PT2 PT4 PT5 MKG
IKG
MECHANISM
1a. Main contacts in Air / 1b. Arcing contacts in SF6 / 1c. Safety Visual Switch (SVS) in Air
1a + 1b = Circuit breaker / 1a + 1c = Air-Disconnector
Equipment list proposal

CT1 - Current transformer : 10000A / 5A - C800 - PER CLASS VA
PT1 - Potential transformer U
> N1 : 21000 / √3 V - 120 / √3 V - 0.3WXY1.2Z
-> Tertiary : 21000 / √3 V - 120 / 3 V - 1.2WXM - 35 VA
Surge arrester on transformer side : PSB20G
Capacitor on transformer side : 300 nF
Capacitor on generator side : 50 nF
1/4
AHT - Villeurbanne
Country : USA
Date : 1/24/2019
Rev. : 0
2/4
AHT - Villeurbanne
Country : USA
Date : 1/24/2019
Rev. : 0
Circuit Breaker with integrated Air-Disconnector FKG
Rated normal current (A) 10000 @ 40 °C

Rated peak withstand current (kApeak) 220
Rated short time withstand current (kA) 80
Rated duration of short-circuit (s) 3
Rated insulation level (at sea level)

Phase to earth
Rated power frequency withstand voltage (kV) 60
Rated lightning impulse withstand voltage : wave 1,2/50µs (kVpeak) 125
Across the isolating distance (open contacts)
Breaking and Making characteristics

Rated breaking capacity :
- Symmetrical short-circuit (system-source fault) (kA) 80
asymmetrical short-circuit : DC component (%) 75
- Symmetrical short-circuit (generator-source fault) (kA) 47.6
asymmetrical short-circuit : DC component (%) 130
Generator circuit-breaker class G2
First pole to clear factor 1.5
Rated short-circuit making current (kApeak) 220
Rated out-of-phase breaking current (kA) 40
Drive mechanism Spring - Spring

Operating Three phase reclosing
Number of mechanism 1
Rated short-circuit current operating sequence CO-30min-CO
Rated load current operating sequence CO-3min-CO
Rated operating sequence without motor supply O-CO
Rated breaking time (note 1) (ms) 75
Rated closing time (note 2) (ms) 116
Free auxiliary switches NO / NC 10 / 10
Insulating gas SF6

Rated absolute pressure at 20°C Pre (kPa) 850
Alarm absolute pressure at 20°C Pae (kPa) 740
Minimum absolute pressure at 20°C Pme (kPa) 710
Gas mass per circuit-breaker (kg) 14
Number of densimeter per circuit breaker 1
Auxiliaries operating voltage

Opening and closing circuits 125 Vdc
Spring charging motor 120 Vac 1P+N
Heating and lighting circuits 120 Vac-1P+N
3/4
AHT - Villeurbanne
Country : USA
Date : 1/24/2019
Rev. : 0
Safety Visual Switch (Air gap) SVS
Rated insulation level across the isolating distance (at sea level)
Drive mechanism Electrical motor

Motor operating voltage 480 Vac 60Hz 3P+N
Free auxiliary switches NO / NC 6/6
Yes
Earthing switch for generator busbar MKG
Yes
Rated peak withstand current (kApeak) 220
Rated short time withstand current (kA) 80
Rated duration of short-circuit (s) 3
Operating time (s) 6.5
Rated insulation level across open contacts (at sea level)

Drive mechanism Electrical motor

Motor operating voltage 480 Vac 60Hz 3P+N
Free auxiliary switches NO / NC 6/6
4/4
Safety Data Sheet
SECTION 1 PRODUCT AND COMPANY IDENTIFICATION
GST Premium 32
Product Use: Turbine Oil

Product Number(s): 253092, 278072
Synonyms: GST Premium 32 ISOCLEAN Certified
Company Identification
Chevron Products Company
a division of Chevron U.S.A. Inc.
6001 Bollinger Canyon Rd.
San Ramon, CA 94583
United States of America
www.chevronlubricants.com
Transportation Emergency Response

CHEMTREC: (800) 424-9300 or (703) 527-3887
Health Emergency
Chevron Emergency Information Center: Located in the USA. International collect calls accepted. (800)
231-0623 or (510) 231-0623
Product Information
email : lubemsds@chevron.com
Product Information: 1 (800) 582-3835, LUBETEK@chevron.com
SECTION 2 HAZARDS IDENTIFICATION
CLASSIFICATION: Not classified as hazardous according to 29 CFR 1910.1200 (2012).
HAZARDS NOT OTHERWISE CLASSIFIED: Not Applicable

_____________________________________________________________________
Revision Number: 3 1 of 9 GST Premium 32

SDS : 32230
Revision Date: January 25, 2017
SECTION 3 COMPOSITION/ INFORMATION ON INGREDIENTS
COMPONENTS CAS NUMBER AMOUNT

Highly refined mineral oil (C15 - C50) Mixture 70 - 99 %weight
SECTION 4 FIRST AID MEASURES
Description of first aid measures

Eye: No specific first aid measures are required. As a precaution, remove contact lenses, if worn, and
flush eyes with water.
Skin: No specific first aid measures are required. As a precaution, remove clothing and shoes if
contaminated. To remove the material from skin, use soap and water. Discard contaminated clothing and
shoes or thoroughly clean before reuse.
Ingestion: No specific first aid measures are required. Do not induce vomiting. As a precaution, get
medical advice.
Inhalation: No specific first aid measures are required. If exposed to excessive levels of material in the air,
move the exposed person to fresh air. Get medical attention if coughing or respiratory discomfort occurs.
Most important symptoms and effects, both acute and delayed

IMMEDIATE HEALTH EFFECTS
Eye: Not expected to cause prolonged or significant eye irritation.
Skin: Contact with the skin is not expected to cause prolonged or significant irritation. Contact with the skin
is not expected to cause an allergic skin response. Not expected to be harmful to internal organs if
absorbed through the skin. High-Pressure Equipment Information: Accidental high-velocity injection under
the skin of materials of this type may result in serious injury. Seek medical attention at once should an
accident like this occur. The initial wound at the injection site may not appear to be serious at first; but, if
left untreated, could result in disfigurement or amputation of the affected part.
Ingestion: Not expected to be harmful if swallowed.

Inhalation: Not expected to be harmful if inhaled. Contains a petroleum-based mineral oil. May cause
respiratory irritation or other pulmonary effects following prolonged or repeated inhalation of oil mist at
airborne levels above the recommended mineral oil mist exposure limit. Symptoms of respiratory irritation
may include coughing and difficulty breathing.
DELAYED OR OTHER HEALTH EFFECTS: Not classified
Indication of any immediate medical attention and special treatment needed

Note to Physicians: In an accident involving high-pressure equipment, this product may be injected under
the skin. Such an accident may result in a small, sometimes bloodless, puncture wound. However,
because of its driving force, material injected into a fingertip can be deposited into the palm of the hand.
_____________________________________________________________________

SDS : 32230
Within 24 hours, there is usually a great deal of swelling, discoloration, and intense throbbing pain.
Immediate treatment at a surgical emergency center is recommended.
SECTION 5 FIRE FIGHTING MEASURES
EXTINGUISHING MEDIA: Use water fog, foam, dry chemical or carbon dioxide (CO2) to extinguish
flames.
Unusual Fire Hazards: Leaks/ruptures in high pressure system using materials of this type can create a
fire hazard when in the vicinity of ignition sources (eg. open flame, pilot lights, sparks, or electric arcs).
PROTECTION OF FIRE FIGHTERS:

Fire Fighting Instructions: This material will burn although it is not easily ignited. See Section 7 for proper
handling and storage. For fires involving this material, do not enter any enclosed or confined fire space
without proper protective equipment, including self-contained breathing apparatus.
Combustion Products: Highly dependent on combustion conditions. A complex mixture of airborne
solids, liquids, and gases including carbon monoxide, carbon dioxide, and unidentified organic compounds
will be evolved when this material undergoes combustion.
SECTION 6 ACCIDENTAL RELEASE MEASURES
Protective Measures: Eliminate all sources of ignition in vicinity of spilled material.

Spill Management: Stop the source of the release if you can do it without risk. Contain release to prevent
further contamination of soil, surface water or groundwater. Clean up spill as soon as possible, observing
precautions in Exposure Controls/Personal Protection. Use appropriate techniques such as applying
non-combustible absorbent materials or pumping. Where feasible and appropriate, remove contaminated
soil. Place contaminated materials in disposable containers and dispose of in a manner consistent with
applicable regulations.
Reporting: Report spills to local authorities and/or the U.S. Coast Guard's National Response Center at
(800) 424-8802 as appropriate or required.
SECTION 7 HANDLING AND STORAGE
General Handling Information: Avoid contaminating soil or releasing this material into sewage and
drainage systems and bodies of water.
Precautionary Measures: DO NOT USE IN HIGH PRESSURE SYSTEMS in the vicinity of flames, sparks
and hot surfaces. Use only in well ventilated areas. Keep container closed.
Static Hazard: Electrostatic charge may accumulate and create a hazardous condition when handling this
material. To minimize this hazard, bonding and grounding may be necessary but may not, by themselves,
be sufficient. Review all operations which have the potential of generating and accumulating an
electrostatic charge and/or a flammable atmosphere (including tank and container filling, splash filling, tank
cleaning, sampling, gauging, switch loading, filtering, mixing, agitation, and vacuum truck operations) and
use appropriate mitigating procedures.
Container Warnings: Container is not designed to contain pressure. Do not use pressure to empty
container or it may rupture with explosive force. Empty containers retain product residue (solid, liquid,
_____________________________________________________________________

SDS : 32230
and/or vapor) and can be dangerous. Do not pressurize, cut, weld, braze, solder, drill, grind, or expose
such containers to heat, flame, sparks, static electricity, or other sources of ignition. They may explode and
cause injury or death. Empty containers should be completely drained, properly closed, and promptly
returned to a drum reconditioner or disposed of properly.
SECTION 8 EXPOSURE CONTROLS/PERSONAL PROTECTION
GENERAL CONSIDERATIONS:
Consider the potential hazards of this material (see Section 2), applicable exposure limits, job activities,
and other substances in the work place when designing engineering controls and selecting personal
protective equipment. If engineering controls or work practices are not adequate to prevent exposure to
harmful levels of this material, the personal protective equipment listed below is recommended. The user
should read and understand all instructions and limitations supplied with the equipment since protection is
usually provided for a limited time or under certain circumstances.
ENGINEERING CONTROLS:
Use in a well-ventilated area.
PERSONAL PROTECTIVE EQUIPMENT

Eye/Face Protection: No special eye protection is normally required. Where splashing is possible, wear
safety glasses with side shields as a good safety practice.
Skin Protection: No special protective clothing is normally required. Where splashing is possible, select
protective clothing depending on operations conducted, physical requirements and other substances in the
workplace. Suggested materials for protective gloves include: 4H (PE/EVAL), Nitrile Rubber, Silver
Shield, Viton.
Respiratory Protection: No respiratory protection is normally required.
If user operations generate an oil mist, determine if airborne concentrations are below the occupational
exposure limit for mineral oil mist. If not, wear an approved respirator that provides adequate protection
from the measured concentrations of this material. For air-purifying respirators use a particulate cartridge.
Use a positive pressure air-supplying respirator in circumstances where air-purifying respirators may not
provide adequate protection.
Occupational Exposure Limits:
Component Agency TWA STEL Ceiling Notation
Highly refined mineral oil (C15 - OSHA Z-1 5 mg/m3 -- -- --

C50)
Highly refined mineral oil (C15 - ACGIH 5 mg/m3 10 mg/m3 -- --
C50)
Consult local authorities for appropriate values.
SECTION 9 PHYSICAL AND CHEMICAL PROPERTIES
_____________________________________________________________________

SDS : 32230
Attention: the data below are typical values and do not constitute a specification.
Color: Colorless to yellow

Physical State: Liquid
Odor: Petroleum odor
Odor Threshold: No data available
pH: Not Applicable
Vapor Pressure: <0.01 mmHg @ 37.8 °C (100 °F)
Vapor Density (Air = 1): >1
Initial Boiling Point: 315°C (599°F)
Solubility: Soluble in hydrocarbons; insoluble in water
Freezing Point: Not Applicable
Melting Point: No data available
Density: 0.8604 kg/l @ 15°C (59°F) (Typical)
Viscosity: 28.80 mm2/s - 32 mm2/s @ 40°C (104°F)
Coefficient of Therm. Expansion / °F: No data available
Evaporation Rate: No data available
Decomposition temperature: No data available
Octanol/Water Partition Coefficient: No data available
FLAMMABLE PROPERTIES:
Flammability (solid, gas): No Data Available
Flashpoint: (Cleveland Open Cup) 215 °C (419 °F) Minimum

Autoignition: No data available
Flammability (Explosive) Limits (% by volume in air): Lower: Not Applicable Upper: Not Applicable
SECTION 10 STABILITY AND REACTIVITY
Reactivity: May react with strong acids or strong oxidizing agents, such as chlorates, nitrates, peroxides,
etc.
Chemical Stability: This material is considered stable under normal ambient and anticipated storage and
handling conditions of temperature and pressure.
Incompatibility With Other Materials: Not applicable
Hazardous Decomposition Products: None known (None expected)
Hazardous Polymerization: Hazardous polymerization will not occur.
SECTION 11 TOXICOLOGICAL INFORMATION
Information on toxicological effects

Serious Eye Damage/Irritation: The eye irritation hazard is based on evaluation of data for product
components.
_____________________________________________________________________

SDS : 32230
Skin Corrosion/Irritation: The skin irritation hazard is based on evaluation of data for product components.
Skin Sensitization: The skin sensitization hazard is based on evaluation of data for product components.
Acute Dermal Toxicity: The acute dermal toxicity hazard is based on evaluation of data for product
components.
Acute Oral Toxicity: The acute oral toxicity hazard is based on evaluation of data for product components.
Acute Inhalation Toxicity: The acute inhalation toxicity hazard is based on evaluation of data for product
components.
Acute Toxicity Estimate: Not Determined
Germ Cell Mutagenicity: The hazard evaluation is based on data for components or a similar material.
Carcinogenicity: The hazard evaluation is based on data for components or a similar material.
Reproductive Toxicity: The hazard evaluation is based on data for components or a similar material.
Specific Target Organ Toxicity - Single Exposure: The hazard evaluation is based on data for components
or a similar material.
Specific Target Organ Toxicity - Repeated Exposure: The hazard evaluation is based on data for
components or a similar material.
ADDITIONAL TOXICOLOGY INFORMATION:

This product contains petroleum base oils which may be refined by various processes including severe
solvent extraction, severe hydrocracking, or severe hydrotreating. None of the oils requires a cancer
warning under the OSHA Hazard Communication Standard (29 CFR 1910.1200). These oils have not
been listed in the National Toxicology Program (NTP) Annual Report nor have they been classified by the
International Agency for Research on Cancer (IARC) as; carcinogenic to humans (Group 1), probably
carcinogenic to humans (Group 2A), or possibly carcinogenic to humans (Group 2B).
These oils have not been classified by the American Conference of Governmental Industrial Hygienists
(ACGIH) as: confirmed human carcinogen (A1), suspected human carcinogen (A2), or confirmed animal
carcinogen with unknown relevance to humans (A3).
SECTION 12 ECOLOGICAL INFORMATION
ECOTOXICITY
This material is not expected to be harmful to aquatic organisms.
The product has not been tested. The statement has been derived from the properties of the individual
components.
MOBILITY
_____________________________________________________________________

SDS : 32230
No data available.
PERSISTENCE AND DEGRADABILITY

This material is not expected to be readily biodegradable. The biodegradability of this material is based on
an evaluation of data for the components or a similar material.
The product has not been tested. The statement has been derived from the properties of the individual
components.
POTENTIAL TO BIOACCUMULATE
Bioconcentration Factor: No data available.
Octanol/Water Partition Coefficient: No data available
SECTION 13 DISPOSAL CONSIDERATIONS
Use material for its intended purpose or recycle if possible. Oil collection services are available for used oil
recycling or disposal. Place contaminated materials in containers and dispose of in a manner consistent
with applicable regulations. Contact your sales representative or local environmental or health authorities
for approved disposal or recycling methods.
SECTION 14 TRANSPORT INFORMATION
The description shown may not apply to all shipping situations. Consult 49CFR, or appropriate Dangerous
Goods Regulations, for additional description requirements (e.g., technical name) and mode-specific or
quantity-specific shipping requirements.
DOT Shipping Description: NOT REGULATED AS A HAZARDOUS MATERIAL UNDER 49 CFR
IMO/IMDG Shipping Description: NOT REGULATED AS DANGEROUS GOODS FOR TRANSPORT

UNDER THE IMDG CODE
ICAO/IATA Shipping Description: NOT REGULATED AS DANGEROUS GOODS FOR TRANSPORT

UNDER ICAO
Transport in bulk according to Annex II of MARPOL 73/78 and the IBC code:
Not applicable
SECTION 15 REGULATORY INFORMATION
EPCRA 311/312 CATEGORIES: 1. Immediate (Acute) Health Effects: NO

2. Delayed (Chronic) Health Effects: NO
3. Fire Hazard: NO
4. Sudden Release of Pressure Hazard: NO
_____________________________________________________________________

SDS : 32230
5. Reactivity Hazard: NO
REGULATORY LISTS SEARCHED:

01-1=IARC Group 1 03=EPCRA 313
01-2A=IARC Group 2A 04=CA Proposition 65
01-2B=IARC Group 2B 05=MA RTK
02=NTP Carcinogen 06=NJ RTK
07=PA RTK
No components of this material were found on the regulatory lists above.
CHEMICAL INVENTORIES:
All components comply with the following chemical inventory requirements: AICS (Australia), DSL
(Canada), EINECS (European Union), ENCS (Japan), IECSC (China), KECI (Korea), PICCS (Philippines),
TCSI (Taiwan), TSCA (United States).
NEW JERSEY RTK CLASSIFICATION:

Under the New Jersey Right-to-Know Act L. 1983 Chapter 315 N.J.S.A. 34:5A-1 et. seq., the product is to
be identified as follows: PETROLEUM OIL (Lubricating oil)
SECTION 16 OTHER INFORMATION
NFPA RATINGS: Health: 0 Flammability: 1 Reactivity: 0
HMIS RATINGS: Health: 0 Flammability: 1 Reactivity: 0

(0-Least, 1-Slight, 2-Moderate, 3-High, 4-Extreme, PPE:- Personal Protection Equipment Index
recommendation, *- Chronic Effect Indicator). These values are obtained using the guidelines or published
evaluations prepared by the National Fire Protection Association (NFPA) or the National Paint and Coating
Association (for HMIS ratings).
REVISION STATEMENT: This revision updates the following sections of this Safety Data Sheet: 1-16
ABBREVIATIONS THAT MAY HAVE BEEN USED IN THIS DOCUMENT:

TLV - Threshold Limit Value TWA - Time Weighted Average
STEL - Short-term Exposure Limit PEL - Permissible Exposure Limit
GHS - Globally Harmonized System CAS - Chemical Abstract Service Number
ACGIH - American Conference of Governmental IMO/IMDG - International Maritime Dangerous Goods
Industrial Hygienists Code
API - American Petroleum Institute SDS - Safety Data Sheet
_____________________________________________________________________

SDS : 32230
HMIS - Hazardous Materials Information System NFPA - National Fire Protection Association (USA)
DOT - Department of Transportation (USA) NTP - National Toxicology Program (USA)
IARC - International Agency for Research on OSHA - Occupational Safety and Health Administration
Cancer
NCEL - New Chemical Exposure Limit EPA - Environmental Protection Agency
SCBA - Self-Contained Breathing Apparatus
Prepared according to the 29 CFR 1910.1200 (2012) by Chevron Energy Technology Company, 6001
Bollinger Canyon Road, San Ramon, CA 94583.
The above information is based on the data of which we are aware and is believed to be correct as of
the date hereof. Since this information may be applied under conditions beyond our control and with
which we may be unfamiliar and since data made available subsequent to the date hereof may
suggest modifications of the information, we do not assume any responsibility for the results of its use.
This information is furnished upon condition that the person receiving it shall make his own
determination of the suitability of the material for his particular purpose.
_____________________________________________________________________

SDS : 32230
Shell Turbo Oil J 32
Version 1.0
Effective Date 02/23/2009
Material Safety Data Sheet
1. IDENTIFICATION OF THE SUBSTANCE/PREPARATION AND COMPANY/UNDERTAKING

Material Name : Shell Turbo Oil J 32
Uses : Turbine oil.
Product Code : 001B0634
Manufacturer/Supplier : Shell Marketing Egypt

Corner St. 254 & 206
Degla, Maadi 11742
Cairo
Egypt
Telephone : +202 25225600, +202 27557500

Fax : +202 25225601 +202 25225602
Emergency Telephone : +202 25225600

Number +202 25198801
2. COMPOSITION/INFORMATION ON INGREDIENTS
Preparation description : Highly refined mineral oils and additives.
Hazardous Components
Chemical CAS EINECS Symbol(s) R-phrase(s) Conc.
Identity
N-phenyl-1- 90-30-2 201-983-0 Xi, N R43; R50/53 0,10 - 0,50 %
naphthylamine
Additional Information : The highly refined mineral oil contains <3% (w/w) DMSO-
extract, according to IP346. Refer to chapter 16 for full text of
EC R-phrases.
3. HAZARDS IDENTIFICATION
EC Classification : Not classified as dangerous under EC criteria.
Health Hazards : Not expected to be a health hazard when used under normal
conditions. Prolonged or repeated skin contact without proper
cleaning can clog the pores of the skin resulting in disorders
such as oil acne/folliculitis. Used oil may contain harmful
impurities.
Signs and Symptoms : Oil acne/folliculitis signs and symptoms may include formation
of black pustules and spots on the skin of exposed areas.
Ingestion may result in nausea, vomiting and/or diarrhoea.
Safety Hazards : Not classified as flammable but will burn.
Environmental Hazards : Not classified as dangerous for the environment.
4. FIRST AID MEASURES

General Information : Not expected to be a health hazard when used under normal
conditions.
Inhalation : No treatment necessary under normal conditions of use. If
1/7
Print Date 10/27/2009
Version 1.0
symptoms persist, obtain medical advice.

Skin Contact : Remove contaminated clothing. Flush exposed area with water
and follow by washing with soap if available. If persistent
irritation occurs, obtain medical attention.
Eye Contact : Flush eye with copious quantities of water. If persistent
irritation occurs, obtain medical attention.
Ingestion : In general no treatment is necessary unless large quantities
are swallowed, however, get medical advice.
Advice to Physician : Treat symptomatically.
5. FIRE FIGHTING MEASURES

Clear fire area of all non-emergency personnel.
Specific Hazards : Hazardous combustion products may include: A complex

mixture of airborne solid and liquid particulates and gases
(smoke). Carbon monoxide. Unidentified organic and inorganic
compounds.
Suitable Extinguishing : Foam, water spray or fog. Dry chemical powder, carbon
Media dioxide, sand or earth may be used for small fires only.
Unsuitable Extinguishing : Do not use water in a jet.
Media
Protective Equipment for : Proper protective equipment including breathing apparatus
Firefighters must be worn when approaching a fire in a confined space.
6. ACCIDENTAL RELEASE MEASURES

Avoid contact with spilled or released material. For guidance on selection of personal protective
equipment see Chapter 8 of this Material Safety Data Sheet. See Chapter 13 for information on
disposal. Observe all relevant local and international regulations.
Protective measures : Avoid contact with skin and eyes. Use appropriate containment
to avoid environmental contamination. Prevent from spreading
or entering drains, ditches or rivers by using sand, earth, or
other appropriate barriers.
Clean Up Methods : Slippery when spilt. Avoid accidents, clean up immediately.
Prevent from spreading by making a barrier with sand, earth or
other containment material. Reclaim liquid directly or in an
absorbent. Soak up residue with an absorbent such as clay,
sand or other suitable material and dispose of properly.
Additional Advice : Local authorities should be advised if significant spillages
cannot be contained.
7. HANDLING AND STORAGE

General Precautions : Use local exhaust ventilation if there is risk of inhalation of
vapours, mists or aerosols. Properly dispose of any
contaminated rags or cleaning materials in order to prevent
fires. Use the information in this data sheet as input to a risk
assessment of local circumstances to help determine
appropriate controls for safe handling, storage and disposal of
this material.
Handling : Avoid prolonged or repeated contact with skin. Avoid inhaling
vapour and/or mists. When handling product in drums, safety
footwear should be worn and proper handling equipment
2/7
Version 1.0
should be used.
Storage : Keep container tightly closed and in a cool, well-ventilated
place. Use properly labelled and closeable containers. Storage
Temperature: 0 - 50 °C / 32 - 122 °F
Recommended Materials : For containers or container linings, use mild steel or high
density polyethylene.
Unsuitable Materials : PVC.
Additional Information : Polyethylene containers should not be exposed to high
temperatures because of possible risk of distortion.
8. EXPOSURE CONTROLS/PERSONAL PROTECTION
Occupational Exposure Limits
Material Source Type ppm mg/m3 Notation
Oil mist, ACGIH TWA 5 mg/m3

mineral [Mist.]
Oil mist, ACGIH STEL 10 mg/m3
mineral [Mist.]
Exposure Controls : The level of protection and types of controls necessary will vary
depending upon potential exposure conditions. Select controls
based on a risk assessment of local circumstances.
Appropriate measures include: Adequate ventilation to control
airborne concentrations. Where material is heated, sprayed or
mist formed, there is greater potential for airborne
concentrations to be generated.
Personal Protective : Personal protective equipment (PPE) should meet
Equipment recommended national standards. Check with PPE suppliers.
Respiratory Protection : No respiratory protection is ordinarily required under normal

conditions of use. In accordance with good industrial hygiene
practices, precautions should be taken to avoid breathing of
material. If engineering controls do not maintain airborne
concentrations to a level which is adequate to protect worker
health, select respiratory protection equipment suitable for the
specific conditions of use and meeting relevant legislation.
Check with respiratory protective equipment suppliers. Where
air-filtering respirators are suitable, select an appropriate
combination of mask and filter. Select a filter suitable for
combined particulate/organic gases and vapours [boiling point
>65°C(149 °F)].
Hand Protection : Where hand contact with the product may occur the use of
gloves approved to relevant standards (e.g. Europe: EN374,
US: F739) made from the following materials may provide
suitable chemical protection: PVC, neoprene or nitrile rubber
gloves. Suitability and durability of a glove is dependent on
usage, e.g. frequency and duration of contact, chemical
resistance of glove material, glove thickness, dexterity. Always
seek advice from glove suppliers. Contaminated gloves should
be replaced. Personal hygiene is a key element of effective
3/7
Version 1.0
hand care. Gloves must only be worn on clean hands. After

using gloves, hands should be washed and dried thoroughly.
Application of a non-perfumed moisturizer is recommended.
Eye Protection : Wear safety glasses or full face shield if splashes are likely to
occur.
Protective Clothing : Skin protection not ordinarily required beyond standard issue
work clothes.
Monitoring Methods : Monitoring of the concentration of substances in the breathing
zone of workers or in the general workplace may be required to
confirm compliance with an OEL and adequacy of exposure
controls. For some substances biological monitoring may also
be appropriate.
Environmental Exposure : Minimise release to the environment. An environmental
Controls assessment must be made to ensure compliance with local
environmental legislation.
9. PHYSICAL AND CHEMICAL PROPERTIES

Appearance : Amber. Liquid at room temperature.
Odour : Slight hydrocarbon.
pH : Not applicable.
Initial Boiling Point and : > 280 °C / 536 °F estimated value(s)
Boiling Range
Pour point : Typical -18 °C / 0 °F
Flash point : Typical 222 °C / 432 °F (COC)
Upper / lower Flammability : Typical 1 - 10 %(V)
or Explosion limits
Auto-ignition temperature : > 320 °C / 608 °F
Vapour pressure : < 0,5 Pa at 20 °C / 68 °F (estimated value(s))
Density : Typical 890 kg/m3 at 15 °C / 59 °F
Water solubility : Negligible.
n-octanol/water partition : > 6 (based on information on similar products)
coefficient (log Pow)
Kinematic viscosity : Typical 32 mm2/s at 40 °C / 104 °F
Vapour density (air=1) : > 1 (estimated value(s))
Evaporation rate (nBuAc=1) : Data not available
10. STABILITY AND REACTIVITY

Stability : Stable.
Conditions to Avoid : Extremes of temperature and direct sunlight.
Materials to Avoid : Strong oxidising agents.
Hazardous : Hazardous decomposition products are not expected to form
Decomposition Products during normal storage.
Hazardous : Data not available
Polymerisation
Sensitivity to Mechanical : Data not available
Impact
11. TOXICOLOGICAL INFORMATION

Basis for Assessment : Information given is based on data on the components and the
toxicology of similar products.
Acute Oral Toxicity : Expected to be of low toxicity: LD50 > 5000 mg/kg
Acute Dermal Toxicity : Expected to be of low toxicity: LD50 > 5000 mg/kg
Acute Inhalation Toxicity : Not considered to be an inhalation hazard under normal
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conditions of use.
Skin Irritation : Expected to be slightly irritating. Prolonged or repeated skin
contact without proper cleaning can clog the pores of the skin
resulting in disorders such as oil acne/folliculitis.
Eye Irritation : Expected to be slightly irritating.
Respiratory Irritation : Inhalation of vapours or mists may cause irritation.
Sensitisation : Not expected to be a skin sensitiser.
Repeated Dose Toxicity : Not expected to be a hazard.
Mutagenicity : Not considered a mutagenic hazard.
Carcinogenicity : Components are not known to be associated with carcinogenic
effects.
Reproductive and : Not expected to be a hazard.
Developmental Toxicity
Additional Information : Used oils may contain harmful impurities that have
accumulated during use. The concentration of such impurities
will depend on use and they may present risks to health and
the environment on disposal. ALL used oil should be handled
with caution and skin contact avoided as far as possible.
Continuous contact with used engine oils has caused skin
cancer in animal tests.
12. ECOLOGICAL INFORMATION

Ecotoxicological data have not been determined specifically for this product. Information given is
based on a knowledge of the components and the ecotoxicology of similar products.
Acute Toxicity : Poorly soluble mixture. May cause physical fouling of aquatic
organisms. Expected to be practically non toxic: LL/EL/IL50 >
100 mg/l (to aquatic organisms) (LL/EL50 expressed as the
nominal amount of product required to prepare aqueous test
extract).
Mobility : Liquid under most environmental conditions. Floats on water. If
it enters soil, it will adsorb to soil particles and will not be
mobile.
Persistence/degradability : Expected to be not readily biodegradable. Major constituents
are expected to be inherently biodegradable, but the product
contains components that may persist in the environment.
Bioaccumulation : Contains components with the potential to bioaccumulate.
Other Adverse Effects : Product is a mixture of non-volatile components, which are not
expected to be released to air in any significant quantities. Not
expected to have ozone depletion potential, photochemical
ozone creation potential or global warming potential.
13. DISPOSAL CONSIDERATIONS

Material Disposal : Recover or recycle if possible. It is the responsibility of the
waste generator to determine the toxicity and physical
properties of the material generated to determine the proper
waste classification and disposal methods in compliance with
applicable regulations. Do not dispose into the environment, in
drains or in water courses.
Container Disposal : Dispose in accordance with prevailing regulations, preferably to
a recognised collector or contractor. The competence of the
collector or contractor should be established beforehand.
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Local Legislation : Disposal should be in accordance with applicable regional,

national, and local laws and regulations.
14. TRANSPORT INFORMATION
Land (as per ADR classification): Not regulated

This material is not classified as dangerous under ADR regulations.
IMDG
This material is not classified as dangerous under IMDG regulations.
IATA (Country variations may apply)

This material is not classified as dangerous under IATA regulations.
15. REGULATORY INFORMATION
The regulatory information is not intended to be comprehensive. Other regulations may apply to this
material.
EC Classification : Not classified as dangerous under EC criteria.

EINECS : All components
listed or polymer
exempt.
TSCA : All components
listed.
Sensitiser not sufficient to : Contains N-phenyl-1-naphthylamine. May produce an allergic
classify reaction.
16. OTHER INFORMATION
R-phrase(s)
R43 May cause sensitisation by skin contact.

R50/53 Very toxic to aquatic organisms, may cause long-term adverse effects in the
aquatic environment.
MSDS Version Number : 1.0
MSDS Effective Date : 02/23/2009
MSDS Revisions : A vertical bar (|) in the left margin indicates an amendment
from the previous version.
MSDS Distribution : The information in this document should be made available to
all who may handle the product.
Disclaimer : This information is based on our current knowledge and is
intended to describe the product for the purposes of health,
safety and environmental requirements only. It should not
therefore be construed as guaranteeing any specific property
of the product.
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Appendix C. BACT Analysis Support
Appendix C Contents
RBLC Database - Natural Gas Fired Simple Cycle Turbine NOx C1-C2
RBLC Database - Natural Gas Fired Simple Cycle Turbine CO C3-C4
RBLC Database - Natural Gas Fired Simple Cycle Turbine VOC C5
RBLC Database - Natural Gas Fired Simple Cycle Turbine PM C6-C10
RBLC Database - Natural Gas Fired Simple Cycle Turbine GHG C-11
RBLC Database – Turbine MSS Emission Rate Comparisons C-12
RBLC Database – Natural Gas Fired Simple Cycle Turbine NOx (MSS) C-13-C14
RBLC Database – Natural Gas Fired Simple Cycle Turbine CO (MSS) C-15-C16
RBLC Database – Natural Gas Fired Simple Cycle Turbine VOC (MSS) C-17-C18
RBLC Database – Natural Gas Fired Simple Cycle Turbine PM (MSS) C-19-C20
RBLC Database – Natural Gas Fired in-line Fuel Gas Heater NOx C-21-C23
RBLC Database – Natural Gas Fired in-line Fuel Gas Heater CO C-24-C27
RBLC Database – Natural Gas Fired in-line Fuel Gas Heater VOC C-28-C-30
RBLC Database – Natural Gas Fired in-line Fuel Gas Heater PM C-31
RBLC Database – Natural Gas Fired in-line Fuel Gas Heater GHG C-32
RBLC Database – Diesel Firewater Pump NOx C-33-C35
RBLC Database – Diesel Firewater Pump CO C-36-C-38
RBLC Database – Diesel Firewater Pump VOC C-39-C40
RBLC Database – Diesel Firewater Pump PM C-41-C46
RBLC Database – Diesel Firewater Pump GHG C-47
RBLC Database – Component Leaks VOC C-48
RBLC Database – Component Leaks GHG C-49
RBLC Database – Natural Gas Fired Simple Cycle Turbine PM10 - LAER C-50-C51
RBLC Database – Natural Gas Fired in line Fuel Gas Heater PM10 - LAER C-52
RBLC Database – Diesel Firewater Pump PM10 - LAER C-53
TCEQ Gas Turbines Rated 20 MW and Greater Electric Output List C-54-C-59
Other recently issued TCEQ and other PSD Permits C-60-C-61
Natural Gas Fired Simple Cycle Turbine NOX ‐ RBLC Dataset
PROCCESS_ THROUGHPUT_U EMISSION_LIMIT_1_ EMISSION_LIMIT_1_AVG_
PROCESS_NAME TYPE PRIMARY_FUEL THROUGHPUT NIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1 UNIT TIME_CONDITION
BOSQUE POWER COMPANY IS
SEEKING TO AMEND THEIR
EXISTING PERMIT TO
CONSTRUCT DUCT FIRING BACT IS 9 PPMVD AT 15% O2 THROUGH THE USE OF
CAPABILITY TO THE HEAT DRY LOW‐NOX (DLN) COMBUSTERS WHEN THE
RECOVERY STEAM COMBUSTION TURBINE IS OPERATING IN THE
ELECTRICAL GENERATION 15.11 NATURAL GAS 170 MW GENERATORS (HRSGS) Nitrogen Oxides (NOx) SIMPLE CYCLE MODE. 2 PPMVD@15%O2 24‐HOUR 15% O2
Utilize water injection when combusting natural gas
GE LMS‐100 combustion turbines, simple cycle with or ULSD; Utilize selective catalytic reduction (SCR) 3‐HR ROLLING AVERAGE
water injection 15.11 natural gas 1690 MMBTU/H Nitrogen Oxides (NOx) with aqueous ammonia injection at all times except 2.5 PPMVD@15%O2 ON NG
TWO GENERAL ELECTRIC (GE) USE OF DRY LOW‐NOX COMBUSTOR TURBINE
FRAME 7EA COMBUSTION DESIGN (DLN1), USE OF FACILITY PROCESS FUEL GAS 3‐HOUR BLOCK AVERAGE,
2 COMBUSTION TURBINES 15.11 NATURAL GAS 130 MW TURBINES (CTS) WITH A Nitrogen Oxides (NOx) AND PIPELINE NATURAL GAS DURING NORMAL 2.5 PPMVD@15%O2 EXCLUDING SU/SD
EIGHT (8) IDENTICAL ROLLS SELECTIVE CATALYTIC REDUCTION SYSTEM (SCR)
COMBUSTION TURBINES, SIMPLE CYCLE , ROLLS ROYCE TRENT 60WLE (64 MW) AND WET LOW‐EMISSION (WLE) COMBUSTORS
ROYCE, 8 15.11 NATURAL GAS 603 MMBTU/H SIMPLE CYCLE COMBUSTION Nitrogen Oxides (NOx) SUBJECT TO LAER 2.5 PPMVD@15%O2
Throughput <= 8.94xE6
MMBtu/year (HHV) combined 3‐HR ROLLING AVERAGE
SIMPLE CYCLE TURBINE 15.11 Natural Gas 8940000 MMBtu/year (HHVfor all six gas turbines. The 6 Nitrogen Oxides (NOx) SCR and Use of Clean Burning Fuel: Natural gas 2.5 PPMVD@15%O2 BASED ON 1‐HR BLOCK
THE PROCESS CONSISTS OF THE TURBINE WILL UTILIZE WATER INJECTION AND
ONE NEW TRENT 60 SIMPLE SELECTIVE CATALYTIC REDUCTION (SCR) TO 3HR ROLLING AVERAGE
SIMPLE CYCLE (NO WASTE HEAT RECOVERY)(>25 MW) 15.11 NATURAL GAS 5000 MMFT3/YR CYCLE COMBUSTION TURBINE. Nitrogen Oxides (NOx) CONTROL NOX EMISSION AND USE CLEAN FUELS 2.5 PPMVD@15%O2 BASED ON 1‐HR BLOCK
The Siemens/Rolls Royce Trent
60 wet low emissions (WLE) Selective Catalytic Reduction, water injection, use of 3 H ROLLING AV BASED ON
Simple Cycle Stationary Turbines firing Natural gas 15.11 Natural Gas 2143980 MMBTU/YR combustion turbine generators Nitrogen Oxides (NOx) natural gas a low NOx emitting fuel 2.5 PPMVD@15%O2 ONE H BLOCK AV
The heat input is for a single 4 HOUR ROLLING AVERAGE
Natural Gas Fired Simple Cycle Turbines 15.11 Natural gas 412 MMBTU/H unit. Nitrogen Oxides (NOx) SCR 5 PPMVD@15%O2 EXCEPT STARTUP
4 HR. ROLLING AVERAGE
Natural gas‐fired turbines 15.11 Natural gas 451 MMBTU/H Rating is for each turbine. Nitrogen Oxides (NOx) Water injection plus SCR 5 PPMVD@15%O2 EXCEPT FOR STARTUP
THE PROCESS USES FUEL OIL 3 HOUR
SIMPLE CYCLE COMBUSTION TURBINE ‐ ELECTRIC FOR BACKUP AT THE RATE OF DRY LOW NOX BURNERS (FIRING NATURAL GAS). AVERAGE/CONDITION
GENERATING PLANT 15.11 NATURAL GASE 1530 MW 2129 MMBUT/H Nitrogen Oxides (NOx) WATER INJECTION (FIRING FUEL OIL). 9 PPMVD@15%O2 3.3.23
dry low NOx burners and fire only pipeline natural 24‐HR ROLLING AVE,
GE LM6000PC SPRINT Simple cycle combustion turbine 15.11 Pipeline quality natu 405.3 MMBTU/hr Nitrogen Dioxide (NO2) gas 9 PPMVD@15%O2 CORRECTED TO 15% O2
dry low NOx burners and fire only pipeline natural 24‐HR ROLLING AVE,
GE 7FA Simple Cycle Combustion Turbine 15.11 Pipeline quality natu 1780 MMBTU/HR Nitrogen Oxides (NOx) gas 9 PPMVD@15%O2 CORRECTED TO 15% O2
Dry Low NOx Combustor Design, Good Combustion
Simple Cycle Combustion Turbines (SCCT1 to SCCT3) 15.11 Natural Gas 927 MM BTU/h Nitrogen Oxides (NOx) Practices, and Natural Gas Combustion. 9 PPMVD@15%O2 30 DAY ROLLING AVERAGE
Throughput could vary slightly Required to employ dry low‐NOx technology and
(+/‐ 120 MMBtu/hr) depending wet injection. Water injection must be used when 24‐HR BLOCK AVG, BY
Five 200‐MW combustion turbines 15.11 Natural gas 2000 MMBtu/hr (appro on final selection of turbine Nitrogen Oxides (NOx) firing ULSD. 9 PPMVD@15%O2 CEMS (NAT GAS)
BACKUP FUEL: ULTRA LOW
TWO SIMPLE CYCLE COMBUSTION TURBINE ‐ MODEL SULFUR DIESEL WITH A FIRING NATURAL GAS AND USING DLN 2.6 24‐HR BLOCK AVG BY
7FA 15.11 NATURAL GAS 170 MW MAXIMUM SULFUR CONTENT Nitrogen Oxides (NOx) COMBUSTORS TO MINIMIZE NOX EMISSSIONS. 9 PPMVD@15%O2 CEMS
Turbine is a GE Model PG 7121 4 H.R.A. WHEN > 50MWE
Combustion Turbine 15.11 Natural gas 986 MMBTU/H (7EA) used as a peaking unit. Nitrogen Oxides (NOx) Dry low‐NOx combustion (DLN) 9 PPMVD@15%O2 AND > 0 DEGREES F
CTG01 NO ‐ Simple‐Cycle Combustion Turbine 1 Normal operations are based
(Normal Operations) [EQT0017] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hrs/yr Nitrogen Oxides (NOx) Pipeline quality natural gas & dry‐low‐NOX burners 9 PPMVD@15%O2 30‐DAY ROLLING AVERAGE
CTG02 NO ‐ Simple‐Cycle Combustion Turbine 2 Normal operations are based
(Normal Operations) [EQT0018] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hours per year Nitrogen Oxides (NOx) Pipeline quality natural gas & dry‐low‐NOX burners 9 PPMVD@15%O2 30‐DAY ROLLING AVERAGE
Five simple cycle GE 7F.05
turbines. Max of 3390 hours Dry‐low‐NOx combustion system. Wet injection
Five 200‐MW combustion turbines 15.11 Natural gas 2100 MMBtu/hr (appro per year per turbine. Of the Nitrogen Oxides (NOx) when firing ULSD. 9 PPMVD@15%O2 24‐HR BLOCK AVERAGE
Gas turbines (9 units) 15.11 natural gas 1069 mm btu/hr Nitrogen Oxides (NOx) good combustion practices and dry low nox burners 15 PPMVD@15%O2 @15%O2
C1
Natural Gas Fired Simple Cycle Turbine NOX ‐ RBLC Dataset
Dry Low NOx Burners Type K & Good Combustion
Normal Mode (without Power Augmentation) 15.11 natural gas 0 Nitrogen Dioxide (NO2) Practice 21 PPMVD@15%O2 HOUR
24‐HR ROLLING AVE;
GE LM6000PC SPRINT Simple cycle combustion turbine 15.11 Pipeline quality natu 405.3 MMBTU/hr Nitrogen Oxides (NOx) water injection 25 PPMVD@15%O2 CORRECTED TO 15% O
AT 15% O2 FOR NATURAL
PRATT & TWIN‐PAC SIMPLE CYCLE TURBINES 15.11 NATURAL GAS 270.9 MMBTU/H NO. 2 DIESEL OIL BACKUP FUEL Nitrogen Oxides (NOx) WATER INJECTION 25 PPMVD@15%O2 GAS
Dry Low NOX burners and good combustion
Gas Turbines (8 units) 15.11 natural gas 333 mm btu/hr Nitrogen Oxides (NOx) practices 25 PPMVD@15%O2 @15 %O2
Simple Cycle Refrigeration Compressor Turbines (16) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 Nitrogen Oxides (NOx) water injection 22.94 LB/HR HOURLY MAXIMUM
GE LMS100PA, natural gas
fired, simple cycle, combustion 1‐HR AVE / STARTUP AND
Turbines ‐ two simple cycle gas 15.11 natural gas 799.7 MMBTU/H each turbine. Nitrogen Oxides (NOx) SCR and dry low NOx burners 23 LB/HR SHUTDOWN
Simple Cycle Generation Turbines (2) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 Nitrogen Oxides (NOx) water injection 28.68 LB/HR HOURLY MAXIMUM
CTG01 SUSD ‐ Simple‐Cycle Combustion Turbine 1
(Startup/Shutdown/ Maintenance/Tuning/Runback)
[EQT0019] 15.11 Natural Gas 2201 MM BTU/hR Limited to 600 hr/yr Nitrogen Oxides (NOx) Pipeline quality natural gas & dry‐low‐NOX burners 86.38 LB/HR HOURLY MAXIMUM
(Startup/Shutdown/ Maintenance/Tuning/Runback)
[EQT0020] 15.11 Natural Gas 2201 MM BTU/hr limited to 600 hr/yr Nitrogen Oxides (NOx) Pipeline quality natural gas & dry‐low‐NOX burners 86.38 LB/HR HOURLY MAXIMUM
Hours per year for all 4
Turbines (4), simple cycle, natural gas 15.11 NATURAL GAS 15020 H/YR turbines Nitrogen Oxides (NOx) dry low NOx burners 161 LB/HR EACH TURBINE
Commissioning is a one‐time
CTG01 CO ‐ Simple‐Cycle Combustion Turbine 1 event which occurs after
(Commissioning) [SCN0005] 15.11 Natural Gas 2201 MM BTU/hr construction and is not Nitrogen Oxides (NOx) Pipeline quality natural gas & dry‐low‐NOX burners 240 LB/HR HOURLY MAXIMUM
CTG02 CO ‐ Simple‐Cycle Combustion Turbine 2 event which occurs after
(Commissioning) [SCN0006] 15.11 natural gas 2201 MM BTU/hr construction and is not Nitrogen Oxides (NOx) Pipeline quality natural gas & dry‐low‐NOX burners 240 LB/HR HOURLY MAXIMUM
SIMPLE CYCLE, NATURAL GAS FIRED COMBUSTION
TURBINES 15.11 NATURAL GAS 80 MW Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 250 LB/HR EACH TURBINE
C2
Natural Gas Fired Simple Cycle Turbine CO ‐ RBLC Dataset
Throughput could vary slightly
MMBtu/hr (+/‐ 120 MMBtu/hr) depending
Five 200‐MW combustion turbines 15.11 Natural gas 2000 (approx) on final selection of turbine Carbon Monoxide Good combustion practices 4 PPMVD@15%O2
MMBtu/hr turbines. Max of 3390 hours NAT GAS, THREE 1‐HR
Five 200‐MW combustion turbines 15.11 Natural gas 2100 (approx) per year per turbine. Of the Carbon Monoxide Good combustion minimizes CO formation 4 PPMVD@15%O2 RUNS
MMBtu/year MMBtu/year (HHV) combined 3‐HR ROLLING AVERAGE
SIMPLE CYCLE TURBINE 15.11 Natural Gas 8940000 (HHV) for all six gas turbines. The 6 Carbon Monoxide Oxidation Catalyst, Good combustion practices 5 PPMVD@15%O2 BASED ON 1‐HR BLOCK
EIGHT (8) IDENTICAL ROLLS
COMBUSTION TURBINES, SIMPLE CYCLE , ROLLS ROYCE TRENT 60WLE (64 MW) CO OXIDATION CATALYST AND CLEAN BURNING
ROYCE, 8 15.11 NATURAL GAS 603 MMBTU/H SIMPLE CYCLE COMBUSTION Carbon Monoxide FUELS 5 PPMVD@15%O2
THE PROCESS CONSISTS OF THE TURBINE WILL UTILIZE A CATALYTIC OXIDIZER
ONE NEW TRENT 60 SIMPLE TO CONTROL CO EMISSION, IN ADDITION TO USING 3HR ROLLING AVERAGE
SIMPLE CYCLE (NO WASTE HEAT RECOVERY)(>25 MW) 15.11 NATURAL GAS 5000 MMFT3/YR CYCLE COMBUSTION TURBINE. Carbon Monoxide CLEAN BURNING FUELS, NATURAL GAS AND ULTRA 5 PPMVD@15%O2 BASED ON 1‐HR BLOCK
60 wet low emissions (WLE) Add‐on control is CO Oxidation Catalyst, and use of 3 H ROLLING AV BASED ON
Simple Cycle Stationary Turbines firing Natural gas 15.11 Natural Gas 2143980 MMBTU/YR combustion turbine generators Carbon Monoxide natural gas as fuel for pollution prevention 5 PPMVD@15%O2 ONE H BLOCK AV
GE LMS‐100 combustion turbines, simple cycle with Oxidation catalyst; Limit the time in startup or 3‐HR ROLLING AVERAGE

water injection 15.11 natural gas 1690 MMBTU/H Carbon Monoxide shutdown. 6 PPMVD@15%O2 ON NG
8 HR. ROLLING
AVERAGE/EXCEPT
Natural gas‐fired turbines 15.11 Natural gas 451 MMBTU/H Rating is for each turbine. Carbon Monoxide Catalytic oxidation system 6 PPMVD@15%O2 STARTUP
The heat input is for a single 8‐HOUR ROLLING
Natural Gas Fired Simple Cycle Turbines 15.11 Natural gas 412 MMBTU/H unit. Carbon Monoxide Oxidation Catalyst 6 PPMVD@15%O2 AVERAGE EXCEPT STARTUP
CTG02 NO ‐ Simple‐Cycle Combustion Turbine 2 Normal operations are based Good combustion practices & use of pipeline quality

(Normal Operations) [EQT0018] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hours per year Carbon Monoxide natural gas 6 PPMVD@15%O2 ANNUAL AVERAGE
CTG01 NO ‐ Simple‐Cycle Combustion Turbine 1 Normal operations are based Good combustion practices & use of pipeline quality

(Normal Operations) [EQT0017] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hrs/yr Carbon Monoxide natural gas 6 PPMVD@15%O2 ANNUAL AVERAGE
TWO SIMPLE CYCLE COMBUSTION TURBINE ‐ MODEL SULFUR DIESEL WITH A
7FA 15.11 NATURAL GAS 170 MW MAXIMUM SULFUR CONTENT Carbon Monoxide 6.5 PPMVD@15%O2
THE PROCESS USES FUEL OIL 3‐HOUR
SIMPLE CYCLE COMBUSTION TURBINE ‐ ELECTRIC FOR BACKUP AT THE RATE OF AVERAGE/CONDITION
GENERATING PLANT 15.11 NATURAL GASE 1530 MW 2129 MMBUT/H Carbon Monoxide GOOD COMBUSTION PRACTICES 9 PPMVD@15%O2 3.3.24
BOSQUE POWER COMPANY IS BACT IS THE USE OF GOOD COMBUSTION
SEEKING TO AMEND THEIR PRACTICES TO MINIMIZE THE PRODUCTS OF
ELECTRICAL GENERATION 15.11 NATURAL GAS 170 MW EXISTING PERMIT TO Carbon Monoxide INCOMPLETE COMBUSTION AND ACHIEVE 9 PPMVD 9 PPMVD@15%O2 3 HOUR @ 15% O2
good combustion practices and fueled by natural
Gas turbines (9 units) 15.11 natural gas 1069 mm btu/hr Carbon Monoxide gas 15 PPMVD@15%O2 @15%O2
Proper Equipment Design, Proper Operation, and
Simple Cycle Combustion Turbines (SCCT1 to SCCT3) 15.11 Natural Gas 927 MM BTU/h Carbon Monoxide Good Combustion Practices. 25 PPMVD@15%O2 30 DAY ROLLING AVERAGE
Turbine is a GE Model PG 7121
Combustion Turbine 15.11 Natural gas 986 MMBTU/H (7EA) used as a peaking unit. Carbon Monoxide Good Combustion 25 PPMVD@15%O2 4 H.R.A./WHEN > 50 MWE
3 liquefied natural gas trains
consisting of a total of (12) GE @15% O2, 4 HOUR
Refrigeration compressor turbines 15.11 natural gas 40000 hp LM2500+ DLE turbines drive Carbon Monoxide dry low emission combustors 29 PPMVD@15%O2 ROLLING AVERAGE
good combustion practices and fueled by natural THREE ONE‐HOUR TEST
Gas Turbines (8 units) 15.11 natural gas 333 mm btu/hr Carbon Monoxide gas 0.062 LB/MMBTU AVERAGE
NATURAL GAS AS PRIMARY FUEL; GOOD
PRATT & TWIN‐PAC SIMPLE CYCLE TURBINES 15.11 NATURAL GAS 270.9 MMBTU/H NO. 2 DIESEL OIL BACKUP FUEL Carbon Monoxide COMBUSTION PRACTICES 0.2 LB/MMBTU NATURAL GAS
Good combustion practices and fueled by natural
Simple Cycle Generation Turbines (2) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 Carbon Monoxide gas 17.46 LB/HR HOURLY MAXIMUM
Pipeline quality
GE 7FA Simple Cycle Combustion Turbine 15.11 natural gas 1780 MMBTU/HR Carbon Monoxide utilize efficient combustion/design technology 39 LB/HR AT FULL LOAD
C3
Natural Gas Fired Simple Cycle Turbine CO ‐ RBLC Dataset
Good combustion practices and fueled by natural
Simple Cycle Refrigeration Compressor Turbines (16) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 Carbon Monoxide gas 43.6 LB/HR HOURLY MAXIMUM
fired, simple cycle, combustion 1‐HR AVE / STARTUP AND
Turbines ‐ two simple cycle gas 15.11 natural gas 799.7 MMBTU/H each turbine. Carbon Monoxide Catalytic Oxidation. 55 LB/HR SHUTDOWN
Pipeline quality FULL LOAD, AMBIENT
GE LM6000PC SPRINT Simple cycle combustion turbine 15.11 natural gas 405.3 MMBTU/hr Carbon Monoxide utilize efficient combustion/design technology 63.8 LB/HR TEMP < OR = TO 54 F
Good Combustion Practices as defined in the
Normal Mode (without Power Augmentation) 15.11 natural gas 0 Carbon Monoxide permit. 77.2 LB/HR HOURLY
Hours per year for all 4
Turbines (4), simple cycle, natural gas 15.11 NATURAL GAS 15020 H/YR turbines Carbon Monoxide efficient combution technology 301 LB/HR EACH TURBINE
SIMPLE CYCLE, NATURAL GAS FIRED COMBUSTION
TURBINES 15.11 NATURAL GAS 80 MW Carbon Monoxide GOOD COMBUSTION PRACTICES 525 LB/HR EACH TURBINE
(Startup/Shutdown/ Maintenance/Tuning/Runback) Good combustion practices & use of pipeline quality
[EQT0019] 15.11 Natural Gas 2201 MM BTU/hR Limited to 600 hr/yr Carbon Monoxide natural gas 800.08 LB/HR HOURLY MAXIMUM
(Startup/Shutdown/ Maintenance/Tuning/Runback) Good combustion practices & use of pipeline quality
[EQT0020] 15.11 Natural Gas 2201 MM BTU/hr limited to 600 hr/yr Carbon Monoxide natural gas 800.08 LB/HR HOURLY MAXIMUM
CTG01 CO ‐ Simple‐Cycle Combustion Turbine 1 event which occurs after Good combustion practices & use of pipeline quality
(Commissioning) [SCN0005] 15.11 Natural Gas 2201 MM BTU/hr construction and is not Carbon Monoxide natural gas 2000 LB/HR HOURLY MAXIMUM
CTG02 CO ‐ Simple‐Cycle Combustion Turbine 2 event which occurs after Good combustion practices & use of pipeline quality
(Commissioning) [SCN0006] 15.11 natural gas 2201 MM BTU/hr construction and is not Carbon Monoxide natural gas 2000 LB/HR HOURLY MAXIMUM
C4
Natural Gas Fired Simple Cycle Turbine VOC ‐ RBLC Dataset
Volatile Organic Proper Equipment Design, Proper Operation, and
Simple Cycle Combustion Turbines (SCCT1 to SCCT3) 15.11 Natural Gas 927 MM BTU/h Compounds (VOC) Good Combustion Practices. 1.4 PPMVD@15%O2 3 HOUR AVERAGE
Volatile Organic good combustion practices and fueled by natural
Gas turbines (9 units) 15.11 natural gas 1069 mm btu/hr Compounds (VOC) gas 1.6 PPMVD@15%O2 @15%O2
60 wet low emissions (WLE) Volatile Organic Add‐on VOC control is Oxidation Catalyst, and use of 3 H ROLLING AV BASED ON
Simple Cycle Stationary Turbines firing Natural gas 15.11 Natural Gas 2143980 MMBTU/YR combustion turbine generators Compounds (VOC) natural gas as fuel for pollution prevention 2 PPMVD@15%O2 ONE H BLOCK AV
NATURAL GAS FIRED, OPEN‐
SIMPLE CYCLE COMBUSTION Volatile Organic GOOD COMBUSTION PRACTICES AND PROPER
TWO (2) NATURAL GAS FIRED COMBUSTION TURBINES 16.21 NATURAL GAS 283 MMBTU/H, EACH TURBINES WITH HEAT Compounds (VOC) DESIGN 2.5 PPMVD@15%O2 1‐HR AVERAGE
SIMPLE CYCLE COMBUSTION Volatile Organic GOOD COMBUSTION PRACTICES AND PROPER
TWO (2) NATURAL GAS FIRED COMBUSTION TURBINES 16.21 NATURAL GAS 283 MMBTU/H, EACH TURBINES WITH HEAT Compounds (VOC) DESIGN 2.5 PPMVD@15%O2 1‐HR AVERAGE
BOSQUE POWER COMPANY IS BACT IS THE USE OF GOOD COMBUSTION
SEEKING TO AMEND THEIR Volatile Organic PRACTICES TO MINIMIZE THE PRODUCTS OF
ELECTRICAL GENERATION 15.11 NATURAL GAS 170 MW EXISTING PERMIT TO Compounds (VOC) INCOMPLETE COMBUSTION OF THE NATURAL GAS 4 PPMVD@15%O2 3 HOUR
MMBtu/year MMBtu/year (HHV) combined Volatile Organic Oxidation Catalyst and good combustion practices,
SIMPLE CYCLE TURBINE 15.11 Natural Gas 8940000 (HHV) for all six gas turbines. The 6 Compounds (VOC) use of natural gas. 4 PPMVD@15%O2 AVERAGE OF THREE TESTS
THE PROCESS USES FUEL OIL 3 HOUR
SIMPLE CYCLE COMBUSTION TURBINE ‐ ELECTRIC FOR BACKUP AT THE RATE OF Volatile Organic AVERAGE/CONTITION
GENERATING PLANT 15.11 NATURAL GASE 1530 MW 2129 MMBUT/H Compounds (VOC) GOOD COMBUSTION PRACTICES 5 PPMVD@15%O2 3.3.24
consisting of a total of (12) GE Volatile Organic
Refrigeration compressor turbines 15.11 natural gas 40000 hp LM2500+ DLE turbines drive Compounds (VOC) good combustion practices 0.6 LB/HR 1 HOUR
consisting of a total of (6) GE Volatile Organic
Refrigeration compressor turbines 15.21 natural gas 40000 hp LM2500+ DLE turbines that Compounds (VOC) good combustion practices 0.6 LB/HR 1 HOUR
Volatile Organic Good combustion practices and fueled by natural
Simple Cycle Refrigeration Compressor Turbines (16) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 Compounds (VOC) gas 0.66 LB/HR HOURLY MAXIMUM
Volatile Organic Good combustion practices and fueled by natural
Simple Cycle Generation Turbines (2) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 Compounds (VOC) gas 0.66 LB/HR HOURLY MAXIMUM
EIGHT (8) IDENTICAL ROLLS CO OXIDATION CATALYST AND POLLUTION
COMBUSTION TURBINES, SIMPLE CYCLE , ROLLS ROYCE TRENT 60WLE (64 MW) Volatile Organic PREVENTION, BURNING CLEAN FUELS, NATURAL
ROYCE, 8 15.11 NATURAL GAS 603 MMBTU/H SIMPLE CYCLE COMBUSTION Compounds (VOC) GAS AND ULTRA LOW SULFUR DISTILLATE OIL WITH 1.93 LB/HR
Pipeline quality Volatile Organic
GE 7FA Simple Cycle Combustion Turbine 15.11 natural gas 1780 MMBTU/HR Compounds (VOC) will utilize efficient combustion/design technology 3.2 LB/HR AT FULL LOAD
Throughput could vary slightly
MMBtu/hr (+/‐ 120 MMBtu/hr) depending Volatile Organic THREE ONE‐HR RUNS
Five 200‐MW combustion turbines 15.11 Natural gas 2000 (approx) on final selection of turbine Compounds (VOC) Good combustion practice 3.77 LB/HR (NATURAL GAS)
Hours per year for all 4 Volatile Organic
Turbines (4), simple cycle, natural gas 15.11 NATURAL GAS 15020 H/YR turbines Compounds (VOC) 4 LB/HR EACH TURBINE
Pipeline quality Volatile Organic
GE LM6000PC SPRINT Simple cycle combustion turbine 15.11 natural gas 405.3 MMBTU/hr Compounds (VOC) utilize efficient combustion/design technology 5.8 LB/HR AT FULL LOAD
SIMPLE CYCLE, NATURAL GAS FIRED COMBUSTION Volatile Organic
TURBINES 15.11 NATURAL GAS 80 MW Compounds (VOC) GOOD COMBUSTION PRACTICES 17.6 LB/HR EACH TURBINE
C5
Natural Gas Fired Simple Cycle Turbine PM ‐ RBLC Dataset
Three simple cycle combustion
turbine generators (CTG). Each Particulate matter, total AT LOADS OF 80% OR
COMBUSTION TURBINES (NORMAL OPERATION) 15.11 NATURAL GAS 300 MW CTG rated at 100 MW (nominal (TPM) PUC‐QUALITY NATURAL GAS 0.0065 LB/MMBTU (HHV) HIGHER
turbine generators (CTG). Each Particulate matter, total < AT LOADS OF 80% OR
COMBUSTION TURBINES (NORMAL OPERATION) 15.11 NATURAL GAS 300 MW CTG rated at 100 MW (nominal 10 µ (TPM10) PUC‐QUALITY NATURAL GAS 0.0065 LB/MMBTU (HHV) HIGHER
turbine generators (CTG). Each Particulate matter, AT LOADS OF 80% OR
COMBUSTION TURBINES (NORMAL OPERATION) 15.11 NATURAL GAS 300 MW CTG rated at 100 MW (nominal filterable < 2.5 µ (FPM2.5) PUC‐QUALITY NATURAL GAS 0.0065 LB/MMBTU (HHV) HIGHER
SIMPLE CYCLE COMBUSTION Particulate matter, GOOD COMBUSTION PRACTICES AND PROPER
TWO (2) NATURAL GAS FIRED COMBUSTION TURBINES 16.21 NATURAL GAS 283 MMBTU/H, EACH TURBINES WITH HEAT filterable (FPM) DESIGN 0.0019 LB/MMBTU 3‐HR AVERAGE
SIMPLE CYCLE COMBUSTION Particulate matter, GOOD COMBUSTION PRACTICES AND PROPER
TWO (2) NATURAL GAS FIRED COMBUSTION TURBINES 16.21 NATURAL GAS 283 MMBTU/H, EACH TURBINES WITH HEAT filterable (FPM) DESIGN 0.0019 LB/MMBTU 3‐HR AVERAGE
Particulate matter,
Turbine ‐ natural gas 15.11 natural gas 107 MW filterable (FPM) Baghouse with leak detection system. 0.002 LB/MMBTU 1 H
TWO GENERAL ELECTRIC (GE) EXCLUSIVE USE OF FACILITY PROCESS FUEL GAS OR
FRAME 7EA COMBUSTION Particulate matter, PIPELINE QUALITY NATURAL GAS AND GOOD
2 COMBUSTION TURBINES 15.11 NATURAL GAS 130 MW TURBINES (CTS) WITH A filterable (FPM) COMBUSTION PRACTICES 0.0033 LB/MMBTU 3‐HOUR BLOCK AVERAGE
Two simple cycle combustion
turbines used for peaking Particulate matter,
Two Simple Cycle Combustion Turbines 15.11 Natural Gas 190 MW purposes and fired primarily filterable (FPM) turbine design and good combustion practices 0.0038 LB/MMBTU 3‐HOUR BLOCK AVERAGE
Each combustion turbine rated
at 214 MW, with a maximum Particulate matter,
Combustion Turbines (GEN1 and GEN2) 15.11 Natural Gas 2217 MMBtu/hr heat input rate of 2,217 filterable (FPM) Clean fuel and good combustion practices 0.0048 LB/MMBTU TEST AVERAGE
at 214 MW, with a maximum Particulate matter, total <
Combustion Turbines (GEN1 and GEN2) 15.11 Natural Gas 2217 MMBtu/hr heat input rate of 2,217 10 µ (TPM10) Clean fuel and good combustion practices 0.0048 LB/MMBTU TEST AVERAGE
Combustion Turbines (GEN1 and GEN2) 15.11 Natural Gas 2217 MMBtu/hr heat input rate of 2,217 2.5 µ (TPM2.5) Clean fuel and good combustion practices 0.0048 LB/MMBTU TEST AVERAGE
turbines used for peaking Particulate matter, total <
Two Simple Cycle Combustion Turbines 15.11 Natural Gas 190 MW purposes and fired primarily 10 µ (TPM10) turbine design and good combustion practices 0.005 LB/MMBTU 3‐HOUR BLOCK AVERAGE
Two Simple Cycle Combustion Turbines 15.11 Natural Gas 190 MW purposes and fired primarily 2.5 µ (TPM2.5) turbine design and good combustion practices 0.005 LB/MMBTU 3‐HOUR BLOCK AVERAGE
Particulate matter, good combustion practiced and pipeline quality
Turbines and duct burners 15.11 natural gas 228 mw filterable (FPM) natural gas 0.005 LB/MMBTU 1 H
Particulate matter, USE NATURAL GAS AS PRIMARY FUEL; GOOD 3‐HR AVG FOR NATURAL

PRATT & TWIN‐PAC SIMPLE CYCLE TURBINES 15.11 NATURAL GAS 270.9 MMBTU/H NO. 2 DIESEL OIL BACKUP FUEL filterable < 10 µ (FPM10) COMBUSTION PRACTICES 0.0066 LB/MMBTU GAS
Particulate matter, total < NATURAL GAS PRIMARY FUEL; GOOD COMBUSTION 3‐HR AVG FOR NATURAL

PRATT & TWIN‐PAC SIMPLE CYCLE TURBINES 15.11 NATURAL GAS 270.9 MMBTU/H NO. 2 DIESEL OIL BACKUP FUEL 2.5 µ (TPM2.5) PRACTICES 0.0066 LB/MMBTU GAS
Three (3) General Electric
Combustion turbine wih duct burner and heat Three 40.6 MW Frame 6B NG fired turbine with Particulate matter, total <
recovery steam generator 15.11 Natural Gas 0 turbines duct burners and heat 10 µ (TPM10) 0.0066 LB/MMBTU
recovery steam generator 15.11 Natural Gas 0 turbines duct burners and heat 2.5 µ (TPM2.5) 0.0066 LB/MMBTU
FRAME 7EA COMBUSTION Particulate matter, total < PIPELINE QUALITY NATURAL GAS AND GOOD 3 STACK TEST RUN
2 COMBUSTION TURBINES 15.11 NATURAL GAS 130 MW TURBINES (CTS) WITH A 10 µ (TPM10) COMBUSTION PRACTICES 0.007 LB/MMBTU AVERAGE, EXCEPT SU/SD
2 COMBUSTION TURBINES 15.11 NATURAL GAS 130 MW TURBINES (CTS) WITH A 2.5 µ (TPM2.5) COMBUSTION PRACTICES 0.007 LB/MMBTU AVERAGE, EXCEPT SU/SD
Particulate matter, total < good combustion practices and fueled by natural THREE ONE‐HOUR TEST

Gas turbines (9 units) 15.11 natural gas 1069 mm btu/hr 10 µ (TPM10) gas 0.0076 LB/MMBTU AVERAGE

Gas turbines (9 units) 15.11 natural gas 1069 mm btu/hr 2.5 µ (TPM2.5) gas 0.0076 LB/MMBTU AVERAGE
C6
SIMPLE CYCLE COMBUSTION Particulate matter, total < GOOD COMBUSTION PRACTICES AND PROPER
TWO (2) NATURAL GAS FIRED COMBUSTION TURBINES 16.21 NATURAL GAS 283 MMBTU/H, EACH TURBINES WITH HEAT 10 µ (TPM10) DESIGN 0.0076 LB/MMBTU 3‐HR AVERAGE
TWO (2) NATURAL GAS FIRED COMBUSTION TURBINES 16.21 NATURAL GAS 283 MMBTU/H, EACH TURBINES WITH HEAT 2.5 µ (TPM2.5) DESIGN 0.0076 LB/MMBTU 3‐HR AVERAGE
TWO (2) NATURAL GAS FIRED COMBUSTION TURBINES 16.21 NATURAL GAS 283 MMBTU/H, EACH TURBINES WITH HEAT 10 µ (TPM10) DESIGN 0.0076 LB/MMBTU 3‐HR AVERAGE
TWO (2) NATURAL GAS FIRED COMBUSTION TURBINES 16.21 NATURAL GAS 283 MMBTU/H, EACH TURBINES WITH HEAT 2.5 µ (TPM2.5) DESIGN 0.0076 LB/MMBTU 3‐HR AVERAGE
Two CT with HRSGs with duct
Combined cycle combustion turnbine with HRSG and Natural gas burner Max fuel input for CTs Particulate matter, total < THREE(3) HOUR ROLLING
duct firing 15.11 pipeline quality 849 MW and HRSGs 6,714 mmBtu/hr 10 µ (TPM10) Combust only pipeline quality natural gas 0.0088 LB/MMBTU AVERAGE
Combined cycle combustion turnbine with HRSG and Natural gas burner Max fuel input for CTs Particulate matter, total < THREE HOUR ROLLING
duct firing 15.11 pipeline quality 849 MW and HRSGs 6,714 mmBtu/hr 2.5 µ (TPM2.5) Combust pipeline quality natural gas only 0.0088 LB/MMBTU AVERAGE
Combined cycle combustion turnbine with HRSG and Natural gas burner Max fuel input for CTs Particulate matter, total THREE HOUR ROLLING
duct firing 15.11 pipeline quality 849 MW and HRSGs 6,714 mmBtu/hr (TPM) Combust only pipeline quality natural gas 0.0088 LB/MMBTU AVERAGE
BOSQUE POWER COMPANY IS BACT IS THE USE OF PIPELINE‐QUALITY NATURAL
SEEKING TO AMEND THEIR GAS AND THE APPLICATION OF GOOD
ELECTRICAL GENERATION 15.11 NATURAL GAS 170 MW EXISTING PERMIT TO Particulate Matter (PM) COMBUSTION CONTROLS. WITH THIS METHOD OF 0.01 LB/MMBTU 3 HR ROLLING PERIOD
Hours per year for all 4 Particulate matter,
Turbines (4), simple cycle, natural gas 15.11 NATURAL GAS 15020 H/YR turbines filterable (FPM) 0.013 LB/MMBTU ACTUAL HEAT INPUT
Turbines (4), simple cycle, natural gas 15.11 NATURAL GAS 15020 H/YR turbines filterable < 10 µ (FPM10) 0.013 LB/MMBTU ACTUAL HEAT INPUT
Particulate matter,
Turbine ‐ natural gas 15.11 natural gas 107 MW filterable < 2.5 µ (FPM2.5) Baghouse with leak detection system. 8.25 LB/MMBTU 1 H
Particulate matter,
Turbine ‐ natural gas 15.11 natural gas 107 MW filterable < 10 µ (FPM10) Baghouse with leak detection system. 8.25 LB/MMBTU 1 H
consisting of a total of (12) GE Particulate matter, total <
Refrigeration compressor turbines 15.11 natural gas 40000 hp LM2500+ DLE turbines drive 2.5 µ (TPM2.5) 0.72 LB/HR 1 HOUR
Particulate matter, total Good combustion practices and fueled by natural
Simple Cycle Refrigeration Compressor Turbines (16) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 (TPM) gas 2.08 LB/HR HOURLY MAXIMUM
Particulate matter, total Good combustion practices and fueled by natural
Simple Cycle Generation Turbines (2) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 (TPM) gas 2.08 LB/HR HOURLY MAXIMUM
Exclusive Combustion of Fuel Gas, Good
Particulate matter, total < Combustion Practices Including Proper Burner
Aeroderivative Simple Cycle Combustion Turbine 16.11 Natural Gas 263 MM BTU/h 10 µ (TPM10) Design. 4.5 LB/HR 3 HOUR AVERAGE
Exclusive Combustion of Fuel Gas, Good
Particulate matter, total < Combustion Practices Including Proper Burner
Aeroderivative Simple Cycle Combustion Turbine 16.11 Natural Gas 263 MM BTU/h 2.5 µ (TPM2.5) Design. 4.5 LB/HR 3 HOUR AVERAGE
Natural Gas Usage:
Combined Cycle Combustion Turbine without Duct <=28,169,501 MMBtu/year Particulate matter, AV OF THREE ONE H STACK
Burner Firing Natural Gas 15.11 Natural Gas 28169501 MMBTU/YR which includes maximum ultra filterable (FPM) USE OF NATURAL GAS A CLEAN BURNING FUEL 4.7 LB/HR TESTS
SIMPLE CYCLE, NATURAL GAS FIRED COMBUSTION Particulate matter,
TURBINES 15.11 NATURAL GAS 80 MW filterable (FPM) GOOD COMBUSTION PRACTICES 5 LB/HR EACH TURBINE
TURBINES 15.11 NATURAL GAS 80 MW filterable < 10 µ (FPM10) GOOD COMBUSTION PRACTICES 5 LB/HR EACH TURBINE
SIMPLE CYCLE, NATURAL GAS FIRED COMBUSTION Particulate matter, total <
TURBINES 15.11 NATURAL GAS 80 MW 2.5 µ (TPM2.5) GOOD COMBUSTION PRACTICES 5 LB/HR EACH TURBINE
(2) 60‐MEGAWATT PRATT &
(2) 60‐MW SIMPLE CYCLE COMBUSTION TURBINES, WHITNEY GAS TURBINE Particulate matter, total < GOOD COMBUSTION PRACTICES AND USE OF
FIRING NATURAL GAS 15.11 NATURAL GAS 120 MW GENERATOR PACKAGE 10 µ (TPM10) NATURAL GAS 5 LB/HR 3 STACK TEST RUNS
C7
The heat input is for a single Particulate matter, total < AVERAGE OF THREE TEST

Natural Gas Fired Simple Cycle Turbines 15.11 Natural gas 412 MMBTU/H unit. 2.5 µ (TPM2.5) 5 LB/HR RUNS
EIGHT (8) IDENTICAL ROLLS BURNING CLEAN FUELS, NATURAL GAS AND ULTRA
COMBUSTION TURBINES, SIMPLE CYCLE , ROLLS ROYCE TRENT 60WLE (64 MW) Particulate matter, LOW SULFUR DISTILLATE OIL WITH SULFUR
ROYCE, 8 15.11 NATURAL GAS 603 MMBTU/H SIMPLE CYCLE COMBUSTION filterable < 10 µ (FPM10) CONTENT OF 15 PPM. 5 LB/HR
ROYCE, 8 15.11 NATURAL GAS 603 MMBTU/H SIMPLE CYCLE COMBUSTION filterable < 2.5 µ (FPM2.5) CONTENT OF 15 PPM. 5 LB/HR
THE PROCESS CONSISTS OF USE OF CLEAN BURNING FUELS; NATURAL GAS AS
ONE NEW TRENT 60 SIMPLE Particulate matter, PRIMARY FUEL AND ULTRA LOW SULFUR DISTILLATE
SIMPLE CYCLE (NO WASTE HEAT RECOVERY)(>25 MW) 15.11 NATURAL GAS 5000 MMFT3/YR CYCLE COMBUSTION TURBINE. filterable < 10 µ (FPM10) OIL WITH 15 PPMSULFUR BY WEIGHT AS BACKUP 5 LB/HR AVERAGE OF THREE TESTS
SIMPLE CYCLE (NO WASTE HEAT RECOVERY)(>25 MW) 15.11 NATURAL GAS 5000 MMFT3/YR CYCLE COMBUSTION TURBINE. filterable < 2.5 µ (FPM2.5) OIL WITH 15 PPMSULFUR BY WEIGHT AS BACKUP 5 LB/HR AVERAGE OF THREE TESTS
60 wet low emissions (WLE) Particulate matter, AV OF THREE ONE H STACK
Simple Cycle Stationary Turbines firing Natural gas 15.11 Natural Gas 2143980 MMBTU/YR combustion turbine generators filterable (FPM) Use of Natural gas a clean burning fuel 5 LB/HR TESTS EVERY 5 YR
60 wet low emissions (WLE) Particulate matter, total < AV OF THREE ONE H STACK
Simple Cycle Stationary Turbines firing Natural gas 15.11 Natural Gas 2143980 MMBTU/YR combustion turbine generators 10 µ (TPM10) Use of Natural gas a clean burning fuel 5 LB/HR TESTS EVERY 5 YR
Simple Cycle Stationary Turbines firing Natural gas 15.11 Natural Gas 2143980 MMBTU/YR combustion turbine generators 2.5 µ (TPM2.5) Use of natural gas a clean burning fuel 5 LB/HR TESTS EVERY 5 YR
Particulate matter, total <
Natural gas‐fired turbines 15.11 Natural gas 451 MMBTU/H Rating is for each turbine. 2.5 µ (TPM2.5) 5.4 LB/HR
Particulate matter, Good Combustion Practices as described in the
Normal Mode (without Power Augmentation) 15.11 natural gas 0 filterable < 10 µ (FPM10) permit. 5.4 LB/HR HOURLY
Increase power output by
lowering the outlet air Particulate matter, Good combustion practices as defined in the
Power Augmentation 15.11 natural gas 0 temperatur through water filterable < 10 µ (FPM10) permit. 5.4 LB/HR HOURLY
Pipeline quality Particulate matter, total <
GE LM6000PC SPRINT Simple cycle combustion turbine 15.11 natural gas 405.3 MMBTU/hr 10 µ (TPM10) fire only pipeline quality natural gas 6 LB/HR AT FULL OAD
Pipeline quality Particulate matter, total
GE LM6000PC SPRINT Simple cycle combustion turbine 15.11 natural gas 405.3 MMBTU/hr (TPM) fire only pipeline quality natural gas 6 LB/HR AT FULL LOAD
MMBtu/year MMBtu/year (HHV) combined Particulate matter, total < Good combustion practice, Use of Clean Burning
SIMPLE CYCLE TURBINE 15.11 Natural Gas 8940000 (HHV) for all six gas turbines. The 6 10 µ (TPM10) Fuel: Natural gas 6 LB/HR AVERAGE OF THREE TESTS
SIMPLE CYCLE TURBINE 15.11 Natural Gas 8940000 (HHV) for all six gas turbines. The 6 2.5 µ (TPM2.5) Fuel: Natural gas 6 LB/HR AVERGE OF THREE TESTS
MMBtu/year MMBtu/year (HHV) combined Particulate matter, Good combustion practice, Use of Clean Burning
SIMPLE CYCLE TURBINE 15.11 Natural Gas 8940000 (HHV) for all six gas turbines. The 6 filterable (FPM) Fuel: Natural gas 6 LB/HR AVERAGE OF THREE TESTS
CTG01 CO ‐ Simple‐Cycle Combustion Turbine 1 event which occurs after Particulate matter, total < Good combustion practices and the use of low
(Commissioning) [SCN0005] 15.11 Natural Gas 2201 MM BTU/hr construction and is not 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
(Commissioning) [SCN0005] 15.11 Natural Gas 2201 MM BTU/hr construction and is not 2.5 µ (TPM2.5) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
(Commissioning) [SCN0006] 15.11 natural gas 2201 MM BTU/hr construction and is not 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
(Commissioning) [SCN0006] 15.11 natural gas 2201 MM BTU/hr construction and is not 2.5 µ (TPM2.5) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
(Startup/Shutdown/ Maintenance/Tuning/Runback) Particulate matter, total < Good combustion practices and the use of low
[EQT0019] 15.11 Natural Gas 2201 MM BTU/hR Limited to 600 hr/yr 2.5 µ (TPM2.5) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
[EQT0019] 15.11 Natural Gas 2201 MM BTU/hR Limited to 600 hr/yr 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
C8
[EQT0020] 15.11 Natural Gas 2201 MM BTU/hr limited to 600 hr/yr 2.5 µ (TPM2.5) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
[EQT0020] 15.11 Natural Gas 2201 MM BTU/hr limited to 600 hr/yr 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
CTG01 NO ‐ Simple‐Cycle Combustion Turbine 1 Normal operations are based Particulate matter, total < Good combustion practices and the use of low

(Normal Operations) [EQT0017] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hrs/yr 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
CTG01 NO ‐ Simple‐Cycle Combustion Turbine 1 Normal operations are based Particulate matter, total < Good combustion practices & use of low sulfur fuels

(Normal Operations) [EQT0017] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hrs/yr 2.5 µ (TPM2.5) (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM

(Normal Operations) [EQT0018] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hours per year 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
CTG02 NO ‐ Simple‐Cycle Combustion Turbine 2 Normal operations are based Particulate matter, total < Good combustion practices & use of low sulfur fuels

(Normal Operations) [EQT0018] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hours per year 2.5 µ (TPM2.5) (pipeline quality natural gas) 6.3 LB/HR HOULY MAXIMUM
Three GE, LMS100PA, natural
gas‐fired, simple cycle CTG Particulate matter, total Use of pipeline quality natural gas and good AVE OVER STACK TEST
Three simple cycle combustion turbines 15.11 natural gas 799.7 MMBTU/H rated at 799.7 MMBtu per (TPM) combustor design 6.6 LB/HR LENGTH
gas‐fired, simple cycle CTG Particulate matter, total < Use of pipeline quality natural gas and good AVE OVER STACK TEST
Three simple cycle combustion turbines 15.11 natural gas 799.7 MMBTU/H rated at 799.7 MMBtu per 10 µ (TPM10) combustor design 6.6 LB/HR LENGTH
Turbine is a GE Model PG 7121 Particulate matter, total <
Combustion Turbine 15.11 Natural gas 986 MMBTU/H (7EA) used as a peaking unit. 10 µ (TPM10) Good Combustion Practices 7.3 LB/HR AVERAGE OF 3 TEST RUNS
Turbine is a GE Model PG 7121 Particulate matter, total < AVERAGE OF THREE TEST

Combustion Turbine 15.11 Natural gas 986 MMBTU/H (7EA) used as a peaking unit. 2.5 µ (TPM2.5) Good combustion practices. 7.3 LB/HR RUNS
Exclusive Combustion of Fuel Gas and Good
Particulate matter, total < Combustion Practices, Including Proper Burner
Simple Cycle Combustion Turbines (SCCT1 to SCCT3) 15.11 Natural Gas 927 MM BTU/h 10 µ (TPM10) Design. 8 LB/HR 3 HOUR AVERAGE
Simple Cycle Combustion Turbines (SCCT1 to SCCT3) 15.11 Natural Gas 927 MM BTU/h 2.5 µ (TPM2.5) Design. 8 LB/HR 3 HOUR AVERAGE
THE PROCESS USES FUEL OIL GOOD COMBUSTION PRACTICES PIPELINE QUALITY 3 HOUR
SIMPLE CYCLE COMBUSTION TURBINE ‐ ELECTRIC FOR BACKUP AT THE RATE OF Particulate matter, total < NATURAL GAS, ULTRA LOW SULFUR DISTILLATE AVERAGE/CONDITION
GENERATING PLANT 15.11 NATURAL GASE 1530 MW 2129 MMBUT/H 10 µ (TPM10) FUEL 9.1 LB/HR 3.3.23
GE LMS‐100 combustion turbines, simple cycle with Particulate matter, total < Utilize only natural gas or ULSD fuel; Limit the time

water injection 15.11 natural gas 1690 MMBTU/H 10 µ (TPM10) in startup or shutdown. 9.1 LB/HR 6‐HR AVERAGE ON NG
Combined Cycle Combustion Turbine with Duct Burner Particulate matter, AV OF THREE ONE H STACK

firing natural gas 15.11 Natural Gas 0 filterable (FPM) Use of clean burning fuel like natural gas 12 LB/HR TESTS
Natural Gas Usage:
Combined Cycle Combustion Turbine without Duct <=28,169,501 MMBtu/year Particulate matter, total < AV OF THREE ONE H STACK
Burner Firing Natural Gas 15.11 Natural Gas 28169501 MMBTU/YR which includes maximum ultra 10 µ (TPM10) Use of natural gas a clean burning fuel 14.4 LB/HR TESTS
Natural Gas Usage:
Burner Firing Natural Gas 15.11 Natural Gas 28169501 MMBTU/YR which includes maximum ultra 2.5 µ (TPM2.5) Use of natural gas a clean burning fuel 14.4 LB/HR TESTS
TURBINE EXHAUST STACK NO. 1 & NO. 2 15.11 NATURAL GAS 1900 MM BTU/H EACH 2.5 µ (TPM2.5) USE OF PIPELINE NATURAL GAS 17 LB/HR HOURLY MAXIMUM
TURBINE EXHAUST STACK NO. 1 & NO. 2 15.11 NATURAL GAS 1900 MM BTU/H EACH 10 µ (TPM10) USE OF PIPELINE NATURAL GAS 17 LB/HR HOURLY MAXIMUM
GE 7FA Simple Cycle Combustion Turbine 15.11 natural gas 1780 MMBTU/HR 10 µ (TPM10) will fire only pipeline quality natural gas 18 LB/HR
Pipeline quality Particulate matter, total
GE 7FA Simple Cycle Combustion Turbine 15.11 natural gas 1780 MMBTU/HR (TPM) will fire only pipeline quality natural gas 18 LB/HR
Combined Cycle Combustion Turbine with Duct Burner Particulate matter, total < AV OF THREE ONE H STACK

firing natural gas 15.11 Natural Gas 0 10 µ (TPM10) Use of natural gas a clean burning fuel 22.6 LB/HR TESTS
C9

firing natural gas 15.11 Natural Gas 0 2.5 µ (TPM2.5) Use of natural gas a clean burning fuel 22.6 LB/HR TESTS
MMBtu/hr turbines. Max of 3390 hours Particulate matter, total
Five 200‐MW combustion turbines 15.11 Natural gas 2100 (approx) per year per turbine. Of the (TPM) Clean fuel prevents PM formation 2 GR. S / 100 SCF GAS FUEL RECORD KEEPING
MMBtu/hr turbines. Max of 3390 hours Particulate matter, total <
Five 200‐MW combustion turbines 15.11 Natural gas 2100 (approx) per year per turbine. Of the 10 µ (TPM10) Clean fuel prevents PM formation 2 GR. S / 100 SCF GAS FUEL RECORD KEEPING
Five 200‐MW combustion turbines 15.11 Natural gas 2100 (approx) per year per turbine. Of the 2.5 µ (TPM2.5) Clean fuel prevents PM formation 2 GR. S / 100 SCF GAS FUEL RECORD KEEPING
Two GE 7F.05 turbines,
approximately 200 MW each. Particulate matter, total
Combustion Turbines 15.11 Natural gas 2262.4 MMBtu/hr gas Natural‐gas is primary fuel. (TPM) Use of clean fuels, and annual VE test 2 GR. S / 100 SCF GAS FOR NATURAL GAS
approximately 200 MW each. Particulate matter, total <
Combustion Turbines 15.11 Natural gas 2262.4 MMBtu/hr gas Natural‐gas is primary fuel. 10 µ (TPM10) Use of clean fuels 2 GR. S / 100 SCF GAS FOR NATURAL GAS
Combustion Turbines 15.11 Natural gas 2262.4 MMBtu/hr gas Natural‐gas is primary fuel. 2.5 µ (TPM2.5) Use of clean fuels 2 GR. S / 100 SCF GAS FOR NATURAL GAS
TWO SIMPLE CYCLE COMBUSTION TURBINE ‐ MODEL SULFUR DIESEL WITH A Particulate matter, total < 6‐MINUTE BLOCK BY EPA
7FA 15.11 NATURAL GAS 170 MW MAXIMUM SULFUR CONTENT 10 µ (TPM10) 10 % OPACITY METHOD 9
C10
Natural Gas Fired Simple Cycle Turbine GHG ‐ RBLC Dataset
PROCCESS_ THROUGHPUT_U EMISSION_LIMIT_1_ EMISSION_LIMIT_1_AVG_ CASE‐BY‐
PROCESS_NAME TYPE PRIMARY_FUEL THROUGHPUT NIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1 UNIT TIME_CONDITION CASE_BASIS
Facility‐wide energy efficiency measures , such as
CTG01 NO ‐ Simple‐Cycle Combustion Turbine 1 Normal operations are based Carbon Dioxide Equivalent improved combustion measures, and use of
(Normal Operations) [EQT0017] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hrs/yr (CO2e) pipeline quality natural gas. 50 KG/GJ ANNUAL AVERAGE BACT‐PSD
Facility‐wide energy efficiency measures , such as
CTG02 NO ‐ Simple‐Cycle Combustion Turbine 2 Normal operations are based Carbon Dioxide Equivalent improved combustion measures, and use of
(Normal Operations) [EQT0018] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hours per year (CO2e) pipeline quality natural gas. 50 KG/GJ ANNUAL AVERAGE BACT‐PSD
CTG01 SUSD ‐ Simple‐Cycle Combustion Turbine 1 Facility‐wide energy efficiency measures , such as
(Startup/Shutdown/ Maintenance/Tuning/Runback) Carbon Dioxide Equivalent improved combustion measures, and use of
[EQT0019] 15.11 Natural Gas 2201 MM BTU/hR Limited to 600 hr/yr (CO2e) pipeline quality natural gas. 120 LB/MM BTU ANNUAL AVERAGE BACT‐PSD
CTG02 SUSD ‐ Simple‐Cycle Combustion Turbine 2 Facility‐wide energy efficiency measures , such as
(Startup/Shutdown/ Maintenance/Tuning/Runback) Carbon Dioxide Equivalent improved combustion measures, and use of
[EQT0020] 15.11 Natural Gas 2201 MM BTU/hr limited to 600 hr/yr (CO2e) pipeline quality natural gas. 120 LB/MM BTU ANNUAL AVERAGE BACT‐PSD
TWO GENERAL ELECTRIC (GE) HIGH EFFICIENCY GE 7EA CTS WITH HRSGS
FRAME 7EA COMBUSTION Carbon Dioxide Equivalent EQUIPPED WITH DLN1 COMBUSTORS AND
2 COMBUSTION TURBINES 15.11 NATURAL GAS 130 MW TURBINES (CTS) WITH A (CO2e) EXCLUSIVE USE OF FACILITY PROCESS FUEL GAS OR 117 LB/MMBTU 3‐HOUR BLOCK AVERAGE BACT‐PSD
NATURAL GAS AS PRIMARY FUEL; GOOD
PRATT & TWIN‐PAC SIMPLE CYCLE TURBINES 15.11 NATURAL GAS 270.9 MMBTU/H NO. 2 DIESEL OIL BACKUP FUEL Carbon Dioxide COMBUSTION PRACTICES 118 LB/MMBTU FOR NATURAL GAS BACT‐PSD
Turbine ‐ natural gas 15.11 natural gas 107 MW Carbon Dioxide 130.17 LB/MMBTU 1 H BACT‐PSD

turbine generators (CTG). Each Carbon Dioxide Equivalent
COMBUSTION TURBINES (NORMAL OPERATION) 15.11 NATURAL GAS 300 MW CTG rated at 100 MW (nominal (CO2e) 1328 LB/MWH GROSS OUTPUT BACT‐PSD
MMBtu/hr turbines. Max of 3390 hours Use of natural gas with restricted use of ULSD as NAT GAS OPERATION, 12‐
Five 200‐MW combustion turbines 15.11 Natural gas 2100 (approx) per year per turbine. Of the Carbon Dioxide backup fuel 1372 LB/MWH OR 36‐ MO ROLLING BACT‐PSD
approximately 200 MW each. Carbon Dioxide Equivalent FOR NATURAL GAS
Combustion Turbines 15.11 Natural gas 2262.4 MMBtu/hr gas Natural‐gas is primary fuel. (CO2e) Use of low‐emitting fuel and efficient turbine 1374 LB/MWH OPERATION BACT‐PSD
(2) 60‐MEGAWATT PRATT & USE OF NATURAL GAS. ENERGY EFFICIENCY DESIGN ‐
(2) 60‐MW SIMPLE CYCLE COMBUSTION TURBINES, WHITNEY GAS TURBINE Carbon Dioxide Equivalent USE OF INLET FOGGING/WET COMPRESSION, 12‐MONTH ROLLING,
FIRING NATURAL GAS 15.11 NATURAL GAS 120 MW GENERATOR PACKAGE (CO2e) INSULATION BLANKETS TO REDUCE HEAT LOSS, 1394 LB/MWH EXCLUDING SU/SD BACT‐PSD
GE LMS‐100 combustion turbines, simple cycle with Carbon Dioxide Equivalent 365‐DAY ROLLING

water injection 15.11 natural gas 1690 MMBTU/H (CO2e) Thermal efficiency Clean fuels 1707 LB/MWH AVERAGE BACT‐PSD
The heat input is for a single Carbon Dioxide Equivalent 12 MONTH ROLLING

Natural Gas Fired Simple Cycle Turbines 15.11 Natural gas 412 MMBTU/H unit. (CO2e) High efficiency turbines 220122 TONS/YR TOTAL BACT‐PSD
Carbon Dioxide Equivalent 12 MONTH ROLLING
Natural gas‐fired turbines 15.11 Natural gas 451 MMBTU/H Rating is for each turbine. (CO2e) 243147 TONS/YR TOTAL/EACH UNIT BACT‐PSD
Turbine is a GE Model PG 7121 Carbon Dioxide Equivalent 12 MONTH ROLLING

Combustion Turbine 15.11 Natural gas 986 MMBTU/H (7EA) used as a peaking unit. (CO2e) 413198 TONS/YR TOTAL BACT‐PSD
Exclusively combust low carbon fuel gas, good
Carbon Dioxide Equivalent combustion practices, good operation and
Simple Cycle Combustion Turbines (SCCT1 to SCCT3) 15.11 Natural Gas 927 MM BTU/h (CO2e) maintenance practices, and insulation 1426146 TONS/YR ANNUAL TOTAL BACT‐PSD
Carbon Dioxide Equivalent Good combustion/operating practices and fueled ANNUAL MAXIMUM FROM

Simple Cycle Refrigeration Compressor Turbines (16) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 (CO2e) by natural gas ‐ use GE LM2500+G4 turbines 4872107 TONS/YR THE FACILITYWIDE BACT‐PSD
Carbon Dioxide Equivalent Good combustion/operating practices and fueled ANNUAL MAXIMUM FROM

Simple Cycle Generation Turbines (2) 15.11 Natural Gas 286 MMBTU/H GE LM2500+G4 (CO2e) by natural gas ‐ use GE LM2500+G4 turbines 4872107 TONS/YR THE FACILITYWIDE BACT‐PSD
turbines used for peaking Carbon Dioxide Equivalent
Two Simple Cycle Combustion Turbines 15.11 Natural Gas 190 MW purposes and fired primarily (CO2e) Turbine‐generator design and proper operation 0 BACT‐PSD
Carbon Dioxide Equivalent good combustion/operating/maintenance practices
Gas Turbines (8 units) 15.11 natural gas 333 mm btu/hr (CO2e) and fueled by natural gas; use intake air chiller 0 BACT‐PSD
Carbon Dioxide Equivalent good combustion practices and fueled by natural
Gas turbines (9 units) 15.11 natural gas 1069 mm btu/hr (CO2e) gas; Use high thermal efficiency turbines 0 BACT‐PSD
C11
El Paso Electric
Newman Station
RBLC MSS Emission Rate Comparisons
BACT/LAER Analysis ‐ Emission Rates During Turbine Startup/Shutdown1
NOX CO VOC2 PM2
Unit Start Shutdown Start Shutdown Start Shutdown Start Shutdown
Proposed lb/hr/MMBTU/hr 0.0232 0.0190 0.2206 0.1343 0.1242 0.0626 0.0028 0.0028
Highest Value from RBLC lb/hr/MMBTU/hr 0.2100 0.0225 3.0240 3.0240 0.0695 0.0695 0.0089 0.0089
Lowest Value from RBLC lb/hr/MMBTU/hr 0.0150 0.0225 0.0350 0.0342 0.0695 0.0695 0.0029 0.0029
Proposed lb/hr/MW 0.0227 0.0186 0.2157 0.1313 0.1203 0.0612 0.0027 0.0027
Highest Value from RBLC lb/hr/MW 5.0173 0.0773 2.2660 2.2660 0.3888 0.0369 0.0395 ‐
Lowest Value from RBLC lb/hr/MW 0.0750 0.0773 0.6180 0.4554 0.3888 0.0369 0.0395 ‐
1
For the purpose of this analysis, to the extent that data is available, the RBLC database turbine startup and shutdown emissions are compared against the
proposed unit emission rates. However, these rates are normalized based on their MMBtu/hr or MW ratings depending on the available data in the RBLC
dataset.
2
Minimal Data for the analysis was available.
C12
Natural Gas Fired Simple Cycle Turbine Start up/Shut Down NOX ‐ RBLC Dataset ‐ Relevant data in Red
THROUG
PROCCESS_ PRIMARY_F THROUGH HPUT_U EMISSION_LIMIT_ EMISSION_LIMIT EMISSION_LIMIT_1_AVG_ EMISSION_LIMIT_ EMISSION_LIMIT EMISSION_LIMIT_2_AVGER
PROCESS_NAME TYPE UEL PUT NIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION 1 _1_UNIT TIME_CONDITION 2 _2_UNIT AGE_TIME_CONDITION POLLUTANT_COMPLIANCE_NOTES
Advanced low NOx burners, closed‐coupled and 0.03 LB/MMBTU 12 MO Includes startups,
Nitrogen Oxides staged over‐fire air, Selective Non‐Catalytic shutdowns, malfunctions, and upsets. 0.0365
Turbine ‐ natural gas 15.11 natural gas 107 MW (NOx) Reduction, and Selective Catalytic Reduction. 0.03 LB/MMBTU 12 MO 0.0365 LB/MMBTU 1 H LB/MMBTU 1 H Does not includes startups,
(2) 60‐MEGAWATT PRATT & USE OF NATURAL GAS, WATER/STEAM INJECTION, STARTUP EVENTS (1 CT OR 2 CTS) ARE LIMITED
(2) 60‐MW SIMPLE CYCLE COMBUSTION NATURAL WHITNEY GAS TURBINE Nitrogen Oxides AND A SELECTIVE CATAYTIC REDUCTION (SCR) PPMVD @ 15% 3‐HOUR BLOCK AVERAGE, 3‐HOUR BLOCK AVERAGE, TO 36.4 LB/EVENT; AND SHUTDOWN EVENTS (1
TURBINES, FIRING NATURAL GAS 15.11 GAS 120 MW GENERATOR PACKAGE (NOx) SYSTEM 2.5 O2 EXCLUDING SU/SD 5.8 LB/H EXCLUDING SU/SD CT OR 2 CTS) ARE LIMITED TO 9.27 LB/EVENT
Utilize water injection when combusting natural gas
or ULSD; Utilize selective catalytic reduction (SCR)
with aqueous ammonia injection at all times except
GE LMS‐100 combustion turbines, simple MMBTU/ Nitrogen Oxides during startup and shutdown; Limit the time in PPMDV AT 15% 3‐HR ROLLING AVERAGE PPMDV AT 15% 3‐HR ROLLING AVERAGE ON
cycle with water injection 15.11 natural gas 1690 H (NOx) startup or shutdown. 2.5 O2 ON NG 3.8 O2 ULSD
Three GE, LMS100PA, startup limit = 12.0 lb per event shutdown limit =
MMBTU/ natural gas‐fired, simple Nitrogen Oxides Good combustor design, Water Injection and PPMVD AT 15% 18.0 lb per event compliance with BACT limits
Three simple cycle combustion turbines 15.11 natural gas 799.7 H cycle CTG rated at 799.7 (NOx) Selective Catalytic Reduction (SCR) 5 O2 1‐HR AVE 15.5 LB/H 30‐DAY ROLLING AVE monitored via continuous emissions monitors.
RBLC Staff: Original Emis Limit 2 Units were
MMBTU/ Nitrogen Oxides 4 HR. ROLLING AVERAGE Numeric Limit ‐ ‘‘LB‘‘ and Avg Time/Condition ‐
Natural gas‐fired turbines 15.11 Natural gas 451 H Rating is for each turbine. (NOx) Water injection plus SCR 5 PPPMVD EXCEPT FOR STARTUP 19 LB/H DURING STARTUP ‘‘PER HOUR DURING STARTUP‘‘ The Emission
The startup limit is for each unit. The three units
MMBTU/ The heat input is for a single Nitrogen Oxides 4 HOUR ROLLING AVERAGE TOTAL FOR 30 MINUTES are limited to a total combined emission rate of
Natural Gas Fired Simple Cycle Turbines 15.11 Natural gas 412 H unit. (NOx) SCR 5 PPMVD EXCEPT STARTUP 18.5 LB DURING STARTUP 42.9 pounds per hour (1‐hour average) at all
Three simple cycle Third emission limit incorrectly entered into the
COMBUSTION TURBINES (STARTUP & NATURAL combustion turbine Nitrogen Oxides Standard Limit field. RBLC SysOp moved the
SHUTDOWN PERIODS) 15.11 GAS 300 MW generators (CTG). Each CTG (NOx) water injection and SCR system 22.5 LB/H STARTUP EVENTS 6 LB/H SHUTDOWN EVENTS information into this Notes field. Here is the
The NOx limit was converted to an equivalent
GE LMS100PA, natural gas hourly based limit (the original permit included
MMBTU/ fired, simple cycle, Nitrogen Oxides 1‐HR AVE / STARTUP AND an event based limit) for periods of startup and
Turbines ‐ two simple cycle gas 15.11 natural gas 799.7 H each combustion turbine. (NOx) SCR and dry low NOx burners 23 LB/H SHUTDOWN 0 shutdown.
CTG01 SUSD ‐ Simple‐Cycle Combustion
Turbine 1 (Startup/Shutdown/ NOX monitored with a Continuous Emissions
Maintenance/Tuning/Runback) MM Nitrogen Oxides Monitoring System (CEMS) as required by NSPS
[EQT0019] 15.11 Natural Gas 2201 BTU/hR Limited to 600 hr/yr (NOx) Pipeline quality natural gas & dry‐low‐NOX burners 86.38 LB/HR HOURLY MAXIMUM 0 Subpart KKKK.
Turbine 2 (Startup/Shutdown/ NOX monitored with a Continuous Emissions
Maintenance/Tuning/Runback) MM Nitrogen Oxides Monitoring System (CEMS) as required by NSPS
[EQT0020] 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr (NOx) Pipeline quality natural gas & dry‐low‐NOX burners 86.38 LB/HR HOURLY MAXIMUM 0 Subpart KKKK.
LIMITS ARE PER TURBINE EXHAUST STACK.
AGGREGATE NOX EMISSIONS FROM BOTH
TURBINE EXHAUST STACKS ARE LIMITED TO
MM HOURLY MAXIMUM / 391.30 TONS PER YEAR. STARTUP & SHUTDOWN
NATURAL BTU/H Nitrogen Oxides STARTUP & SHUTDOWN OPERATIONS ARE LIMITED TO 520 HOURS PER
TURBINE EXHAUST STACK NO. 1 & NO. 2 15.11 GAS 1900 EACH (NOx) DRY LOW NOX COMBUSTORS 240 LB/H HOURLY MAXIMUM 798 LB/H ONLY YEAR.
Utilize dry low‐NOx burners when combusting
natural gas; Utilize water injection when combusting
ULSD; Utilize selective catalytic reduction (SCR) with
Mitsubishi M501‐GAC combustion aqueous ammonia injection at all times except
turbine, combined cycle configuration MMBTU/ or ULSD; Duct burner 499 Nitrogen Oxides during startup and shutdown; Limit the time in PPMDV AT 15% 3‐HR ROLLING AVERAGE PPMDV AT 15% 3‐HR ROLLING AVERAGE ON
with duct burner. 15.21 natural gs 2988 H MMBtu/hr, natural gas (NOx) startup or shutdown. 2 O2 ON NG 5.5 O2 ULSD
C13
Natural Gas Fired Simple Cycle Turbine Start up/Shut Down NOX ‐ RBLC Dataset ‐ Relevant data in Red
THROUG
PROCCESS_ PRIMARY_F THROUGH HPUT_U Shut Down MSS MSS startup MSS Shutdown MSS Startup MSS Shutdown
PROCESS_NAME TYPE UEL PUT NIT PROCESS_NOTES POLLUTANT Startup MSS lb/hr/unit lb/hr/unit lb/hr/MMBtu/hr lb/hr/MMBTU/hr lb/hr/MW lb/hr/MW
Nitrogen Oxides Limit duration of Limit duration of

Turbine ‐ natural gas 15.11 natural gas 107 MW (NOx) event/hours per year event/hours per year
(2) 60‐MW SIMPLE CYCLE COMBUSTION NATURAL WHITNEY GAS TURBINE Nitrogen Oxides
TURBINES, FIRING NATURAL GAS 15.11 GAS 120 MW GENERATOR PACKAGE (NOx) 36.4 9.27 0.303 0.077
GE LMS‐100 combustion turbines, simple MMBTU/ Nitrogen Oxides Limit duration of Limit duration of

cycle with water injection 15.11 natural gas 1690 H (NOx) event/hours per year event/hours per year
Three GE, LMS100PA,
MMBTU/ natural gas‐fired, simple Nitrogen Oxides
Three simple cycle combustion turbines 15.11 natural gas 799.7 H cycle CTG rated at 799.7 (NOx) 12 18 0.015 0.023
MMBTU/ Nitrogen Oxides
Natural gas‐fired turbines 15.11 Natural gas 451 H Rating is for each turbine. (NOx) 19 0.042
MMBTU/ The heat input is for a single Nitrogen Oxides

Natural Gas Fired Simple Cycle Turbines 15.11 Natural gas 412 H unit. (NOx) 18.5 0.045
Three simple cycle
COMBUSTION TURBINES (STARTUP & NATURAL combustion turbine Nitrogen Oxides
SHUTDOWN PERIODS) 15.11 GAS 300 MW generators (CTG). Each CTG (NOx) 22.5 0.075
MMBTU/ fired, simple cycle, Nitrogen Oxides
Turbines ‐ two simple cycle gas 15.11 natural gas 799.7 H each combustion turbine. (NOx) 23 0.029
Turbine 1 (Startup/Shutdown/
Maintenance/Tuning/Runback) MM Nitrogen Oxides
[EQT0019] 15.11 Natural Gas 2201 BTU/hR Limited to 600 hr/yr (NOx) 86.38 0.039
Turbine 2 (Startup/Shutdown/
Maintenance/Tuning/Runback) MM Nitrogen Oxides
[EQT0020] 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr (NOx) 86.38 0.039
MM
NATURAL BTU/H Nitrogen Oxides
TURBINE EXHAUST STACK NO. 1 & NO. 2 15.11 GAS 1900 EACH (NOx) 399 0.210
Mitsubishi M501‐GAC combustion
turbine, combined cycle configuration MMBTU/ or ULSD; Duct burner 499 Nitrogen Oxides Limit duration of Limit duration of
with duct burner. 15.21 natural gs 2988 H MMBtu/hr, natural gas (NOx) event/hours per year event/hours per year
C14
Natural Gas Fired Simple Cycle Turbine Start up/Shut Down CO ‐ RBLC Dataset ‐ Relevant data in Red
THROUG
PROCCESS_ PRIMARY_F THROUGH HPUT_U EMISSION_LIMIT_ EMISSION_LIMIT EMISSION_LIMIT_1_AVG_ CASE‐BY‐ EMISSION_LIMIT_ EMISSION_LIMIT EMISSION_LIMIT_2_AVGER
PROCESS_NAME TYPE UEL PUT NIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION 1 _1_UNIT TIME_CONDITION CASE_BASIS 2 _2_UNIT AGE_TIME_CONDITION POLLUTANT_COMPLIANCE_NOTES
Includes startups, shutdowns, malfunctions, and
Turbine ‐ natural gas 15.11 natural gas 107 MW Carbon Monoxide 0.095 LB/MMBTU 12 MO BACT‐PSD 0.037 LB/MMBTU 24 H upsets.
GE LMS100PA, natural gas The CO limit was converted to an equivalent
MMBTU/ fired, simple cycle, 1‐HR AVE / STARTUP AND hourly based limit (the original permit included
Turbines ‐ two simple cycle gas 15.11 natural gas 799.7 H each combustion turbine. Carbon Monoxide Catalytic Oxidation. 55 LB/H SHUTDOWN BACT‐PSD 0 an event based limit) for periods of startup and
T/YR limit is for both fuels and for the 4 turbines
NATURAL MMBTU/ Hours per year for all 4 PER ROLLING 12‐MO. FOR 4 combined. Limit during startup‐shutdown shall
Turbines (4), simple cycle, natural gas 15.11 GAS 1115.2 hr turbines Carbon Monoxide efficient combution technology 301 LB/H EACH TURBINE BACT‐PSD 724 T/YR UNITS &ALL FUEL not exceed 413 LB/H for each unit when burning
CTG01 SUSD ‐ Simple‐Cycle Combustion CO emissions will be monitored with a
Turbine 1 (Startup/Shutdown/ MM Good combustion practices & use of pipeline quality Continuous Emissions Monitoring System
Maintenance/Tuning/Runback) 15.11 Natural Gas 2201 BTU/hR Limited to 600 hr/yr Carbon Monoxide natural gas 800.08 LB/HR HOURLY MAXIMUM BACT‐PSD 0 (CEMS).
CTG02 SUSD ‐ Simple‐Cycle Combustion CO emissions will be monitored with a
Turbine 2 (Startup/Shutdown/ MM Good combustion practices & use of pipeline quality Continuous Emissions Monitoring System
Maintenance/Tuning/Runback) 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr Carbon Monoxide natural gas 800.08 LB/HR HOURLY MAXIMUM BACT‐PSD 0 (CEMS).
Each combustion turbine During demonstration period, limit without duct
MMBtu/h rated at 214 MW, with a 1‐HR, DEMO LIMIT, W/O firing is 2.0 ppm Mass Emission Limits: w/o duct
Combustion Turbines (GEN1 and GEN2) 15.11 Natural Gas 2217 r maximum heat input rate of Carbon Monoxide Oxidation Catalyst 1.5 PPM @ 15% O2 DUCT FIRING BACT‐PSD 2 PPM @ 15% O2 1‐HR W/DUCT FIRING firing: 7.8 lb/hr (10.4 lb/hr during demonstration
Combustion turbine wih duct burner and Frame 6B NG fired turbine PPMDV @ 15% 1 HR AVG EX DURING DURING STARTUP AND
heat recovery steam generator 15.11 Natural Gas 40.6 MW with duct burners and heat Carbon Monoxide 2 O2 STARTUP AND SHUTDOWN BACT‐PSD 276 LB/HR SHUTDOWN 3 units
GE LMS‐100 combustion turbines, simple MMBTU/ Oxidation catalyst; Limit the time in startup or PPMDV AT 15% 3‐HR ROLLING AVERAGE PPMDV AT 15% 3‐HR ROLLING AVERAGE ON

cycle with water injection 15.11 natural gas 1690 H Carbon Monoxide shutdown. 6 O2 ON NG BACT‐PSD 6 O2 ULSD
turbine, combined cycle configuration MMBTU/ or ULSD; Duct burner 499 Oxidation catalyst; Limit the time in startup or PPMDV AT 15% 3‐HR ROLLING AVERAGE PPMDV AT 15% 3‐HR ROLLING AVERAGE ON
with duct burner. 15.21 natural gs 2988 H MMBtu/hr, natural gas Carbon Monoxide shutdown. 3.3 O2 ON NG BACT‐PSD 9 O2 ULSD
RBLC Staff: Original Emis Limit 2 Units were
MMBTU/ 8 HR. ROLLING Numeric Limit ‐ ‘‘LB‘‘ and Avg Time/Condition ‐
Natural gas‐fired turbines 15.11 Natural gas 451 H Rating is for each turbine. Carbon Monoxide Catalytic oxidation system 6 PPMVD AVERAGE/EXCEPT STARTUP BACT‐PSD 57.2 LB/H DURING STARTUP ‘‘1 HR/DURING STARTUP‘‘ The Emission Units
The startup limit is for each unit. The three units
MMBTU/ The heat input is for a single 8‐HOUR ROLLING AVERAGE 30 MINUTE TOTAL FOR are limited to a total combined emission rate of
Natural Gas Fired Simple Cycle Turbines 15.11 Natural gas 412 H unit. Carbon Monoxide Oxidation Catalyst 6 PPMVD EXCEPT STARTUP BACT‐PSD 31.5 LB STARTUP 54.2 pounds per hour (1‐hour average) at all
Three GE, LMS100PA, Startup limit: 28.0 lb per event Shutdown limit:
MMBTU/ natural gas‐fired, simple Good Combustion Control and Catalytic Oxidation PPMVD AT 15% 36.0 lb per event compliance with BACT limits
Three simple cycle combustion turbines 15.11 natural gas 799.7 H cycle CTG rated at 799.7 Carbon Monoxide (CatOx) 10 O2 1‐HR AVE BACT‐PSD 19.8 LB/H 30‐DAY ROLLING AVE monitored via continuous emissions monitors.
TWO GENERAL ELECTRIC
(GE) FRAME 7EA
COMBUSTION TURBINES
(CTS) WITH A NOMINAL
NET 87.2 MEGAWATT
(MW) RATED CAPACITY,
COUPLED WITH A HEAT
RECOVERY STEAM
GENERATOR (HRSG),
EQUIPPED WITH DRY LOW‐
NOX COMBUSTORS,
SELECTIVE CATALYTIC EXCLUSIVE USE OF FACILITY PROCESS FUEL GAS OR 59.2 LB/SHUTDOWN EVENT. LIMITS ARE TOTAL
NATURAL REDUCTION SYSTEM (SCR), PIPELINE QUALITY NATURAL GAS, USE OF AN PPMVD @ 15% 3‐HOUR BLOCK AVERAGE, FOR BOTH FRAME 7 CTS PER STARTUP OR
2 COMBUSTION TURBINES 15.11 GAS 130 MW AND OXIDATION CATALYST Carbon Monoxide OXIDATION CATALYST AND EFFICIENT COMBUSTION 1.5 O2 EXLUDING SU/SD BACT‐PSD 562.4 LB/EVENT FOR ALL STARTUPS SHUTDOWN EVENT
PPMVD @ 15% Applies to all operating loads, except during
Turbines and duct burners 15.11 natural gas 228 MW Carbon Monoxide good combustion practice and oxidation catalyst 2 O2 1 H BACT‐PSD 0 startup and shutdown.
Three GE, LMS6000 PF,
natural gas‐fired, combined
cycle CTG, rated at 373
MMBtu per hour each,
based on HHV and one (1) startup limit: 140.0 lb per event shutdown limit:
MMBTU/ HRSG each with no Duct PPMVD AT 15% 15.0 lb per event compliance is monitored with
Four combined cycle combution turbines 15.21 natural gas 373 H Burners Carbon Monoxide Good combustion control and catalytic oxidation 4 O2 1‐HR AVE BACT‐PSD 3.3 LB/H 30‐DAY ROLLING AVE continuous emissions monitors
Natural gas with up to 19%
biomass ‐ clean
natural gas unadulterated wood and/or Includes startups, shutdowns, malfunctions, and
and up to kiln dried wood (including upsets. 0.095 LB/MMBTU 12 M 0.075
Turbine ‐ natural gas and wood 15.9 19% wood 107 MW resinated wood) Carbon Monoxide 0.095 LB/MMBTU 12 MO BACT‐PSD 0.075 LB/MMBTU 24 H LB/MMBTU 24 H 0.075 LB/MMBTU 30 D
AGGREGATE CO EMISSIONS FROM BOTH
MM HOURLY MAXIMUM / 1344.53 TONS PER YEAR. STARTUP &
NATURAL BTU/H STARTUP & SHUTDOWN SHUTDOWN OPERATIONS ARE LIMITED TO 520
TURBINE EXHAUST STACK NO. 1 & NO. 2 15.11 GAS 1900 EACH Carbon Monoxide DRY LOW NOX COMBUSTORS 781 LB/H HOURLY MAXIMUM BACT‐PSD 5745.6 LB/H ONLY HOURS PER YEAR.
C15
Natural Gas Fired Simple Cycle Turbine Start up/Shut Down CO ‐ RBLC Dataset ‐ Relevant data in Red
THROUG
PROCCESS_ PRIMARY_F THROUGH HPUT_U MSS startup MSS Shutdown MSS Startup MSS Shutdown
PROCESS_NAME TYPE UEL PUT NIT PROCESS_NOTES POLLUTANT Startup MSS lb/hr/unit Shut Down MSS lb/hr/unit lb/hr/MMBtu/hr lb/hr/MMBTU/hr lb/hr/MW lb/hr/MW
Limit duration of event/hours Limit duration of event/hours
Turbine ‐ natural gas 15.11 natural gas 107 MW Carbon Monoxide per year per year
MMBTU/ fired, simple cycle,
Turbines ‐ two simple cycle gas 15.11 natural gas 799.7 H each combustion turbine. Carbon Monoxide 55 0.068775791
NATURAL MMBTU/ Hours per year for all 4

Turbines (4), simple cycle, natural gas 15.11 GAS 1115.2 hr turbines Carbon Monoxide 413 413 0.370 0.370
Turbine 1 (Startup/Shutdown/ MM
Maintenance/Tuning/Runback) 15.11 Natural Gas 2201 BTU/hR Limited to 600 hr/yr Carbon Monoxide 800.08 800.08 0.364 0.364
Turbine 2 (Startup/Shutdown/ MM
Maintenance/Tuning/Runback) 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr Carbon Monoxide 800.08 800.08 0.364 0.364
Each combustion turbine
MMBtu/h rated at 214 MW, with a
Combustion Turbines (GEN1 and GEN2) 15.11 Natural Gas 2217 r maximum heat input rate of Carbon Monoxide 416 75.9 0.187640956 0.034235453
Combustion turbine wih duct burner and Frame 6B NG fired turbine
heat recovery steam generator 15.11 Natural Gas 40.6 MW with duct burners and heat Carbon Monoxide 92 92 2.266 2.266
GE LMS‐100 combustion turbines, simple MMBTU/ Limit duration of event/hours Limit duration of event/hours

cycle with water injection 15.11 natural gas 1690 H Carbon Monoxide per year per year
turbine, combined cycle configuration MMBTU/ or ULSD; Duct burner 499 Limit duration of event/hours Limit duration of event/hours
with duct burner. 15.21 natural gs 2988 H MMBtu/hr, natural gas Carbon Monoxide per year per year
MMBTU/
Natural gas‐fired turbines 15.11 Natural gas 451 H Rating is for each turbine. Carbon Monoxide 57.2 57.2 0.127 0.127
MMBTU/ The heat input is for a single
Natural Gas Fired Simple Cycle Turbines 15.11 Natural gas 412 H unit. Carbon Monoxide 31.5 31.5 0.076 0.076
Three GE, LMS100PA,
MMBTU/ natural gas‐fired, simple
Three simple cycle combustion turbines 15.11 natural gas 799.7 H cycle CTG rated at 799.7 Carbon Monoxide 28 36 0.035 0.045
(GE) FRAME 7EA
COMBUSTION TURBINES
NET 87.2 MEGAWATT
(MW) RATED CAPACITY,
COUPLED WITH A HEAT
RECOVERY STEAM
GENERATOR (HRSG),
EQUIPPED WITH DRY LOW‐
NOX COMBUSTORS,
SELECTIVE CATALYTIC
NATURAL REDUCTION SYSTEM (SCR),
2 COMBUSTION TURBINES 15.11 GAS 130 MW AND OXIDATION CATALYST Carbon Monoxide 80.3 59.2 0.62 0.46
Limit duration of event/hours Limit duration of event/hours
Turbines and duct burners 15.11 natural gas 228 MW Carbon Monoxide per year per year
Three GE, LMS6000 PF,
natural gas‐fired, combined
cycle CTG, rated at 373
MMBtu per hour each,
based on HHV and one (1)
MMBTU/ HRSG each with no Duct
Four combined cycle combution turbines 15.21 natural gas 373 H Burners Carbon Monoxide 140.0 15.0 0.4 0.04
Natural gas with up to 19%
biomass ‐ clean
natural gas unadulterated wood and/or
and up to kiln dried wood (including Limit duration of event/hours Limit duration of event/hours
Turbine ‐ natural gas and wood 15.9 19% wood 107 MW resinated wood) Carbon Monoxide per year per year
MM
NATURAL BTU/H
TURBINE EXHAUST STACK NO. 1 & NO. 2 15.11 GAS 1900 EACH Carbon Monoxide 5745.6 5745.6 3.024 3.024
C16
Natural Gas Fired Simple Cycle Turbine Start up/Shut Down VOC ‐ RBLC Dataset ‐ Relevant data in Red
THROUG EMISSION_LIMIT_2
PROCCESS_ PRIMARY_F THROUGH HPUT_U EMISSION_LIMIT_ EMISSION_LIMIT EMISSION_LIMIT_1_AVG_ CASE‐BY‐ EMISSION_LIMIT_ EMISSION_LIMIT _AVGERAGE_TIME_
PROCESS_NAME TYPE UEL PUT NIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION 1 _1_UNIT TIME_CONDITION CASE_BASIS 2 _2_UNIT CONDITION POLLUTANT_COMPLIANCE_NOTES
CTG01 SUSD ‐ Simple‐Cycle
Combustion Turbine 1
(Startup/Shutdown/
Maintenance/Tuning/Runback) MM Volatile Organic Good combustion practices & use of pipeline quality
[EQT0019] 15.11 Natural Gas 2201 BTU/hR Limited to 600 hr/yr Compounds (VOC) natural gas 0 BACT‐PSD 0
(Startup/Shutdown/
Maintenance/Tuning/Runback) MM Volatile Organic Good combustion practices & use of pipeline quality
[EQT0020] 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr Compounds (VOC) natural gas 0 BACT‐PSD 0
GE LMS‐100 combustion turbines, MMBTU/ Volatile Organic Oxidation catalyst; Limit the time in startup or

simple cycle with water injection 15.11 natural gas 1690 H Compounds (VOC) shutdown. 0 BACT‐PSD 0
(GE) FRAME 7EA
COMBUSTION TURBINES
(CTS) WITH A NOMINAL THE USE OF PROCESS FUEL GAS AND PIPELINE 4.8 LBS/SHUTDOWN EVENT. LIMITS ARE TOTAL
NATURAL NET 87.2 MEGAWATT (MW) Volatile Organic NATURAL GAS, GOOD COMBUSTION PRACTICES, PPMVD @ 15% 3‐HOUR BLOCK AVERAGE, FOR BOTH FRAME 7 CTS PER STARTUP OR
2 COMBUSTION TURBINES 15.11 GAS 130 MW RATED CAPACITY, COUPLED Compounds (VOC) AND USE OF AN OXIDATION CATALYST 0.7 O2 EXCLUDING SU/SD LAER 101.1 LB/EVENT FOR ALL STARTUPSSHUTDOWN EVENT
AGGREGATE VOC EMISSIONS FROM BOTH
MM HOURLY MAXIMUM 45.24 TONS PER YEAR. STARTUP & SHUTDOWN
TURBINE EXHAUST STACK NO. 1 & NATURAL BTU/H Volatile Organic / STARTUP & OPERATIONS ARE LIMITED TO 520 HOURS PER
NO. 2 15.11 GAS 1900 EACH Compounds (VOC) DRY LOW NOX COMBUSTORS 7 LB/H HOURLY MAXIMUM BACT‐PSD 132 LB/H SHUTDOWN ONLY YEAR.
C17
Natural Gas Fired Simple Cycle Turbine Start up/Shut Down VOC ‐ RBLC Dataset ‐ Relevant data in Red
THROUG
(Startup/Shutdown/
Maintenance/Tuning/Runback) MM Volatile Organic Limit duration of event/hours Limit duration of event/hours
[EQT0019] 15.11 Natural Gas 2201 BTU/hR Limited to 600 hr/yr Compounds (VOC) per year per year
(Startup/Shutdown/
Maintenance/Tuning/Runback) MM Volatile Organic Limit duration of event/hours Limit duration of event/hours
[EQT0020] 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr Compounds (VOC) per year per year
GE LMS‐100 combustion turbines, MMBTU/ Volatile Organic Limit duration of event/hours

simple cycle with water injection 15.11 natural gas 1690 H Compounds (VOC) per year
(GE) FRAME 7EA
COMBUSTION TURBINES
NATURAL NET 87.2 MEGAWATT (MW) Volatile Organic
2 COMBUSTION TURBINES 15.11 GAS 130 MW RATED CAPACITY, COUPLED Compounds (VOC) 50.55 4.80 0.39 0.04
MM
TURBINE EXHAUST STACK NO. 1 & NATURAL BTU/H Volatile Organic
NO. 2 15.11 GAS 1900 EACH Compounds (VOC) 132.00 132.00 0.07 0.07
C18
Natural Gas Fired Simple Cycle Turbine Start up/Shut Down PM ‐ RBLC Dataset ‐ Relevant data in Red
THROUG EMISSION_LIMIT_2
PROCCESS_ PRIMARY_F THROUGH HPUT_U EMISSION_LIMIT_ EMISSION_LIMIT EMISSION_LIMIT_1_AVG_ CASE‐BY‐ EMISSION_LIMIT_ EMISSION_LIMIT _AVGERAGE_TIME_
PROCESS_NAME TYPE UEL PUT NIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION 1 _1_UNIT TIME_CONDITION CASE_BASIS 2 _2_UNIT CONDITION POLLUTANT_COMPLIANCE_NOTES
Two simple cycle
combustion turbines used Emission 1 (natural gas): 0.0038 lb/mmbtu*
for peaking purposes and Emission 2 (ULSD): 0.0150 lb/mmbtu* *During
fired primarily on natural an hour that includes a startup, the particulate
Two Simple Cycle Combustion gas with ULSD as a Particulate matter, 3‐HOUR BLOCK emissions of the turbine shall not exceed 7.5
Turbines 15.11 Natural Gas 190 MW secondary fuel. filterable (FPM) turbine design and good combustion practices 0.0038 LB/MMBTU 3‐HOUR BLOCK AVERAGE BACT‐PSD 0.015 LB/MMBTU AVERAGE lb/hr (natural gas) and 32.2 lb/hr (ULSD).
Also for PM‐10 EPA Method 201/201A or 202
0.005 lb/mmBtu without duct firing 0.006
lb/mmBtu with duct firing Applies to all
Particulate matter, good combustion practiced and pipeline quality operating loads, except during startup and
Turbines and duct burners 15.11 natural gas 228 MW filterable (FPM) natural gas 0.005 LB/MMBTU 1 H BACT‐PSD 0 shutdown.
CTG01 SUSD ‐ Simple‐Cycle Particulate matter,
Combustion Turbine 1 MM total < 2.5 µ Good combustion practices and the use of low sulfur
(Startup/Shutdown/ 15.11 Natural Gas 2201 BTU/hr Limited to 600 hr/yr (TPM2.5) fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM BACT‐PSD 0
Combustion Turbine 1 MM Particulate matter, Good combustion practices and the use of low sulfur
(Startup/Shutdown/ 15.11 Natural Gas 2201 BTU/hr Limited to 600 hr/yr total < 10 µ (TPM10) fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM BACT‐PSD 0
Combustion Turbine 2 MM total < 2.5 µ Good combustion practices and the use of low sulfur
(Startup/Shutdown/ 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr (TPM2.5) fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM BACT‐PSD 0
Combustion Turbine 2 MM Particulate matter, Good combustion practices and the use of low sulfur
(Startup/Shutdown/ 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr total < 10 µ (TPM10) fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM BACT‐PSD 0
GE LMS‐100 combustion turbines, MM Particulate matter, Utilize only natural gas or ULSD fuel; Limit the time in 6‐HR AVERAGE ON

simple cycle with water injection 15.11 natural gas 1690 BTU/hr total < 10 µ (TPM10) startup or shutdown. 9.1 LB/H TOTAL PM 6‐HR AVERAGE ON NG BACT‐PSD 22.7 LB/H TOTAL PM ULSD
AGGREGATE PM2.5 EMISSIONS FROM BOTH
Particulate matter, HOURLY MAXIMUM 30.94 TONS PER YEAR. STARTUP & SHUTDOWN
TURBINE EXHAUST STACK NO. 1 & NATURAL MM total < 2.5 µ / STARTUP & OPERATIONS ARE LIMITED TO 520 HOURS PER
NO. 2 15.11 GAS 1900 BTU/hr (TPM2.5) USE OF PIPELINE NATURAL GAS 17 LB/H HOURLY MAXIMUM BACT‐PSD 17 LB/H SHUTDOWN ONLY YEAR.
AGGREGATE PM10 EMISSIONS FROM BOTH
HOURLY MAXIMUM 30.94 TONS PER YEAR. STARTUP & SHUTDOWN
TURBINE EXHAUST STACK NO. 1 & NATURAL MM Particulate matter, / STARTUP & OPERATIONS ARE LIMITED TO 520 HOURS PER
NO. 2 15.11 GAS 1900 BTU/hr total < 10 µ (TPM10) USE OF PIPELINE NATURAL GAS 17 LB/H HOURLY MAXIMUM BACT‐PSD 17 LB/H SHUTDOWN ONLY YEAR.
C19
Natural Gas Fired Simple Cycle Turbine Start up/Shut Down PM ‐ RBLC Dataset ‐ Relevant data in Red
THROUG
Two simple cycle
combustion turbines used
for peaking purposes and
fired primarily on natural
Two Simple Cycle Combustion gas with ULSD as a Particulate matter,
Turbines 15.11 Natural Gas 190 MW secondary fuel. filterable (FPM) 7.5 0.0395
Particulate matter,
Turbines and duct burners 15.11 natural gas 228 MW filterable (FPM) ‐ ‐
Combustion Turbine 1 MM total < 2.5 µ
(Startup/Shutdown/ 15.11 Natural Gas 2201 BTU/hr Limited to 600 hr/yr (TPM2.5) 6.3 0.00286 0.00286
Combustion Turbine 1 MM Particulate matter,
(Startup/Shutdown/ 15.11 Natural Gas 2201 BTU/hr Limited to 600 hr/yr total < 10 µ (TPM10) 6.3 0.00286 0.00286
Combustion Turbine 2 MM total < 2.5 µ
(Startup/Shutdown/ 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr (TPM2.5) 6.3 0.00286 0.00286
Combustion Turbine 2 MM Particulate matter,
(Startup/Shutdown/ 15.11 Natural Gas 2201 BTU/hr limited to 600 hr/yr total < 10 µ (TPM10) 6.3 0.00286 0.00286
GE LMS‐100 combustion turbines, MM Particulate matter, Limit duration of event/hours

simple cycle with water injection 15.11 natural gas 1690 BTU/hr total < 10 µ (TPM10) per year ‐ ‐ ‐
Particulate matter,
TURBINE EXHAUST STACK NO. 1 & NATURAL MM total < 2.5 µ
NO. 2 15.11 GAS 1900 BTU/hr (TPM2.5) 17 0.00895 0.00895
TURBINE EXHAUST STACK NO. 1 & NATURAL MM Particulate matter,

NO. 2 15.11 GAS 1900 BTU/hr total < 10 µ (TPM10) 17 0.00895 0.00895
C20
Natural Gas Fired in‐line Fuel Gas Heater NOX ‐ RBLC Dataset
PROCCESS_ THROUGHPUT_U EMISSION_LIMIT_1_ EMISSION_LIMIT_1_AVG_T
PROCESS_NAME TYPE PRIMARY_FUEL THROUGHPUT NIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1 UNIT IME_CONDITION
A natural gas‐fired 3.8
MMBTU/H heat input HP fuel
EUFUELHTR2: Natural gas fired fuel heater 13.31 Natural gas 3.8 MMBTU/H heater. Nitrogen Oxides (NOx) Low NOx burner 0.14 LB/HR HOURLY
One (1) indirect fuel‐gas EXCLUDES STARTUP,
heater, rated at 2 mmBtu/hr SHUTDOWN &
Indirect fuel‐gas heater 13.31 2 mmBTU/hr heat input, which shall only Nitrogen Oxides (NOx) 0.2 LB/HR MALFUNCTION
Two identical Fuel Gas Heaters;
15.0 MMBtu/hr natural gas‐
Fuel Gas Heaters (2 identical, P007 and P008) 13.31 Natural gas 15 MMBTU/H fired fuel gas heater with low‐ Nitrogen Oxides (NOx) Low‐NOx gas burner 0.3 LB/HR
Reactor Charge Heater ‐ 53B001 13.31 Natural Gas 10.1 MMBTU/HR Nitrogen Oxides (NOx) Ultra‐Low NOx Burners (ULNB) 0.4 LB/HR HOURLY MAXIMUM
One natural gas‐fired dew
point heater for warming the
Fuel pre‐heater (EUFUELHTR) 13.31 natural gas 3.7 MMBTU/H natural gas fuel (EUFUELHTR). Nitrogen Oxides (NOx) Good combustion practices. 0.55 LB/HR TEST PROTOCOL
One natural gas fired dew point
heater for warming the natural TEST PROTOCOL WILL
EUFUELHTR (Fuel pre‐heater) 13.31 Natural gas 3.7 MMBTU/H gas fuel (EUFUELHTR). Nitrogen Oxides (NOx) Good combustion practices. 0.55 LB/HR SPECIFY AVG TIME.
Startup boiler, natural gas fired
with maximum heat input of Low‐NOX burners, good combustion practices and
Startup boiler (B001) 13.31 Natural gas 15.17 MMBTU/H 15.17 MMBtu/hr. Nitrogen Oxides (NOx) the use of natural gas 0.634 LB/HR
EUFUELHTR1: Natural gas fired fuel heater 13.31 Natural gas 20.8 MMBTU/H heater. Nitrogen Oxides (NOx) Low NOx burner 0.75 LB/HR HOURLY
Recycle Gas Heater ‐ 51B002A 13.31 Natural Gas 33 MMBTU/HR Nitrogen Oxides (NOx) Ultra‐Low NOx Burners (ULNB) 1.3 LB/HR HOURLY MAXIMUM
Recycle Gas Heater ‐ 51B002B 13.31 Natural Gas 33 MMBTU/HR Nitrogen Oxides (NOx) Ultra‐Low NOx Burners (ULNB) 1.3 LB/HR HOURLY MAXIMUM
Recycle Gas Heater ‐ 51B002C 13.31 Natural Gas 33 MMBTU/HR Nitrogen Oxides (NOx) Ultra‐Low NOx Burners (ULNB) 1.3 LB/HR HOURLY MAXIMUM
Recycle Gas Heater ‐ 51B002D 13.31 Natural Gas 33 MMBTU/HR Nitrogen Oxides (NOx) Ultra‐Low NOx Burners (ULNB) 1.3 LB/HR HOURLY MAXIMUM
Recycle Gas Heater ‐ 51B002E 13.31 Natural Gas 33 MMBTU/HR Nitrogen Oxides (NOx) Ultra‐Low NOx Burners (ULNB) 1.3 LB/HR HOURLY MAXIMUM
NATURAL GAS SPACE HEATERS ‐ 14 UNITS (ID 17) 13.31 NATURAL GAS 20.89 MMBTU/H Nitrogen Oxides (NOx) 1.99 LB/HR

Three identical Ladle dryers /
preheaters, natural gas fired Good combustion practices and the use of natural
Ladle Preheaters (P002, P003 and P004) 13.31 Natural gas 15 MMBTU/H with maximum heat input of Nitrogen Oxides (NOx) gas 2.12 LB/HR
Regeneraton Heater ‐ 51B001 13.31 Natural Gas 61 MMBTU/HR Nitrogen Oxides (NOx) Ultra‐Low NOx Burners (ULNB) 2.44 LB/HR HOURLY MAXIMUM

Two natural gas fired dew
FGFUELHTR (Two fuel pre‐heaters identified as point heaters for warming the
EUFUELHTR1 & EUFUELHTR2) 13.31 Natural gas 27 MMBTU/H natural gas fuel (EUFUELHTR1 Nitrogen Oxides (NOx) Good combustion practices. 2.65 LB/HR HOURLY; EACH UNIT
FUEL GAS HEATER (H2O BATH) 13.31 18.8 MMBTU/H Nitrogen Oxides (NOx) 2.7 LB/HR
EQT0028 ‐ PACOL STARTUP HEATER H‐202 13.31 natural gas 21 MMBTU/H Nitrogen Oxides (NOx) low nox burners 2.71 LB/HR HOURLY MAXIMUM
SHIFT REACTOR STARTUP HEATER 13.31 NATURAL GAS 34.2 MMBTU/H Nitrogen Oxides (NOx) GOOD DESIGN AND PROPER OPERATION 3.35 LB/HR MAXIMUM
GASIFIER STARTUP PREHEATER BURNERS (5) 13.31 NATURAL GAS 35 MMBTU/H Nitrogen Oxides (NOx) GOOD DESIGN AND PROPER OPERATION 3.85 LB/HR MAXIMUM (EACH)
METHANATION STARTUP HEATERS 13.31 NATURAL GAS 56.9 MMBTU/H Nitrogen Oxides (NOx) GOOD DESIGN AND PROPER OPERATION 5.58 LB/HR MAXIMUM
C21
EQT0027 ‐ PACOL CHARGE HEATER H‐201 13.31 Natural Gas 87.3 MMBTU/H Nitrogen Oxides (NOx) Low NOX Burners 7.15 LB/HR HOURLY MAXIMUM
Good combustion control (i.e., high temperatures,
sufficient excess air, sufficient residence times, and
Startup Heater (B001) 13.31 Natural gas 100 MMBTU/H 100 mmBtu/hr Startup Heater Nitrogen Oxides (NOx) god air/fuel mixing). 10 LB/HR
STARTUP HEATER EU‐002 13.31 NATURAL GAS 70 MMBTU/HR Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 12.611 LB/HR 3 HOUR AVERAGE

HEATER IS PERMITTED TO GOOD COMBUSTION PRACTICES: PROPER DESIGN
OPERATE 500 HOURS PER OF BURNER AND FIREBOX COMPONENTS;
AMMONIA START‐UP HEATER (102‐B) 13.31 NATURAL GAS 59.4 MM BTU/HR YEAR. Nitrogen Oxides (NOx) MAINTAINING THE PROPER AIR‐TO‐FUEL RATIO, 14.65 LB/HR HOURLY MAXIMUM
Heater 13.31 natural gas 10 MMBTU/H Nitrogen Oxides (NOx) low‐NOx burners 0.01 LB/MMBTU
Inlet Air Heater (EP06) 13.31 Natural Gas 16.1 MMBTU/H Nitrogen Oxides (NOx) Ultra Low‐NOx Burners 0.012 LB/MMBTU 3‐HOUR AVERAGE
Inlet Air Heater (EP07) 13.31 Natural Gas 16.1 MMBTU/H Nitrogen Oxides (NOx) Ultra Low NOx Burners 0.012 LB/MMBTU 3‐HOUR AVERAGE
dew point heater 13.31 natural gas 13.32 mmBtu/hr Nitrogen Oxides (NOx) 0.013 LB/MMBTU 3‐HOUR AVERAGE

THE TWO UNITS ARE
WATER HEATERS ‐ UNITS NY037 AND NY038 AT NEW IDENTICAL RBI FUTURA III LOW‐NOX BURNERS AND GOOD COMBUSTION
YORK ‐ NEW YORK 13.31 NATURAL GAS 2 MMBTU/H WATER HEATERS.THE Nitrogen Oxides (NOx) PRACTICES 0.025 LB/MMBTU
LOW NOX BURNERS WITH FLUE GAS
HOT OIL HEATER S38 13.31 NATURAL GAS 84 MMBTU/H Nitrogen Oxides (NOx) RECIRCULATION 0.03 LB/MMBTU
SCR, LOW NOX BURNERS, AND COMBUSTION OF
PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Nitrogen Oxides (NOx) CLEAN FUEL AND GOOD COMBUSTION PRACTICES 0.035 LB/MMBTU
heater 13.31 natural gas 5.5 MMBTU/H Nitrogen Oxides (NOx) 0.036 LB/MMBTU 1 HOUR
heaters (5) 13.31 natural gas 24.3 MMBTU/H Nitrogen Oxides (NOx) ultra low NOx burners 0.036 LB/MMBTU
Heaters 13.31 natural gas 45 MMBTU/H Nitrogen Oxides (NOx) ultra low NOx burners 0.036 LB/MMBTU
HEATERS 13.31 NATL GAS 31 BTU/HR Nitrogen Oxides (NOx) LOW NOX BURNERS, CLEAN FUEL 0.04 LB/MMBTU
THERE ARE TO BE TWO
REGENERATION HEATERS 13.31 NATURAL GAS 5.61 MMBTUH IDENTICAL HEATERS. Nitrogen Oxides (NOx) LOW‐NOx BURNERS 0.045 LB/MMBTU 3‐HR
PROCESS PERTAINS TO TWO(2)
HOT OIL HEATER 13.31 NATURAL GAS 17.4 MMBTUH IDENTICAL HEATERS. Nitrogen Oxides (NOx) LOW‐NOx BURNERS. 0.045 LB/MMBTU 3‐HR
Residue gas Hot Oil Heaters: 60 MMBtu/hr;
equivalent to Regeneration Heaters: 36
Hot Oil Heaters and Regeneration Heaters 13.31 natural gas 60 MMBTU/H MMBtu/hr Nitrogen Oxides (NOx) low NOx burners 0.045 LB/MMBTU
C22
(a) Six (6) Sterling TF‐400
natural gas‐fired space heaters, UNITS 1‐6, COMBUSTING
Space Heaters 13.31 0 identified as HTR 1 through 6, Nitrogen Oxides (NOx) 0.05 LB/MMBTU NATURAL GAS
One natural gas‐fired thermal
oil system for thermally fused Good design and combustion practices, low NOx TEST PROTOCOL SHALL
EUFLTOS1 in FGTOH 13.31 Natural gas 10.2 MMBTU/H lamination lines rated at 10.2 Nitrogen Oxides (NOx) burners. 0.05 LB/MMBTU SPECIFY
GASIFICATION PREHEATER 2 13.31 NATURAL GAS 21 MMBTU/H 500 HOURS OF OPERATION Nitrogen Oxides (NOx) LOW NOX BURNERS 0.05 LB/MMBTU HOURLY
One natural gas fired thermal
EUFLTOS1 in FGTOH (Thermal Oil System for Thermally oil system for thermally fused Low NOx burners and good design and combustion TEST PROTOCOL WILL
Fused Lamination Lines) 13.31 Natural gas 34 MMBTU/H lamination lines rated at 10.2 Nitrogen Oxides (NOx) practices. 0.05 LB/MMBTU SPECIFY AVG TIME
oil heater for press and sifter Low NOx burners and good design and combustion TEST PROTOCOL WILL
EUTOH (In FGTOH)‐‐Thermal Oil Heater 13.31 Natural gas 34 MMBTU/H rated at 34 MMBTU/H fuel Nitrogen Oxides (NOx) practices. 0.05 LB/MMBTU SPECIFY AVG TIME
oil heater for press and sifter Good design and combustion practices, Low NOx TEST PROTOCOL SHALL
EUTOH in FGTOH 13.31 Natural gas 38 MMBTU/H rated at 38 MMBTU/hr fuel Nitrogen Oxides (NOx) burners. 0.05 LB/MMBTU SPECIFY
Reboiler (dehydrator with reboiler) 13.31 natural gas 4.8 MMBTU/H 4.8 MMBTU/H reboiler Nitrogen Oxides (NOx) 0.098 LB/MMBTU TEST METHOD
Numerous gas‐fired heaters
will be installed. The
Heaters (Gas‐Fired) 13.31 Natural Gas 0 application requested that the Nitrogen Oxides (NOx) Natural Gas Fuel 0.1 LB/MMBTU
heater 13.31 natural gas 3 MMBTU/H Nitrogen Oxides (NOx) 0.1 LB/MMBTU 1 HOUR
two small heaters (~3 and 5
2 Heaters 13.31 natural gas 5 MMBTU/H MMBtu/hr) Nitrogen Oxides (NOx) 0.1 LB/MMBTU
Two natural gas heaters 13.31 Natural gas 9.9 MMBtu/hr Nitrogen Oxides (NOx) Manufacturer certification 0.1 LB/MMBTU DESIGN VALUE
Fueled only with gas. May Must have NOx emission design value less than 0.1
Two natural gas heaters 13.31 Natural gas 10 MMBtu/hr operate one heater at a time. Nitrogen Oxides (NOx) lb/MMBtu 0.1 LB/MMBTU
fuel gas heater 13.31 natural gas 18 MMBTU/H Nitrogen Oxides (NOx) 0.1 LB/MMBTU

Four preheaters for 2
production test cells for OPERATING AT 60% TO
4 Indirect‐Fired Air Preheaters 13.31 Natural gas 0 aviation engines and turbines Nitrogen Oxides (NOx) 0.14 LB/MMBTU 100% CAPACITY
Propane, field gas,
Heater 13.31 PUC natural gas 3 MMBTU/H Nitrogen Oxides (NOx) Low NOx burner 12 PPMVD@3% O2 40 MINUTES
Heaters 13.31 Natural Gas 48 MMBTU/H Nitrogen Oxides (NOx) Flue Gas Recirculation 7.62 TON YEAR
C23
Natural Gas Fired in‐line Fuel Gas Heater CO ‐ RBLC Dataset
EUFUELHTR2: Natural gas fired fuel heater 13.31 Natural gas 3.8 MMBTU/H heater. Carbon Monoxide Good combustion controls 0.14 LB/HR HOURLY
One (1) indirect fuel‐gas EXCLUDES STARTUP,
heater, rated at 2 mmBtu/hr SHUTDOWN &
Indirect fuel‐gas heater 13.31 2 mmBTU/hr heat input, which shall only Carbon Monoxide 0.16 LB/HR MALFUNCTION
FUEL GAS HEATER (H2O BATH) 13.31 18.8 MMBTU/H Carbon Monoxide 0.39 LB/HR

point heater for warming the
Fuel pre‐heater (EUFUELHTR) 13.31 natural gas 3.7 MMBTU/H natural gas fuel (EUFUELHTR). Carbon Monoxide Good combustion practices 0.41 LB/HR TEST PROTOCOL
One natural gas fired dew
point heater for warming the TEST PROTOCOL WILL
EUFUELHTR (Fuel pre‐heater) 13.31 Natural gas 3.7 MMBTU/H natural gas fuel (EUFUELHTR). Carbon Monoxide Good combustion practices. 0.41 LB/HR SPECIFY AVG TIME
EUFUELHTR1: Natural gas fired fuel heater 13.31 Natural gas 20.8 MMBTU/H heater. Carbon Monoxide Good combustion controls. 0.77 LB/HR HOURLY
Combustion controls (proper burner design and
Reactor Charge Heater ‐ 53B001 13.31 Natural Gas 10.1 MMBTU/HR Carbon Monoxide operation using natural gas) 0.83 LB/HR HOURLY MAXIMUM
Two identical Fuel Gas Heaters;
15.0 MMBtu/hr natural gas‐
Fuel Gas Heaters (2 identical, P007 and P008) 13.31 Natural gas 15 MMBTU/H fired fuel gas heater with low‐ Carbon Monoxide Combustion control 0.83 LB/HR
Nitric Acid Preheaters No. 1 (EU 401, EUG 4) 13.31 Natural Gas 20 MMBTUH Carbon Monoxide good combustion practices 1.65 LB/HR 1‐HR, 8‐HR
Nitric Acid Preheater No3 (EU 402, EUG 4) 13.31 Natural Gas 20 mmbtu/h Carbon Monoxide good combustion 1.65 LB/HR 1‐HR/8‐HR

THE NITRIC ACID PLANT
PREHEATERS ARE USED TO
NITRIC ACID PREHEATERS #1, #3, AND #4 13.31 NATURAL GAS 20 MMBTU/H PREHEAT THE PROCESS AIR Carbon Monoxide GOOD COMBUSTION PRACTICES. 1.65 LB/HR 1‐HOUR/8‐HOUR
NATURAL GAS SPACE HEATERS ‐ 14 UNITS (ID 17) 13.31 NATURAL GAS 20.89 MMBTU/H Carbon Monoxide 1.67 LB/HR
GASIFIER STARTUP PREHEATER BURNERS (5) 13.31 NATURAL GAS 35 MMBTU/H Carbon Monoxide GOOD DESIGN AND PROPER OPERATION 1.96 LB/HR MAXIMUM (EACH)

Two natural gas fired dew
FGFUELHTR (Two fuel pre‐heaters identified as point heaters for warming the
EUFUELHTR1 & EUFUELHTR2) 13.31 Natural gas 27 MMBTU/H natural gas fuel (EUFUELHTR1 Carbon Monoxide Good combustion practices. 2.22 LB/HR HOURLY; EACH UNIT
STARTUP HEATER EU‐002 13.31 NATURAL GAS 70 MMBTU/HR Carbon Monoxide GOOD COMBUSTION PRACTICES 2.556 LB/HR 3 HOUR AVERAGE
Recycle Gas Heater ‐ 51B002A 13.31 Natural Gas 33 MMBTU/HR Carbon Monoxide operation using natural gas) 2.67 LB/HR HOURLY MAXIMUM
Recycle Gas Heater ‐ 51B002B 13.31 Natural Gas 33 MMBTU/HR Carbon Monoxide operation using natural gas) 2.67 LB/HR HOURLY MAXIMUM
Recycle Gas Heater ‐ 51B002C 13.31 Natural Gas 33 MMBTU/HR Carbon Monoxide operation using natural gas) 2.67 LB/HR HOURLY MAXIMUM
Recycle Gas Heater ‐ 51B002D 13.31 Natural Gas 33 MMBTU/HR Carbon Monoxide operation using natural gas) 2.67 LB/HR HOURLY MAXIMUM
Recycle Gas Heater ‐ 51B002E 13.31 Natural Gas 33 MMBTU/HR Carbon Monoxide operation using natural gas) 2.67 LB/HR HOURLY MAXIMUM
SHIFT REACTOR STARTUP HEATER 13.31 NATURAL GAS 34.2 MMBTU/H Carbon Monoxide GOOD DESIGN AND PROPER OPERATION 2.82 LB/HR MAXIMUM
HEATER IS PERMITTED TO GOOD COMBUSTION PRACTICES: PROPER DESIGN
OPERATE 500 HOURS PER OF BURNER AND FIREBOX COMPONENTS;
AMMONIA START‐UP HEATER (102‐B) 13.31 NATURAL GAS 59.4 MM BTU/HR YEAR. Carbon Monoxide MAINTAINING THE PROPER AIR‐TO‐FUEL RATIO, 2.97 LB/HR HOURLY MAXIMUM
C24
METHANATION STARTUP HEATERS 13.31 NATURAL GAS 56.9 MMBTU/H Carbon Monoxide GOOD DESIGN AND PROPER OPERATION 4.69 LB/HR MAXIMUM
Regeneraton Heater ‐ 51B001 13.31 Natural Gas 61 MMBTU/HR Carbon Monoxide operation using natural gas) 5 LB/HR HOURLY MAXIMUM
THE THERMAL OIL HEATER IS A TUNE‐UPS AND INSPECTIONS WILL BE PERFORMED
STAND‐ALONE NATURAL GAS AS OUTLINED THE GOOD MANAGEMENT PRACTICE
75 MILLION BTU/HR BACKUP THERMAL OIL HEATER 13.31 NATURAL GAS 75 MMBTU/H FIRED HEATER USED TO Carbon Monoxide PLAN. 6 LB/HR
good combustion control (i.e., high temperatures,
sufficient excess air, sufficient residence times, and
Startup Heater (B001) 13.31 Natural gas 100 MMBTU/H 100 mmBtu/hr Startup Heater Carbon Monoxide god air/fuel mixing) 8.24 LB/HR
Heater permitted for 96 hours Good combustion practices; proper engineering
No. 6 Ammonia Plant Start‐up Heater (4‐13, EQT 158) 13.31 Natural Gas 94.5 MM Btu/hr per year of operation. Carbon Monoxide design 7.78 LB/HR HOURLY MAXIMUM
Limited to 5.76 MMCF of AVERAGE OF THREE (3)
Startup Heater 13.31 natural gas 58.8 MMBTU/H natural gas/yr Carbon Monoxide good operating practices & use of natural gas 0.0194 LB/MMBTU STACK TEST RUNS
HOT OIL HEATER S38 13.31 NATURAL GAS 84 MMBTU/H Carbon Monoxide GOOD COMBUSTION PRACTICES 0.02 LB/MMBTU

THE TWO UNITS ARE
WATER HEATERS ‐ UNITS NY037 AND NY038 AT NEW IDENTICAL RBI FUTURA III LIMITING THE FUEL TO NATURAL GAS ONLY AND
YORK ‐ NEW YORK 13.31 NATURAL GAS 2 MMBTU/H WATER HEATERS.THE Carbon Monoxide GOOD COMBUSTION PRACTICES 0.035 LB/MMBTU
natural gas‐fired space WHEN COMBUSTING
Space Heaters 13.31 0 heaters, identified as HTR 1 Carbon Monoxide 0.038 LB/MMBTU NATURAL GAS
heater 13.31 natural gas 3 MMBTU/H Carbon Monoxide 0.04 LB/MMBTU 1 HOUR
dew point heater 13.31 natural gas 13.32 mmBtu/hr Carbon Monoxide 0.041 LB/MMBTU 3‐HOUR AVERAGE
GOOD COMBUSTION PRACTICES AND USE OF THREE ONE‐HOUR TEST
CRACKING FURNACES A‐D 13.31 90 MMBTU/H EA. Carbon Monoxide NATURAL GAS AS FUEL 0.046 LB/MMBTU AVERAGE
fuel gas heater 13.31 natural gas 18 MMBTU/H Carbon Monoxide 0.054 LB/MMBTU
heater 13.31 natural gas 5.5 MMBTU/H Carbon Monoxide 0.08 LB/MMBTU 1 HOUR

Five 12 MMBTU/H reactor
heaters, equipped with low‐
Reactor Heater, 5 13.31 NATURAL GAS 12 MMBTU/H NOx burners Carbon Monoxide 0.08 LB/MMBTU 3‐HR AVERAGE
13 MMBTU/H methanol‐to‐
gasoline regeneration heater,
Regeneration Heater, methanol to gasoline 13.31 NATURAL GAS 13 MMBTU/H equipped with low‐NOx burner Carbon Monoxide 0.08 LB/MMBTU 3‐HR AVERAGE
Inlet Air Heater (EP06) 13.31 Natural Gas 16.1 MMBTU/H Carbon Monoxide good combustion practices 0.08 LB/MMBTU 3‐HOUR AVERAGE
C25
GASIFICATION PREHEATER 2 13.31 NATURAL GAS 21 MMBTU/H 500 HOURS OF OPERATION Carbon Monoxide GOOD COMBUSTION PRACTICES 0.08 LB/MMBTU HOURLY
oil system for thermally fused TEST PROTOCOL SHALL
EUFLTOS1 in FGTOH 13.31 Natural gas 10.2 MMBTU/H lamination lines rated at 10.2 Carbon Monoxide Good design and operation. 0.082 LB/MMBTU SPECIFY
EUFLTOS1 in FGTOH (Thermal Oil System for Thermally oil system for thermally fused TEST PROTOCOL WILL
Fused Lamination Lines) 13.31 Natural gas 34 MMBTU/H lamination lines rated at 10.2 Carbon Monoxide Good design and operation 0.082 LB/MMBTU SPECIFY AVG TIME
oil heater for press and sifter TEST PROTOCOL WILL
EUTOH (In FGTOH)‐‐Thermal Oil Heater 13.31 Natural gas 34 MMBTU/H rated at 34 MMBTU/H fuel Carbon Monoxide Good design and operation 0.082 LB/MMBTU SPECIFY AVG TIME.
oil heater for press and sifter TEST PROTOCOL SHALL
EUTOH in FGTOH 13.31 Natural gas 38 MMBTU/H rated at 38 MMBTU/hr fuel Carbon Monoxide Good design and operation. 0.082 LB/MMBTU SPECIFY
Two thermal oxidizers to burn
acid gas from natural gas Acid Natural Gas / Clean Fuel, good combustion
Thermal Oxidizer 13.31 NATL GAS 71.3 MMBTU/HR Gas Removal Units for Trains 1 Carbon Monoxide practices. 0.082 LB/MMBTU
THERE ARE TO BE TWO
REGENERATION HEATERS 13.31 NATURAL GAS 5.61 MMBTUH IDENTICAL HEATERS. Carbon Monoxide GOOD COMBUSTION PRACTICES. 0.0824 LB/MMBTU 3‐HR
PROCESS PERTAINS TO TWO(2)
HOT OIL HEATER 13.31 NATURAL GAS 17.4 MMBTUH IDENTICAL HEATERS. Carbon Monoxide Efficient design and combustion. 0.0824 LB/MMBTU 3‐HR
COMBUSTION OF NATURAL GAS AND GOOD
FURNACES SN‐40 AND SN‐42, DECARBURIZING LINE 13.31 NATURAL GAS 22 MMBTU/H Carbon Monoxide COMBUSTION PRACTICE 0.0824 LB/MMBTU
COMBUSTION OF NATURAL GAS AND GOOD
PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Carbon Monoxide COMBUSTION PRACTICE 0.0824 LB/MMBTU
will be installed. The
Heaters (Gas‐Fired) 13.31 Natural Gas 0 application requested that the Carbon Monoxide Natural Gas Fuel. 0.084 LB/MMBTU
production test cells for
4 Indirect‐Fired Air Preheaters 13.31 Natural gas 0 aviation engines and turbines Carbon Monoxide 0.15 LB/MMBTU
heaters (5) 13.31 natural gas 24.3 MMBTU/H Carbon Monoxide clean fuel and good combustion practices 50 PPMVD @ 3% O2 ANNUAL
Heaters 13.31 natural gas 45 MMBTU/H Carbon Monoxide clean fuel and good combustion practices 50 PPMVD @ 3% O2 ANNUAL
two small heaters (~3 and 5
2 Heaters 13.31 natural gas 5 MMBTU/H MMBtu/hr) Carbon Monoxide 100 PPMVD @ 3% O2 @3% O2
Heater 13.31 natural gas 10 MMBTU/H Carbon Monoxide 100 PPMVD @ 3% O2 @3% O2

Residue gas Hot Oil Heaters: 60 MMBtu/hr;
equivalent to Regeneration Heaters: 36 Good combustion practices and firing of residue gas
Hot Oil Heaters and Regeneration Heaters 13.31 natural gas 60 MMBTU/H MMBtu/hr Carbon Monoxide with low carbon content 50 PPMVD @ 3% O2
Heaters 13.31 Natural Gas 48 MMBTU/H Carbon Monoxide Best combustion practices 17.39 TON YEAR
C26
good engineering design and practices and use of
WSA Preheat Burners 13.31 Natural Gas 0 Carbon Monoxide clean fuels 0
Heaters 13.31 Natural Gas 3 MMBTU/H Carbon Monoxide Good Combustion Practices 0
Regenerative Heaters 13.31 natural gas 7.37 mm btu/hr Carbon Monoxide good combustion practices 0
Heaters 13.31 Natural Gas 10 MMBTU/H Carbon Monoxide Good combustion Practices 0
Heaters 13.31 Natural Gas 17 MMBTU/H Carbon Monoxide Good Combustion Practices 0
MM BTU/hr good engineering practices, good combustion
Gasifier Start‐up Preheat Burners 13.31 Natural gas 23 (each) Carbon Monoxide technology, and use of clean fuels 0
NATURAL GAS FIRED, LOW‐
NOX BURNER USED IN THE GOOD COMBUSTION PRACTICES AND NATURAL GAS
FACE PRIMARY DRYER 13.31 NATURAL GAS 45 MMBTU/H PRIMARY FACE DRYER OF AN Carbon Monoxide AS FUEL 0
NATURAL GAS FIRED, LOW‐
NOX BURNER USED IN THE GOOD COMBUSTION PRACTICES AND NATURAL GAS
CORE PRIMARY DRYER 13.31 NATURAL GAS 45 MMBTU/H PRIMARY CORE DRYER OF AN Carbon Monoxide AS FUEL 0
C27
Natural Gas Fired in‐line Fuel Gas Heater VOC ‐ RBLC Dataset
PROCCESS_ THROUGHPUT_U EMISSION_LIMIT_1_ EMISSION_LIMIT_1_AVG_TIME
PROCESS_NAME TYPE PRIMARY_FUEL THROUGHPUT NIT PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1 UNIT _CONDITION
AVERAGE OF THREE (3) STACK
Startup Heater 13.31 natural gas 58.8 MMBTU/H Limited to 5.76 MMCF of natura Volatile Organic Compoundgood operating practices & use of natural gas 0.0014 LB/MMBTU TEST RUNS
Volatile Organic
AUXILIARY BOILER 13.31 Natural Gas 40 MMBTU/H Compounds (VOC) 0.0015 LB/MMBTU
Volatile Organic
Auxiliary boiler 13.31 natural gas 60 MMBTU/H Limited to 4,500 H/YR Compounds (VOC) good combustion practice 0.0015 LB/MMBTU 1 H
Volatile Organic
Auxiliary Boiler 13.31 natual gas 25.06 MMBtu/h Compounds (VOC) good combustion practices 0.0017 LB/MMBTU 3 HOUR AVERAGE
NATURAL GAS FUEL ONLY,
OPERATION OF LOW‐NOX Volatile Organic EXCLUSIVE USE OF NATURAL GAS, AND GOOD
AUXILLARY BOILER 13.31 NATURAL GAS 93 MMBTU/H BURNER TECHNOLOGY, FLUE Compounds (VOC) COMBUSTION PRACTICES 0.002 LB/MMBTU 3‐HOUR AVERAGE BLOCK
ONE AUXILIARY BOILER WITH EFFICIENT BOILER DESIGN, EXCLUSIVE USE OF
PIPELINE QUALITY ULTRA‐LOW NOX BURNER Volatile Organic PIPELINE QUALITY NATURAL GAS, THE USE OF
AUXILIARY BOILER 13.31 NATURAL GAS 93 MMBTU/H (ULNB) AND FLUE GAS Compounds (VOC) ULTRA‐LOW NOX BURNERS, AND GOOD 0.002 LB/MMBTU 3‐HOUR BLOCK AVERAGE
Volatile Organic Good equipment design and proper combustion
Boilers 13.31 natural gas 25.1 MMBTU/H Compounds (VOC) techniques 0.003 LB/MMBTU NATURAL GAS FIRED
PIPELINE QUALITY NATURAL
GAS FUEL ONLY, OPERATION Volatile Organic EXCLUSIVE USE OF NATURAL GAS, AND GOOD
AUXILIARY BOILER 13.31 NATURAL GAS 42 MMBTU/H OF ULTRA LOW‐NOX BURNER Compounds (VOC) COMBUSTION PRACTICES 0.003 LB/MMBTU 3‐HOUR BLOCK AVERAGE
The four natural gas boilers are
used to generate the hot water Volatile Organic
Four(4) Natural Gas Boilers ‐ 46 MMBtu/hour 13.31 Natural Gas 46 MMBTU/H that is used in the lumber kiln Compounds (VOC) Good Combustion Practice 0.003 LB/MMBTU
Volatile Organic
NATURAL GAS BOILER EU004 13.31 NATURAL GAS 46 MMBTU/H Compounds (VOC) 0.003 LB/MMBTU 3‐HOUR
Volatile Organic
Volatile Organic
NATURAL GAS FUEL ONLY, THE EXCLUSIVE USE OF PIPELINE QUALITY NATURAL
OPERATION OF ULTRA LOW‐ Volatile Organic GAS, LIMITED HOURS OF OPERATION, AND GOOD
AUXILLARY BOILER 13.31 NATURAL GAS 45 MMBTU/H NOX BURNER TECHNOLOGY, Compounds (VOC) COMBUSTION PRACTICES 0.0033 LB/MMBTU 3‐HOUR BLOCK AVERAGE
Volatile Organic
Auxiliary boiler 13.31 natural gas 0 Compounds (VOC) Good combustion practice. 0.0038 LB/MMBTU 1 H
A natural gas‐fired auxiliary
boiler, rated at 61.5 MMBTU/H Volatile Organic
EUAUXBOILER (North Plant): Auxiliary Boilder 13.31 Natural gas 61.5 MMBTU/H (HHV) to facilitate startup of Compounds (VOC) Good combustion practices. 0.004 LB/MMBTU HOURLY
EUAUXBOILER (South Plant): Auxiliary Boiler 13.31 Natural gas 61.5 MMBTU/h (HHV) to facilitate startup of Compounds (VOC) Good combustion practices. 0.004 LB/MMBTU HOURLY
The proposed auxilary boiler
will fire NG exclusively with Volatile Organic
Auxilary Boiler 13.31 Natural Gas 62.04 MCF/hr maximum rated heat input Compounds (VOC) Good combustion practices and FGR 0.004 LB/MMBTU
production test cells for Volatile Organic
4 Indirect‐Fired Air Preheaters 13.31 Natural gas 0 aviation engines and turbines Compounds (VOC) 0.005 LB/MMBTU
Two natural gas heaters, each Volatile Organic
Two natural gas heaters (< 10 MMBtu/hr each) 13.31 Natural gas 9.9 MMBtu/hr less than 10 MMBtu/hr Compounds (VOC) 0.005 LB/MMBTU
Fired only on natural gas
supplied by a public utility. Volatile Organic
Auxillary Boiler 13.31 Natural gas 13.31 MMBtu/hr Limited to 4000 hrs per year on Compounds (VOC) 0.005 LB/MMBTU 30‐DAY ROLLING BASIS
Volatile Organic
Auxiliary boiler 13.31 natural gas 39.8 MMBTU/H Compounds (VOC) Utilize Low‐NOx burners and FGR. 0.005 LB/MMBTU 3‐HR BLOCK AVERAGE
Two (2) natural gas‐fired
FG‐AUXBOILER1‐2; Two (2) natural gas‐fired auxiliary auxiliary boilers. 40 MMBTU/H Volatile Organic
boilers. 13.31 natural gas 40 MMBTU/H each. Fuel restriction = 360.8 Compounds (VOC) Good combustion practices. 0.005 LB/MMBTU TEST PROTOCOL; EACH UNIT.
C28
Shall construct qualifying small
gas combustion units capable Volatile Organic
Auxilary Boiler 13.31 Natural Gas 55.4 MMBtu/hr of reducing nitrogen oxides Compounds (VOC) 0.005 LB/MMBTU
fuel limit of 288.7 million cubic
feet of natural gas per 12‐ Volatile Organic AVERAGE OF 3 ONE‐HOUR
auxiliary boiler 13.31 natural gas 60.1 mmBtu/hr month rolling period Compounds (VOC) 0.005 LB/MMBTU TEST RUNS
The auxiliary boiler will provide
steam to the steam turbine at Volatile Organic
AUXILIARY BOILER 13.31 Natural Gas 66.7 MMBTU/H start‐up and at cold starts to Compounds (VOC) Clean fuel and good combustion practices 0.005 LB/MMBTU
BOTH BOILERS, LABELED AS
B001 AND B002, ARE Volatile Organic
TWO (2) NATURAL GAS AUXILIARY BOILERS 13.31 NATURAL GAS 80 MMBTU/H EQUIPPED WITH LOW NOX Compounds (VOC) GOOD COMBUSTION PRACTICES 0.005 LB/MMBTU 3 HOURS
natural gas‐fired space heaters, Volatile Organic WHEN COMBUSTING NATURAL
Space Heaters 13.31 0 identified as HTR 1 through 6, Compounds (VOC) 0.0053 LB/MMBTU GAS
29.113 MMBtu/hr rated heat Volatile Organic
Boiler No. 2 13.31 Natural Gas 0 input capacity Compounds (VOC) Work Practice Standards 0.0054 LB/MMBTU
THE TWO UNITS ARE
WATER HEATERS ‐ UNITS NY037 AND NY038 AT NEW IDENTICAL RBI FUTURA III Volatile Organic LIMITING THE FUEL TO NATURAL GAS ONLY AND
YORK ‐ NEW YORK 13.31 NATURAL GAS 2 MMBTU/H WATER HEATERS.THE Compounds (VOC) GOOD COMBUSTION PRACTICES 0.0054 LB/MMBTU
Volatile Organic
Reboiler (dehydrator with reboiler) 13.31 natural gas 4.8 MMBTU/H 4.8 MMBTU/H reboiler Compounds (VOC) Thermal oxidizer 0.0054 LB/MMBTU TEST METHOD
Volatile Organic
Refinery Boiler 13.31 Natural Gas 5 MMBTUH Compounds (VOC) Good Combustion 0.0054 LB/MMBTU 3‐HOUR AVG
oil system for thermally fused Volatile Organic TEST PROTOCOL SHALL
EUFLTOS1 in FGTOH 13.31 Natural gas 10.2 MMBTU/H lamination lines rated at 10.2 Compounds (VOC) Good design and operating/combustion practices. 0.0054 LB/MMBTU SPECIFY
Volatile Organic
Commercial/Institutional Boilers (<100 MMBTUH) 13.31 Natural Gas 11.04 MMBTUH Compounds (VOC) 0.0054 LB/MMBTU
UNIT FL01 IS A JOHNSTON
BOILER AT FLAMINGO LAS Volatile Organic
BOILER ‐ UNIT FL01 13.31 NATURAL GAS 14.34 MMBTU/H VEGAS. THIS UNIT MAY Compounds (VOC) FLUE GAS RECIRCULATION 0.0054 LB/MMBTU
UNIT BA01 IS A KEWANEE
BOILER AT BALLY'S LAS VEGAS. Volatile Organic
BOILER ‐ UNIT BA01 13.31 NATURAL GAS 16.8 MMBTU/H UNIT BA01 IS IDENTICAL TO Compounds (VOC) FLUE GAS RECIRCULATION 0.0054 LB/MMBTU
Volatile Organic COMBUSTION OF NATURAL GAS AND GOOD
FURNACES SN‐40 AND SN‐42, DECARBURIZING LINE 13.31 NATURAL GAS 22 MMBTU/H Compounds (VOC) COMBUSTION PRACTICE 0.0054 LB/MMBTU
UNIT CP26 IS A UNILUX BOILER
AT CAESAR'S PALACE. THE Volatile Organic OPERATING IN ACCORDANCE WITH THE
BOILER ‐ UNIT CP26 13.31 NATURAL GAS 24 MMBTU/H UNIT IS ALLOWED TO OPERATE Compounds (VOC) MANUFACTURER'S SPECIFICATION 0.0054 LB/MMBTU
BOILERS SN‐26 AND 27, GALVANIZING LINE 13.31 NATURAL GAS 24.5 MMBTU/H Compounds (VOC) COMBUSTION PRACTICE 0.0054 LB/MMBTU
UNIT BA03 IS A KIWANEE
BOLER AT BALLY'S LAS VEGAS. Volatile Organic OPERATING IN ACCORDANCE WITH THE
BOILER ‐ UNIT BA03 13.31 NATURAL GAS 31.38 MMBTU/H THE ANNUAL OPERATING TIME Compounds (VOC) MANUFACTURER'S SPECIFICATION 0.0054 LB/MMBTU
UNIT CP03 IS A BURNHAM
BOILER AT CAESAR'S PALACE. Volatile Organic OPERATING IN ACCORDANCE WITH THE
BOILER ‐ UNIT CP03 13.31 NATURAL GAS 33.48 MMBTU/H UNITS CP01 THROUGH CP05 Compounds (VOC) MANUFACTURER'S SPECIFICATION 0.0054 LB/MMBTU
EUFLTOS1 in FGTOH (Thermal Oil System for Thermally oil system for thermally fused Volatile Organic TEST PROTOCOL WILL SPECIFY
Fused Lamination Lines) 13.31 Natural gas 34 MMBTU/H lamination lines rated at 10.2 Compounds (VOC) Good design and operating/combustion practices. 0.0054 LB/MMBTU AVG TIME
oil heater for press and sifter Volatile Organic TEST PROTOCOL WILL SPECIFY
EUTOH (In FGTOH)‐‐Thermal Oil Heater 13.31 Natural gas 34 MMBTU/H rated at 34 MMBTU/H fuel Compounds (VOC) Good design and operating/combustion practices. 0.0054 LB/MMBTU AVG TIME
UNIT CP01 IS A HURST BOILER FLUE GAS RECIRCULATION AND OPERATING IN
AT CAESAR'S PALACE. UNIT Volatile Organic ACCORDANCE WITH THE MANUFACTURER'S
BOILER ‐ UNIT CP01 13.31 NATURAL GAS 35.4 MMBTU/H CP01 IS IDENTICAL TO UNIT Compounds (VOC) SPECIFICATION 0.0054 LB/MMBTU
oil heater for press and sifter Volatile Organic TEST PROTOCOL SHALL
EUTOH in FGTOH 13.31 Natural gas 38 MMBTU/H rated at 38 MMBTU/hr fuel Compounds (VOC) Good design and operating/combustion practices. 0.0054 LB/MMBTU SPECIFY
C29
Five (5) Natural Gas‐Fired 50
MMBtu/hr Waste Heat Boilers. Volatile Organic
Five (5) Waste Heat Boilers 13.31 Natural Gas 50 MMBTU/H Installed in 1986. Compounds (VOC) 0.0054 LB/MMBTU 3‐HR AVG
BOILER, PICKLE LINE 13.31 NATURAL GAS 53.7 MMBTU/HR Compounds (VOC) COMBUSTION PRACTICE 0.0054 LB/MMBTU
Two thermal oxidizers to burn
acid gas from natural gas Acid Volatile Organic Natural Gas / Clean Fuel, good combustion
Thermal Oxidizer 13.31 NATL GAS 71.3 MMBTU/HR Gas Removal Units for Trains 1 Compounds (VOC) practices. 0.0054 LB/MMBTU
PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Compounds (VOC) COMBUSTION PRACTICE 0.0054 LB/MMBTU
Volatile Organic
Natural Gas Fired Boilers (3) 13.31 Natural Gas 100 mm btu/hr Compounds (VOC) Good combustion Practices. 0.0054 LB/MMBTU
Volatile Organic
60 MMBTU/HR NATURAL GAS‐FIRED BOILER (ES‐008) 13.31 NATURAL GAS 60 MMBTU/H Compounds (VOC) GOOD COMBUSTION PRACTICES 0.0054 LB/MMBTU
will be installed. The Volatile Organic
Heaters (Gas‐Fired) 13.31 Natural Gas 0 application requested that the Compounds (VOC) Natural Gas Fuel. 0.0055 LB/MMBTU
Good combustion practices, use only natural gas,
Volatile Organic equip boiler with Low NOx burners and flue gas
Natural gas‐fied boiler (Boiler B01) 13.31 Natural Gas 35 mmBtu/hr Compounds (VOC) recirculation 0.0055 LB/MMBTU
BOILER PROVIDES ADDITIONAL
STEAM FOR TEH SOYBEAN Volatile Organic
DUAL‐FIRED 85.6 MMBTU/HR WATER‐TUBE BOILER 13.31 NATURAL GAS 85.6 MMBTU/H SOLVENT EXTRACTION. Compounds (VOC) GOOD COMBUSTION PRACTICES 0.0055 LB/MMBTU TEST METHOD AVG
Volatile Organic
PACKAGE BOILER 13.31 NATURAL GAS 17.5 MMBTU/H Compounds (VOC) GCP 0.006 LB/MMBTU
Volatile Organic
2 CALP LINE BOILERS 13.31 NATURAL GAS 24.59 MMBTU/H 2 IDENTICAL BOILERS Compounds (VOC) GCP 0.006 LB/MMBTU
Volatile Organic
Gas‐fired Boiler 13.31 Natural Gas 95 MMBTUH Compounds (VOC) Good Combustion 0.006 LB/MMBTU 3‐HOUR
One natural gas‐fired auxiliary
boiler rated at 55 MMBTU/hr Volatile Organic
Auxiliary Boiler A (EUAUXBOILERA) 13.31 natural gas 55 MMBTU/H fuel heat input Compounds (VOC) Good combustion control 0.008 LB/MMBTU TEST PROTOCOL
One natural gas fired auxiliary
boiler rated at 83.5 MMBTU/hr Volatile Organic TEST PROTOCOL WILL SPECIFY
EUAUXBOILER (Auxiliary boiler) 13.31 natural gas 83.5 MMBTU/H fuel heat input Compounds (VOC) Good combustion practices. 0.008 LB/MMBTU AVG TIME
One natural gas‐fired auxiliary
boiler rated at 95 MMBtu/hr Volatile Organic
Auxiliary Boiler B (EUAUXBOILERB) 13.31 natural gas 95 MMBTU/H fuel heat input Compounds (VOC) Good combustion practices 0.008 LB/MMBTU TEST PROTOCOL
EUAUXBOILER: Auxiliary Boiler 13.31 Natural gas 99.9 MMBTU/H to facilitate startup of the Compounds (VOC) Good combustion practices 0.008 LB/MMBTU HOURLY
There are two auxiliary boilers
FGAUXBOILERS: Two auxiliary boilers < 100 MMBTU/H MMBTU/H heat each rated at less than 100 Volatile Organic HEAT INPUT; TEST PROTOCOL
heat input each 13.31 natural gas 100 input each MMBTU/H heat input. Fuel Compounds (VOC) Efficient combustion; natural gas fuel. 0.008 LB/MMBTU WILL SPECIFY
Volatile Organic
HOT OIL HEATER S38 13.31 NATURAL GAS 84 MMBTU/H Compounds (VOC) GOOD COMBUSTION PRACTICES 0.02 LB/MMBTU
Volatile Organic
AMINE UNIT VOC CONTROL 13.31 NATURAL GAS 72 MMBTU/H Compounds (VOC) THERMAL OXIDIZER 0.04 LB/MMBTU
BOILER SN‐26, GALVANIZING LINE 13.31 NATURAL GAS 53.7 MMBTU/HR Compounds (VOC) COMBUSTION PRACTICE 0.054 LB/MMBTU
Commercial/Institutional Size Boilers (<100 MMBtu) – Volatile Organic
natural gas 13.31 natural gas 73.3 MMBTU/H Compounds (VOC) 4 PPM 1‐HR AVG
Volatile Organic 1 HR BLOCK AVG, DOES NOT
Auxiliary Boiler 13.31 Natural Gas 80 MMBTU/H Compounds (VOC) oxidation catalyst 11.8 PPMVD@3% O2 APPLY DURING SS
C30
Natural Gas Fired in‐line Fuel Gas Heater PM ‐ RBLC Dataset
point heater for warming the Particulate matter,
Fuel pre‐heater (EUFUELHTR) 13.31 natural gas 3.7 MMBTU/H natural gas fuel (EUFUELHTR). filterable (FPM) Good combustion practices. 0.007 LB/MMBTU TEST PROTOCOL
heater for warming the natural Particulate matter, TEST PROTOCOL WILL
EUFUELHTR (Fuel pre‐heater) 13.31 Natural gas 3.7 MMBTU/H gas fuel (EUFUELHTR). filterable (FPM) Good combustion practices. 0.007 LB/MMBTU SPECIFY AVG TIME
THE TWO UNITS ARE
WATER HEATERS ‐ UNITS NY037 AND NY038 AT NEW IDENTICAL RBI FUTURA III Particulate matter, LIMITING THE FUEL TO NATURAL GAS ONLY AND
YORK ‐ NEW YORK 13.31 NATURAL GAS 2 MMBTU/H WATER HEATERS.THE filterable < 10 µ (FPM10) GOOD COMBUSTION PRACTICES 0.0075 LB/MMBTU
point heater for warming the Particulate matter, total <
Fuel pre‐heater (EUFUELHTR) 13.31 natural gas 3.7 MMBTU/H natural gas fuel (EUFUELHTR). 10 µ (TPM10) Good combustion practices 0.0075 LB/MMBTU TEST PROTOCOL
point heater for warming the Particulate matter, total <
Fuel pre‐heater (EUFUELHTR) 13.31 natural gas 3.7 MMBTU/H natural gas fuel (EUFUELHTR). 2.5 µ (TPM2.5) Good combustion pracitces. 0.0075 LB/MMBTU TEST PROTOCOL
heater for warming the natural Particulate matter, total < TEST PROTOCOL WILL
EUFUELHTR (Fuel pre‐heater) 13.31 Natural gas 3.7 MMBTU/H gas fuel (EUFUELHTR). 10 µ (TPM10) Good combustion practices. 0.0075 LB/MMBTU SPECIFY AVG TIME
heater for warming the natural Particulate matter, total < TEST PROTOCOL WILL
EUFUELHTR (Fuel pre‐heater) 13.31 Natural gas 3.7 MMBTU/H gas fuel (EUFUELHTR). 2.5 µ (TPM2.5) Good combustion practices. 0.0075 LB/MMBTU SPECIFY AVG TIME.
Two natural gas‐fired auxiliary
boilers, each rated at 6 Particulate matter, total < Good combustion practices and low sulfur fuel
FGAUXBOILERS 13.31 Natural gas 6 MMBTU/H MMBTU/H fuel heat input. The 10 µ (TPM10) (pipeline quality natural gas). 0.0075 LB/MMBTU TEST PROTOCOL
Two natural gas‐fired auxiliary
boilers, each rated at 6 Particulate matter, total < Good combustion practices and low sulfur fuel
FGAUXBOILERS 13.31 Natural gas 6 MMBTU/H MMBTU/H fuel heat input. The 2.5 µ (TPM2.5) (pipeline quality natural gas). 0.0075 LB/MMBTU TEST PROTOCOL
C31
Natural Gas Fired in‐line Fuel Gas Heater GHG ‐ RBLC Dataset
will be installed. The Carbon Dioxide Equivalent
Heaters (Gas‐Fired) 13.31 Natural Gas 0 application requested that the (CO2e) Natural Gas Fuel 120 LB/MMBTU
Startup Heater 13.31 natural gas 58.8 MMBTU/H natural gas/yr Carbon Dioxide good operating practices & use of natural gas 117 LB/MMBTU STACK TEST RUNS
Startup Heater 13.31 natural gas 58.8 MMBTU/H natural gas/yr Methane good operating practices & use of natural gas 0.0023 LB/MMBTU STACK TEST RUNS
Startup Heater 13.31 natural gas 58.8 MMBTU/H natural gas/yr Nitrous Oxide (N2O) good operating practices & use of natural gas 0.0006 LB/MMBTU STACK TEST RUNS
PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Carbon Dioxide GOOD OPERATING PRACTICES 117 LB/MMBTU

PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Methane GOOD OPERATING PRACTICES 0.0022 LB/MMBTU
PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Nitrous Oxide (N2O) GOOD OPERATING PRACTICES 0.0002 LB/MMBTU
C32
Diesel Firewater Pump NO X ‐ RBLC Dataset
Compliance demonstrated with vendor emission
ultra low sulfur certification and adherence to vendor‐specified
Emergency fire pump 17.21 diesel 460 hp Nitrogen Oxides (NOx) maintenance recommendations. 2.6 G/BHP‐HR 1 H
The fire pump will be restricted
to operate not more than 100
Fire Pump 17.21 Diesel 0 hr/yr. Nitrogen Oxides (NOx) 2.6 G/BHP‐HR
Fire Pump Engine ‐ 460 BHP 17.21 Diesel 0 Nitrogen Oxides (NOx) 2.6 G/BHP‐HR EXPRESSED AS NO2

OPERATION LIMITED TO 500
HOURS PER YEAR.
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 2.83 G/BHP‐HR 3‐HR AVERAGE
OPERATION NOT TO EXCEED
500 HOURS PER YEAR.
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 2.83 G/BHP‐HR 3‐HR AVERAGE
HOURS PER YEAR.
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 2.83 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR.
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 2.83 G/BHP‐HR 3‐HR AVERAGE
The Emergency Fire Pump is
rated at 335 BHP and limited to
Emergency Diesel Fire Pump 17.21 ULSD Fuel Oil #2 0 500 hr/yr (emergency Nitrogen Oxides (NOx) 2.85 G/BHP‐HR
ANNUAL OPERATION LIMITED
DIESEL‐FIRED EMERGENCY WATER PUMP 17.21 NO. 2 FUEL OIL 481 BHP TO 200 HR, Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 2.86 G/BHP‐HR 3‐HR AVERAGE
A 260 brake horsepower (bhp)
diesel‐fueled emergency Good combustion practices and meeting NSPS TEST PROTOCOL WILL
EUFPENGINE (Emergency engine‐‐diesel fire pump) 17.21 Diesel 1.66 MMBTU/H engine manufactured in 2011 Nitrogen Oxides (NOx) Subpart IIII requirements. 3 G/BHP‐HR SPECIFY AVG TIME
A 300 HP diesel‐fired
emergency fire pump engine Good combustion practices and meeting NSPS
EUFPENGINE (South Plant): Fire pump engine 17.21 Diesel 300 HP with a model year of 2011 or Nitrogen Oxides (NOx) Subpart IIII requirements. 3 G/BHP‐HR HOURLY
EUFPENGINE (North Plant): Fire pump engine 17.21 Diesel 300 HP with a model year of 2011 or Nitrogen Oxides (NOx) Subpart IIII requirements. 3 G/BHP‐HR HOURLY
EUFIREPUMPENGS ‐ Two (2)
diesel‐fueled emergency fire HOURLY; EACH ENGINE
EUFIREPUMPENGS (2 emergency fire pump engines) 17.21 Diesel 250 BHP pump engines rated at 250 Nitrogen Oxides (NOx) Good combustion practices. 3 G/BHP‐HR (NMHC+NOX)
Firewater Pump Engines 17.21 Diesel 288 hp (each) Nitrogen Oxides (NOx) Complying with 40 CFR 60 Subpart IIII 3 G/BHP‐HR
Emergency Diesel Fire Pump, One 600 HP 17.21 ULSD 0 Nitrogen Dioxide (NO2) 3 G/BHP‐HR

THE TWO FIREWATER PUMP
ENGINES, IDENTIFIED AS FP01 COMBUSTION DESIGN CONTROLS AND USAGE
TWO (2) FIREWATER PUMP DIESEL ENGINES 17.21 DIESEL 371 BHP, EACH AND FP02, EXHAUSTING Nitrogen Oxides (NOx) LIMITS 3 G/BHP‐HR 3 HOURS
40 CFR 60, SUBPART IIII, ULTRA EXCLUSIVE USE OF ULSD FUEL, GOOD COMBUSTION
ULTRA‐LOW LOW‐SULFUR DIESEL FUEL, PRACTICES, AND LIMITING THE HOURS OF
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 300 HP GOOD COMBUSTION Nitrogen Oxides (NOx) OPERATION 3 G/BHP‐HR N/A
40 CFR 60, SUBPART IIII, ULTRA
ULTRA LOW LOW‐SULFUR DIESEL FUEL, LIMITED OPERATING HOURS, USE OF ULTRA‐ LOW
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 477 HP GOOD COMBUSTION Nitrogen Oxides (NOx) SULFUR FUEL AND GOOD COMBUSTION PRACTICES 3 G/BHP‐HR
ULTRAL LOW 40 CFR 60, SUBPART IIII, GOOD GOOD COMBUSTION PRACTICES, LIMITED HOURS

EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 350 HP COMBUSTION PRACTICES Nitrogen Oxides (NOx) OF OPERATION, AND EXCLUSIVE USE OF ULSD 3 G/BHP‐HR
ULTRA LOW LOW‐SULFUR DIESEL FUEL, GOOD COMBUSTION PRACTICES AND DESIGNED TO
5 EMERGENCY FIRE WATER PUMP ENGINES 17.21 SULFUR DIESEL 350 HP GOOD COMBUSTION Nitrogen Oxides (NOx) ACHIEVE EMISSION LIMIT 3 G/BHP‐HR NOX + NMHC
Maximum operation was TEST PROTOCOL;
Fire Pump 17.21 Diesel 420 HP based on 500 hours per year. Nitrogen Oxides (NOx) 3 G/BHP‐HR BACT/SIP/NSPS
This is a diesel fuel fired
EU‐FPENGINE: Diesel fuel fired emergency backup fire emergency backup fire mump. Proper combustion design and ultra low sulfur TEST PROTOCOL WILL
pump 17.21 diesel fuel 315 hp nameplate It has a capacity of 315 hp, Nitrogen Oxides (NOx) diesel fuel. 3 G/BHP‐HR SPECIFY AVG. TIME.
C33
A 165 hoursepower (hp) diesel‐
fueled emergency engine
Emergency Engine ‐‐Diesel Fire Pump (EUFPENGINE) 17.21 Diesel 165 HP manufactured in 2013, iwth a Nitrogen Oxides (NOx) Good combustion practices 3 G/BHP‐HR TEST PROTOCOL
A 165 horsepower (hp) diesel‐
fueled emergency engine TEST PROTOCOL WILL
EUFPENGINE (Emergency engine‐‐diesel fire pump) 17.21 diesel 500 H/YR manufactured in 2016 with a Nitrogen Oxides (NOx) Good combustion practices. 3 G/BHP‐HR SPECIFY AVG TIME
One (1) compression ignition EXCLUDES STARTUP,
Ultra‐lowsulfur emergency fire pump engine, SHUTDOWN &
Compression ignition RICE emergency fire pump 17.21 diesel (ULSD) 197 HP rated at 197 HP, which shall Nitrogen Oxides (NOx) 3 G/BHP‐HR MALFUNCTION
Good combustion practices and the use of ultra low
Ultra Low Sulfur sulfur diesel (S15 ULSD) fuel oil with a maximum
Emergency Fire Water Pump 17.21 Diesel 500 HR/YR 315 BHP Nitrogen Oxides (NOx) sulfur content of 15 ppmw. 3 G/BHP‐HR
≤ 300 hours of operation per
12‐month rolling period S in
Fire Pump Engine 17.21 ULSD 2.7 MMBTU/H ULSD: ≤0.0015% by weight Nitrogen Oxides (NOx) 3 G/BHP‐HR 1 HR BLOCK AVG
Ultra‐low sulfur
Fire pump engine 17.21 diesel 15 gal/hr Nitrogen Oxides (NOx) 3 G/BHP‐HR
EQUIPPED W/ A TURBOCHARGER AND AN
EMERGENCY FIREWATER PUMP ENGINE 17.21 DIESEL 288 HP Nitrogen Oxides (NOx) INTERCOOLER/AFTERCOOLER 3.4 G/BHP‐HR
40 CFR 60 SUBPART IIII, ULTRA EXCLUSIVE USE OF ULSD FUEL, GOOD COMBUSTION
ULTRA‐LOW LOW‐SULFUR DIESEL FUEL, PRACTICES, AND LIMITING THE HOURS OF
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1500 KW GOOD COMBUSTION Nitrogen Oxides (NOx) OPERATION 4.8 G/BHP‐HR N/A
Ultra Low Sulfur One 490 hp Airstrip Generator
Airstrip Generator Engine 17.21 Diesel 490 hp Engine Nitrogen Oxides (NOx) 4.8 G/BHP‐HR
Ultra Low Sulfur ULSD‐fired 102 hp Incinerator
Incinerator Generator Engine 17.21 Diesel 102 hp Generator Engine Nitrogen Dioxide (NO2) 4.9 G/BHP‐HR
Ultra Low Sulfur ULSD‐fired 98 hp Agitator
Agitator Generator Engine 17.21 Diesel 98 hp Generator Engine Nitrogen Oxides (NOx) 5.6 G/BHP‐HR
400‐KW DIESEL EMERGENCY GENERATOR 17.21 #2 Oil 29.2 GAL/H Nitrogen Oxides (NOx) 6.9 G/BHP‐HR

Each pump engine is 252 HP.
They are limited to emergency QP1&QP2 EACH; TEST
4 Diesel‐fired quench pumps 17.21 Diesel fuel 252 HP use and subject to NSPS Nitrogen Oxides (NOx) Good combustion practices. 7.8 G/BHP‐HR PROTOCOL
EMERGENCY FIRE PUMP ENGINE 17.21 DISTILLATE OIL 0 425 HP Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 9.5 G/BHP‐HR
2 units at 75 hp, 1 unit at 150
Emergency Diesel Generators 17.21 Deisel 150 hp hp Nitrogen Oxides (NOx) 14.06 G/BHP‐HR
FIRE PUMP DIESEL ENGINE 17.21 NO 2 DIESEL 214 kW Nitrogen Oxides (NOx) Meets EPA Tier 4 requirements 0.4 G / KWH HR
Internal Combustion Engine ‐ 450 bhp 17.21 diesel 450 bhp Model qsx15‐c‐ Cummins Nitrogen Oxides (NOx) 1.8 G / KWH
Tier IV standards for non‐road engines at 40 CFR
Firewater Pump Engine 17.21 distillate fuel oil 373 hp Nitrogen Oxides (NOx) 1039.102, Table 7. 3.5 G / KWH
Three (3) 252 hp fire pump
diesel internal combustion
Fire Pump Diesel Internal Combustion Engines 17.21 Diesel 252 hp engines. Nitrogen Oxides (NOx) Good Combustion Practices 3.7 G / KWH 3‐HOUR AVERAGE
AVERAGE OF 3 STACK TEST
Fire Pump 17.21 diesel fuel 14 GAL/H rated @ 235 KW Nitrogen Oxides (NOx) good combustion practices 3.75 G / KWH RUNS
135 KW (182 hp) IC Diesel‐fired
Emergency Firewater Pump OPERATIONAL RESTRICTION OF 50 HR/YR, OPERATE
EMERGENCY FIREWATER PUMP ENGINE 17.21 DIESEL 135 KW Engine Nitrogen Oxides (NOx) AS REQUIRED FOR FIRE SAFETY TESTING 3.8 G / KWH
Emergency engine. ULSD only.
BACT limits equal NSPS IIII NMHC + NOX (SUBPART
Emergency fire pump engine, 300 HP 17.21 Diesel 29 MMBTU/H limits. Nitrogen Oxides (NOx) Low‐emitting fuel and certified engine 4 G / KWH IIII)
C34
EMERGENCY IC ENGINE 17.21 DIESEL 182 HP UNIT IS 135 KW. Nitrogen Oxides (NOx) 4 G / KWH 3‐HR AVG
Use of inherently clean ultra low sulfur distillate
250 Kw Emergency Generator 17.21 ULSD 0 Nitrogen Oxides (NOx) (ULSD) fuel oil and GCP 4 G / KWH
COMPRESSION IGNITION
INTERNAL COMBUSTION (CI TIER 3 ENGINE‐BASED GOOD COMBUSTION
FIRE PUMP ENGINE 17.21 DIESEL 235 KW ICE) Nitrogen Oxides (NOx) PRACTICES (GCP) 4 G / KWH NOX+NMHC
Emergency Diesel Engine Pump P‐39A 17.21 Diesel Fuel 375 HP Emergency Engine Nitrogen Oxides (NOx) Good combustion practices and NSPS IIII 4 G / KWH
Emergency Diesel Engine Pump P‐39B 17.21 Diesel Fuel 300 HP Emergency Engine Nitrogen Oxides (NOx) Good combustion practices and NSPS Subpart IIII 4 G / KWH

40 CFR 60, SUBPART IIII, 40 CFR
ULTRA‐LOW 63 SUBPART ZZZZ, ULTRA LOW‐ EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 305 HP SULFURDIESEL FUEL, GOOD Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 4 G / KWH
ONE DIESEL‐FIRED FIRE PUMP
ULTRA‐LOW ENGINE, RATED AT A NOMINAL EXCLUSIVE USE OF ULTRA LOW SULFUR DIESEL FUEL
DIESEL‐FIRED FIRE PUMP ENGINE 17.21 SULFUR DIESEL 300 HP 300‐HORSEPOWER. SUBJECT Nitrogen Oxides (NOx) AND GOOD COMBUSTION PRACTICES 4 G / KWH
EULIFESAFETYENG ‐ One (1)
EULIFESAFETYENG ‐ One diesel‐fueled emergency diesel‐fueled emergency
engine/generator 17.21 Diesel 500 KW engine/generator rated at 500 Nitrogen Oxides (NOx) Good combustion practices. 4 G / KWH HOURLY; NMHC+NOX
A 399 brake HP diesel‐fueled
emergency fire pump engine
EUFPENGINE: Fire pump engine 17.21 Diesel 399 BHP with a model year of 2011 or Nitrogen Oxides (NOx) State of the art combustion design. 4 G / KWH HOURLY
Operate and maintain the engine according to the
Emergency Fire Pump Engine (347 HP) 17.21 ULSD 8700 gal/year Limits equal Subpart IIII limits Nitrogen Oxides (NOx) manufacturer's written instructions 4 G / KWH
One engine will power the
Ultra‐Low Sulfur pump in the firewater system.
Firewater Pump Engine 17.21 Diesel 420 horsepower The fuel must meet the Nitrogen Oxides (NOx) 4 G / KWH
THE CONSTRUCTION PERMIT
AUTHORIZES THE PURCHASE OF CERTIFIED ENGINE BASED ON NSPS,
FIRE PUMP 17.21 DIESEL 500 HP CONSTRUCTION OF ONE (1) Nitrogen Oxides (NOx) SUBPART IIII. 4 G / KWH
40 CFR 60 SUBPART IIII, 40 CFR
ULTRA‐LOW 63 SUBPART ZZZZ ULTRA LOW‐ EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1490 HP SULFUR DIESEL FUEL, GOOD Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 6.4 G / KWH
TWO DIESEL‐FIRED AUXILIARY
DIESEL‐FIRED AUXILIARY (EMERGENCY) ENGINES ULTRA‐LOW GENERATORS (EMERGENCY EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
(TWO) 17.21 SULFUR DIESEL 1500 KW GENERATORS), EACH RATED AT Nitrogen Oxides (NOx) GOOD COMBUSTION PRACTICES 6.4 G / KWH
THE CONSTRUCTION PERMIT
AUTHORIZES THE
EMERGENCY ENGINE 1 THRU 8 17.21 DIESEL 29 HP CONSTRUCTION OF EIGHT (8) Nitrogen Oxides (NOx) PURCHASE OF CERTIFIED ENGINE. 7.5 G / KWH
Emergency Diesel Generators 17.21 Diesel 250 hp 2 units Nitrogen Oxides (NOx) 9.2 G / KWH
C35
Diesel Firewater Pump CO ‐ RBLC Dataset
EQUIPPED W/ A TURBOCHARGER AND AN
EMERGENCY FIREWATER PUMP ENGINE 17.21 DIESEL 288 HP Carbon Monoxide INTERCOOLER/AFTERCOOLER 0.447 G/BHP‐HR
Ultra‐low sulfur
Fire pump engine 17.21 diesel 15 gal/hr Carbon Monoxide 0.5 G/BHP‐HR
Fire Pump Engine ‐ 460 BHP 17.21 Diesel 0 Carbon Monoxide 0.5 G/BHP‐HR

to operate not more than 100
Fire Pump 17.21 Diesel 0 hr/yr. Carbon Monoxide 0.5 G/BHP‐HR
ultra low sulfur certification and adherence to vendor‐specified
Emergency fire pump 17.21 diesel 460 hp Carbon Monoxide maintenance recommendations. 0.53 G/BHP‐HR 1 H
EMERGENCY FIRE PUMP ENGINE 17.21 DISTILLATE OIL 0 425 HP Carbon Monoxide GOOD COMBUSTION PRACTICES 2.01 G/BHP‐HR
Ultra Low Sulfur One 490 hp Airstrip Generator
Airstrip Generator Engine 17.21 Diesel 490 hp Engine Carbon Monoxide 2.6 G/BHP‐HR
12‐month rolling period S in
Fire Pump Engine 17.21 ULSD 2.7 MMBTU/H ULSD: ≤0.0015% by weight Carbon Monoxide 2.6 G/BHP‐HR 1 HR BLOCK AVG
Emergency Diesel Fire Pump, One 600 HP 17.21 ULSD 0 Carbon Monoxide 2.6 G/BHP‐HR

ENGINES, IDENTIFIED AS FP01 COMBUSTION DESIGN CONTROLS AND USAGE
TWO (2) FIREWATER PUMP DIESEL ENGINES 17.21 DIESEL 371 BHP, EACH AND FP02, EXHAUSTING Carbon Monoxide LIMITS 2.6 G/BHP‐HR
ULTRA LOW SULFUR DIESEL AND GOOD
EMERGENCY FIRE PUMP 17.21 DIESEL 350 HP Carbon Monoxide COMBUSTION PRACTICES 2.6 G/BHP‐HR LB/MM BTU
40 CFR 60 SUBPART IIII, ULTRA
ULTRA‐LOW LOW‐SULFUR DIESEL FUEL, USE OF ULTRA LOW SULFUR DIESEL AND GOOD
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1500 KW GOOD COMBUSTION Carbon Monoxide COMBUSTION PRACTICES 2.6 G/BHP‐HR N/A
ULTRA‐LOW LOW‐SULFUR DIESEL FUEL, USE OF ULTRA LOW SULFUR DIESEL AND GOOD
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 300 HP GOOD COMBUSTION Carbon Monoxide COMBUSTION PRACTICES 2.6 G/BHP‐HR N/A
40 CFR 60, SUBPART IIII, ULTRA USE OF ULSD FUEL, GOOD COMBUSTION PRACTICES
ULTRA LOW LOW‐SULFUR DIESEL FUEL, AND HOURS OF OPERATION LIMITED TO 100 HOURS
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 477 HP GOOD COMBUSTION Carbon Monoxide PER YEAR 2.6 G/BHP‐HR
They are limited to emergency EACH PUMP; TEST
4 Diesel‐fired quench pumps 17.21 Diesel fuel 252 HP use and subject to NSPS Carbon Monoxide Good combustion practices. 2.6 G/BHP‐HR PROTOCOL
EU‐FPENGINE: Diesel fuel fired emergency backup fire emergency backup fire mump. Proper combustion design and ultra low sulfur TEST PROTOCOL WILL
pump 17.21 diesel fuel 315 hp nameplate It has a capacity of 315 hp, Carbon Monoxide diesel fuel. 2.6 G/BHP‐HR SPECIFY AVG. TIME.
LOW SULFUR
EMERGENCY FIRE PUMP (267‐HP DIESEL) 17.21 DIESEL 267 HP Carbon Monoxide 2.6 G/BHP‐HR NSPS
FWP‐1: 104.0 tons/year (12‐
DIESEL‐FIRED WATER PUMP 376 bph (1) 17.21 DIESEL FUEL 0 month rolling total) Carbon Monoxide Good Combustion Practices/Maintenance 2.6 G/BHP‐HR HR
good combustion practices and the use of ultra low
Ultra Low Sulfur sulfur diesel (S15 ULSD) fuel oil with a maximum
Emergency Fire Water Pump 17.21 Diesel 500 HR/YR 315 BHP Carbon Monoxide sulfur content of 15 ppmw. 2.6 G/BHP‐HR
EUFPENGINE (South Plant): Fire pump engine 17.21 Diesel 300 HP with a model year of 2011 or Carbon Monoxide Subpart IIII requirements. 2.6 G/BHP‐HR HOURLY
DIESEL‐FIRED EMERGENCY WATER PUMP 17.21 NO. 2 FUEL OIL 481 BHP TO 200 HR, Carbon Monoxide GOOD COMBUSTION PRACTICES 2.6 G/BHP‐HR 3‐HR AVERAGE
HOURS PER YEAR.
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL Carbon Monoxide GOOD COMBUSTION PRACTICES 2.6 G/BHP‐HR 3‐HR AVERAGE
C36
500 HOURS PER YEAR.
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL Carbon Monoxide GOOD COMBUSTION PRACTICES 2.6 G/BHP‐HR 3‐HR AVERAGE
rated at 335 BHP and limited to
Emergency Diesel Fire Pump 17.21 ULSD Fuel Oil #2 0 500 hr/yr (emergency Carbon Monoxide 2.6 G/BHP‐HR
HOURS PER YEAR.
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL Carbon Monoxide GOOD COMBUSTION PRACTICES 2.6 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR.
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL Carbon Monoxide GOOD COMBUSTION PRACTICES 2.6 G/BHP‐HR 3‐HR AVERAGE
diesel‐fueled emergency Good combustion practices and meeting NSPS TEST PROTOCOL WILL
EUFPENGINE (Emergency engine‐‐diesel fire pump) 17.21 Diesel 1.66 MMBTU/H engine manufactured in 2011 Carbon Monoxide Subpart IIII requirements. 2.6 G/BHP‐HR SPECIFY AVG. TIME
EUFPENGINE (North Plant): Fire pump engine 17.21 Diesel 300 HP with a model year of 2011 or Carbon Monoxide Subpart IIII requirements. 2.6 G/BHP‐HR HOURLY
ULTRA LOW LOW‐SULFUR DIESEL FUEL, GOOD COMBUSTION PRACTICES AND DESIGNED TO
5 EMERGENCY FIRE WATER PUMP ENGINES 17.21 SULFUR DIESEL 350 HP GOOD COMBUSTION Carbon Monoxide MEET EMISSION LIMIT 3 G/BHP‐HR
Emergency Diesel Generators 17.21 Diesel 250 hp 2 units Carbon Monoxide 3.08 G/BHP‐HR
Ultra Low Sulfur ULSD‐fired 98 hp Agitator
Agitator Generator Engine 17.21 Diesel 98 hp Generator Engine Carbon Monoxide 3.7 G/BHP‐HR
Ultra Low Sulfur ULSD‐fired 102 hp Incinerator
Incinerator Generator Engine 17.21 Diesel 102 hp Generator Engine Carbon Monoxide 3.7 G/BHP‐HR
fueled emergency engine
Emergency Engine ‐‐Diesel Fire Pump (EUFPENGINE) 17.21 Diesel 165 HP manufactured in 2013, iwth a Carbon Monoxide Good combustion practices 3.7 G/BHP‐HR TEST PROTOCOL
fueled emergency engine TEST PROTOCOL WILL
EUFPENGINE (Emergency engine‐‐diesel fire pump) 17.21 diesel 500 H/YR manufactured in 2016 with a Carbon Monoxide Good combustion practices. 3.7 G/BHP‐HR SPECIFY AVG TIME
Diesel Fire water pump 376 bhp 17.21 diesel 500 h/yr Carbon Monoxide good combustion practices 0.9 G / KWH
FUEL OIL #2
EMERGENCY GEN. UNIT 3 ‐ 300Kw ‐ CU 17.21 (DIESEL) 300 KW Carbon Monoxide 3 G / KWH
2 units at 75 hp, 1 unit at 150
Emergency Diesel Generators 17.21 Deisel 150 hp hp Carbon Monoxide 3.08 G / KWH
diesel internal combustion
Fire Pump Diesel Internal Combustion Engines 17.21 Diesel 252 hp engines. Carbon Monoxide Good Combustion Practices 3.3 G / KWH 3‐HOUR AVERAGE
BACT limits equal NSPS IIII
Emergency fire pump engine, 300 HP 17.21 Diesel 29 MMBTU/H limits. Carbon Monoxide Low‐emitting fuel and certified engine 3.5 G / KWH
Emergency Fire Pump Engine (422 hp) 17.21 ULSD 0 Limits equal Subpart IIII limits Carbon Monoxide Certified engine 3.5 G / KWH

BACT limits equal to NSPS
Subpart IIII limits. Will use IIII
One 422‐hp emergency fire pump engine 17.21 ULSD 0 certified engine. Carbon Monoxide Use of clean engine technology 3.5 G / KWH
Emergency Firewater Pump OPERATIONAL RESTRICTION OF 50 HR/YR, OPERATE
EMERGENCY FIREWATER PUMP ENGINE 17.21 DIESEL 135 KW Engine Carbon Monoxide AS REQUIRED FOR FIRE SAFETY TESTING 3.5 G / KWH
EMERGENCY IC ENGINE 17.21 DIESEL 182 HP UNIT IS 135 KW. Carbon Monoxide 3.5 G / KWH
250 Kw Emergency Generator 17.21 ULSD 0 Carbon Monoxide (ULSD) fuel oil and GCP 3.5 G / KWH
C37
Fire Pump 17.21 diesel fuel 14 GAL/H rated @ 235 KW Carbon Monoxide good combustion practices 3.5 G / KWH RUNS
Tier IV standards for non‐road engines at 40 CFR
Firewater Pump Engine 17.21 distillate fuel oil 373 hp Carbon Monoxide 1039.102, Table 7. 3.5 G / KWH
ULTRA‐LOW 63 SUBPART ZZZZ ULTRA LOW‐ EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1490 HP SULFUR DIESEL FUEL, GOOD Carbon Monoxide GOOD COMBUSTION PRACTICES 3.5 G / KWH
ULTRA‐LOW 63 SUBPART ZZZZ, ULTRA LOW‐ USE OF ULTRA LOW SULFUR DIESEL AND GOOD
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 305 HP SULFURDIESEL FUEL, GOOD Carbon Monoxide COMBUSTION PRACTICES 3.5 G / KWH
DIESEL‐FIRED AUXILIARY (EMERGENCY) ENGINES ULTRA‐LOW GENERATORS (EMERGENCY EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
(TWO) 17.21 SULFUR DIESEL 1500 KW GENERATORS), EACH RATED AT Carbon Monoxide GOOD COMBUSTION PRACTICES 3.5 G / KWH
ULTRA‐LOW ENGINE, RATED AT A NOMINAL EXCLUSIVE USE OF ULTRA LOW SULFUR DIESEL FUEL
DIESEL‐FIRED FIRE PUMP ENGINE 17.21 SULFUR DIESEL 300 HP 300‐HORSEPOWER. SUBJECT Carbon Monoxide AND GOOD COMBUSTION PRACTICES 3.5 G / KWH
emergency fire pump engine
EUFPENGINE: Fire pump engine 17.21 Diesel 399 BHP with a model year of 2011 or Carbon Monoxide State of the art combustion design. 3.5 G / KWH HOURLY
Operate and maintain the engine according to the
Emergency Fire Pump Engine (347 HP) 17.21 ULSD 8700 gal/year Limits equal Subpart IIII limits Carbon Monoxide manufacturer's written instructions 3.5 G / KWH
Ultra‐Low Sulfur pump in the firewater system.
Firewater Pump Engine 17.21 Diesel 420 horsepower The fuel must meet the Carbon Monoxide 3.5 G / KWH
THE CONSTRUCTION PERMIT ENGINES CERTIFIED TO MEET NSPS, SUBPART IIII.
AUTHORIZES THE HOURS OF OPERATION LIMITED TO 100 HOURS PER
FIRE PUMP 17.21 DIESEL 500 HP CONSTRUCTION OF ONE (1) Carbon Monoxide YEAR FOR MAINTENANCE AND TESTING. 3.5 G / KWH
Emergency engine. BACT =
Emergency fire pump engine (300 HP) 17.21 USLD 29 MMBTU/H NSPS IIII. Carbon Monoxide Good combustion practice. 3.5 G / KWH
FIRE PUMP DIESEL ENGINE 17.21 NO 2 DIESEL 214 kW Carbon Monoxide Meets EPA Tier 4 requirements 3.58 G / KWH HR

OPERATIONAL LIMITS 1
ULTRA LOW HR/DAY AND 500 HRS/YR FOR ENGINE DESIGN AND OPERATION. 15 PPM SULFUR
FIRE BOOSTER PUMP 17.21 SULFUR DIESEL 40 KW PM2.5 NAAQS. Carbon Monoxide FUEL. 5 G / KWH TEST METHOD
THE CONSTRUCTION PERMIT PURCHASE OF CERTIFIED ENGINE. HOURS OF
AUTHORIZES THE OPERATION LIMITED TO 100 HOURS FOR
EMERGENCY ENGINE 1 THRU 8 17.21 DIESEL 29 HP CONSTRUCTION OF EIGHT (8) Carbon Monoxide MAINTENANCE AND TESTING. 5.5 G / KWH
C38
Diesel Firewater Pump VOC ‐ RBLC Dataset
Volatile Organic
EMERGENCY FIRE PUMP ENGINE 17.21 DISTILLATE OIL 0 425 HP Compounds (VOC) GOOD COMBUSTION PRACTICES 0.05 G/BHP‐HR
ultra low sulfur Volatile Organic certification and adherence to vendor‐specified
Emergency fire pump 17.21 diesel 460 hp Compounds (VOC) maintenance recommendations. 0.1 G/BHP‐HR 1 H
to operate not more than 100 Volatile Organic
Fire Pump 17.21 Diesel 0 hr/yr. Compounds (VOC) 0.1 G/BHP‐HR
Volatile Organic
Fire Pump Engine ‐ 460 BHP 17.21 Diesel 0 Compounds (VOC) 0.1 G/BHP‐HR
Ultra‐low sulfur Volatile Organic
Fire pump engine 17.21 diesel 15 gal/hr Compounds (VOC) 0.12 G/BHP‐HR
HOURS PER YEAR. Volatile Organic
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL Compounds (VOC) GOOD COMBUSTION PRACTICES 0.141 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR. Volatile Organic
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL Compounds (VOC) GOOD COMBUSTION PRACTICES 0.141 G/BHP‐HR 3‐HR AVERAGE
ANNUAL OPERATION LIMITED Volatile Organic
DIESEL‐FIRED EMERGENCY WATER PUMP 17.21 NO. 2 FUEL OIL 481 BHP TO 200 HR, Compounds (VOC) GOOD COMBUSTION PRACTICES 0.141 G/BHP‐HR 3‐HR AVERAGE
HOURS PER YEAR. Volatile Organic
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL Compounds (VOC) GOOD COMBUSTION PRACTICES 0.141 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR. Volatile Organic
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL Compounds (VOC) GOOD COMBUSTION PRACTICES 0.141 G/BHP‐HR 3‐HR AVERAGE
rated at 335 BHP and limited to Volatile Organic
Emergency Diesel Fire Pump 17.21 ULSD Fuel Oil #2 0 500 hr/yr (emergency Compounds (VOC) 0.15 G/BHP‐HR
Ultra‐Low Sulfur Operate for 100 hours Volatile Organic

Diesel‐Fueled Fire Pump Engines 17.21 Distillate Fuel 300 HP maximum annually Compounds (VOC) 1. Good Combustion Practices. 0.15 G/BHP‐HR TOTAL FOR 3 ENGINES.
Volatile Organic
Cummins 6BTA 5.9F‐1 Diesel Engine Fire Pump 17.21 No. 2 Fuel Oil 182 BHP Compounds (VOC) utilize efficient combustion/design technology 0.77 G/BHP‐HR
Volatile Organic ULTRA LOW SULFUR DIESEL AND GOOD
EMERGENCY FIRE PUMP 17.21 DIESEL 350 HP Compounds (VOC) COMBUSTION PRACTICES 1 G/BHP‐HR ANNUAL AVERAGE
2 units at 75 hp, 1 unit at 150 Volatile Organic
Emergency Diesel Generators 17.21 Deisel 150 hp hp Compounds (VOC) 1.134 G/BHP‐HR
Volatile Organic
Emergency Diesel Generators 17.21 Diesel 250 hp 2 units Compounds (VOC) 1.134 G/BHP‐HR
Ultra‐lowsulfur emergency fire pump engine, Volatile Organic SHUTDOWN &
Compression ignition RICE emergency fire pump 17.21 diesel (ULSD) 197 HP rated at 197 HP, which shall Compounds (VOC) 1.14 G/BHP‐HR MALFUNCTION
ULTRA LOW LOW‐SULFUR DIESEL FUEL, Volatile Organic USE ONLY ULSD, GOOD COMBUSTION PRACTICES,
5 EMERGENCY FIRE WATER PUMP ENGINES 17.21 SULFUR DIESEL 350 HP GOOD COMBUSTION Compounds (VOC) AND DESIGNED TO ACHIEVE EMISSION LIMIT 3 G/BHP‐HR NOX + NMHC
FWP‐1: 104.0 tons/year (12‐ Volatile Organic
DIESEL‐FIRED WATER PUMP 376 bph (1) 17.21 DIESEL FUEL 0 month rolling total) Compounds (VOC) Good Combustion Practices/Maintenance 3 G/BHP‐HR PER HR
One (1) 275‐hp emergency Good combustion practices, certified to meet EPA
generator, two (2) 176‐hp Volatile Organic Tier 3 engine standards. Gen‐1, FP‐1, and FP‐2 shall
Emergency Use Engine less than or equal to 500 HP 17.21 Diesel 0 firewater pump engines, and Compounds (VOC) be limited to operate no more than 500 hr/yr. 3 G/BHP‐HR
197 BHP / 147 KW; 1.38 NSPS engine [Tier 3 emergency engine]. EG7 Storage
MMBTU/hr (est. 125 KWe). Volatile Organic tank, conventional fuel oil storage tank, good NOX + NMHC HOURLY
EG7 ‐ Diesel Emergency Electric Generator w/ tank 17.21 Diesel fuel oil 197 BHP Limited to 200 hours / year. Compounds (VOC) operating practices; limiting leakage, spills. (FT01). 3.75 G/BHP‐HR AVG., FOR EG7
Volatile Organic
FIRE PUMP DIESEL ENGINE 17.21 NO 2 DIESEL 214 kW Compounds (VOC) Meets EPA Tier 4 requirements 0.19 G / KWH HR
C39
Diesel Firewater Pump VOC ‐ RBLC Dataset
Volatile Organic AVERAGE OF 3 STACK TEST
Fire Pump 17.21 diesel fuel 14 GAL/H rated @ 235 KW Compounds (VOC) good combustion practices 0.25 G / KWH RUNS
Volatile Organic Tier IV standards for non‐road engines at 40 CFR
Firewater Pump Engine 17.21 distillate fuel oil 373 hp Compounds (VOC) 1039.102, Table 7. 0.4 G / KWH
INTERNAL COMBUSTION (CI Volatile Organic TIER 3 ENGINE‐BASED, GOOD COMBUSTION
FIRE PUMP ENGINE 17.21 DIESEL 235 KW ICE) Compounds (VOC) PRACTICES (GCP) 4 G / KWH NOX+NMHC
Volatile Organic
Emergency Diesel Engine Pump P‐39A 17.21 Diesel Fuel 375 HP Emergency Engine Compounds (VOC) Good combustion practices and NSPS Subpart IIII 4 G / KWH
Volatile Organic
Emergency Diesel Engine Pump P‐39B 17.21 Diesel Fuel 300 HP Emergency Engine Compounds (VOC) Good combustion practices and NSPS Subpart IIII 4 G / KWH
THREE (3) 211 KW/282 BHP BACT HAS BEEN DETERMINED TO BE COMPLIANCE
(EACH) EMERGENCY DIESEL Volatile Organic WITH NSPS, SUBPART IIII, 40 CFR60.4202 AND 40
FIRE PUMPS, FIRE1, FIRE2, FIRE3 17.21 DIESEL 211 KW FIRE PUMPS THAT ARE Compounds (VOC) CFR60.4205. 4 G / KWH
THE CONSTRUCTION PERMIT CERTIFIED ENGINES THAT COMPLY WITH NSPS,
AUTHORIZES THE Volatile Organic SUBPART IIII. HOURS OF OPERATION LIMITED TO
FIRE PUMP 17.21 DIESEL 500 HP CONSTRUCTION OF ONE (1) Compounds (VOC) 100 HOURS PER YEAR FOR MAINTENANCE AND 4 G / KWH
THE CONSTRUCTION PERMIT PURCHASE OF CERTIFIED ENGINES. HOURS OF
AUTHORIZES THE Volatile Organic OPERATION LIMITED TO 100 HOURS FOR
EMERGENCY ENGINE 1 THRU 8 17.21 DIESEL 29 HP CONSTRUCTION OF EIGHT (8) Compounds (VOC) MAINTENANCE AND TESTING. 7.5 G / KWH
C40
Diesel Firewater Pump PM ‐ RBLC Dataset
ultra low sulfur Particulate matter, certification and adherence to vendor‐specified
Emergency fire pump 17.21 diesel 460 hp filterable (FPM) maintenance recommendations. 0.087 G/BHP‐HR 1 H
to operate not more than 100 Particulate matter, total <
Fire Pump 17.21 Diesel 0 hr/yr. 10 µ (TPM10) 0.09 G/BHP‐HR
to operate not more than 100 Particulate matter, total <
Fire Pump 17.21 Diesel 0 hr/yr. 2.5 µ (TPM2.5) 0.09 G/BHP‐HR
Fire Pump Engine ‐ 460 BHP 17.21 Diesel 0 10 µ (TPM10) 0.09 G/BHP‐HR
Fire Pump Engine ‐ 460 BHP 17.21 Diesel 0 2.5 µ (TPM2.5) 0.09 G/BHP‐HR
Ultra‐low sulfur Particulate matter,
Fire pump engine 17.21 diesel 15 gal/hr filterable (FPM) 0.11 G/BHP‐HR
Ultra‐low sulfur Particulate matter, total <
Fire pump engine 17.21 diesel 15 gal/hr 10 µ (TPM10) 0.11 G/BHP‐HR
Ultra‐low sulfur Particulate matter, total <
Fire pump engine 17.21 diesel 15 gal/hr 2.5 µ (TPM2.5) 0.11 G/BHP‐HR
One (1) 1102 HP (750 KW) Particulate matter, total <
Emergency diesel engine 17.21 diesel 750 KW emergency diesel engine 2.5 µ (TPM2.5) Low sulfur fuel oil (<15 ppm sulfur) 0.15 G/BHP‐HR
One (1) 1102 HP (750 KW) Particulate matter, total <
Emergency diesel engine 17.21 diesel 750 KW emergency diesel engine 10 µ (TPM10) Low sulfur fuel oil (<15 ppm sulfur) 0.15 G/BHP‐HR
One (1) 1102 HP (750 KW) Particulate matter, total
Emergency diesel engine 17.21 diesel 750 KW emergency diesel engine (TPM) Low sulfur fuel oil (<15 ppm sulfur) 0.15 G/BHP‐HR
HOURS PER YEAR. Particulate matter,
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL filterable (FPM) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
HOURS PER YEAR. Particulate matter, total <
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL 10 µ (TPM10) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL 2.5 µ (TPM2.5) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR. Particulate matter,
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL filterable (FPM) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR. Particulate matter, total <
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL 10 µ (TPM10) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL 2.5 µ (TPM2.5) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
ULTRA LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, PRACTICES AND DESIGNED TO ACHIEVE EMISSION
5 EMERGENCY FIRE WATER PUMP ENGINES 17.21 SULFUR DIESEL 350 HP GOOD COMBUSTION filterable (FPM) LIMITS 0.15 G/BHP‐HR
diesel‐fueled emergency Particulate matter, Good combustion practices and meeting NSPS TEST PROTOCOL WILL
EUFPENGINE (Emergency engine‐‐diesel fire pump) 17.21 Diesel 1.66 MMBTU/H engine manufactured in 2011 filterable (FPM) Subpart IIII requirements. 0.15 G/BHP‐HR SPECIFY AVG TIME.
emergency fire pump engine Particulate matter, Diesel particulate filter, good combustion practices
EUFPENGINE (South Plant): Fire pump engine 17.21 Diesel 300 HP with a model year of 2011 or filterable (FPM) and meeting NSPS Subpart IIII requirements. 0.15 G/BHP‐HR HOURLY
emergency fire pump engine Particulate matter, Diesel particulate filter, good combustion practices
EUFPENGINE (North Plant): Fire pump engine 17.21 Diesel 300 HP with a model year of 2011 or filterable (FPM) and meeting NSPS Subpart IIII requirements. 0.15 G/BHP‐HR HOURLY
ANNUAL OPERATION LIMITED Particulate matter,
DIESEL‐FIRED EMERGENCY WATER PUMP 17.21 NO. 2 FUEL OIL 481 BHP TO 200 HR, filterable (FPM) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
C41
ANNUAL OPERATION LIMITED Particulate matter, total <
DIESEL‐FIRED EMERGENCY WATER PUMP 17.21 NO. 2 FUEL OIL 481 BHP TO 200 HR, 10 µ (TPM10) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
ANNUAL OPERATION LIMITED Particulate matter, total <
DIESEL‐FIRED EMERGENCY WATER PUMP 17.21 NO. 2 FUEL OIL 481 BHP TO 200 HR, 2.5 µ (TPM2.5) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
HOURS PER YEAR. Particulate matter,
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL filterable (FPM) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL 10 µ (TPM10) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL 2.5 µ (TPM2.5) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR. Particulate matter,
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL filterable (FPM) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL 10 µ (TPM10) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL 2.5 µ (TPM2.5) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR 3‐HR AVERAGE
The fire pump has a maximum
Ultra Low Sulfur heat input rate of 2.63 Particulate matter,
Emergency diesel fire pump 17.21 Distillate oil 0 MMBtu/hr (approximately 250 filterable (FPM) Use of Ultra low sulfur distillate oil 0.15 G/BHP‐HR
Ultra Low Sulfur heat input rate of 2.63 Particulate matter, total <
Emergency diesel fire pump 17.21 Distillate oil 0 MMBtu/hr (approximately 250 10 µ (TPM10) Use of ultra low sulfur distillate oil 0.15 G/BHP‐HR
Ultra Low Sulfur heat input rate of 2.63 Particulate matter, total <
Emergency diesel fire pump 17.21 Distillate oil 0 MMBtu/hr (approximately 250 2.5 µ (TPM2.5) Use of Ultra low sulfur distillate oil 0.15 G/BHP‐HR
rated at 335 BHP and limited to Particulate matter,
Emergency Diesel Fire Pump 17.21 ULSD Fuel Oil #2 0 500 hr/yr (emergency filterable (FPM) 0.15 G/BHP‐HR
rated at 335 BHP and limited to Particulate matter, total <
Emergency Diesel Fire Pump 17.21 ULSD Fuel Oil #2 0 500 hr/yr (emergency 10 µ (TPM10) 0.15 G/BHP‐HR
rated at 335 BHP and limited to Particulate matter, total <
Emergency Diesel Fire Pump 17.21 ULSD Fuel Oil #2 0 500 hr/yr (emergency 2.5 µ (TPM2.5) 0.15 G/BHP‐HR
Firewater Pump Engines 17.21 Diesel 288 hp (each) 10 µ (TPM10) Complying with 40 CFR 60 Subpart IIII 0.15 G/BHP‐HR
Firewater Pump Engines 17.21 Diesel 288 hp (each) 2.5 µ (TPM2.5) Complying with 40 CFR 60 Subpart IIII 0.15 G/BHP‐HR
Ultra Low Sulfur Particulate matter, total < sulfur diesel (S15 ULSD) fuel oil with a maximum
Emergency Fire Water Pump 17.21 Diesel 500 HR/YR 315 BHP 10 µ (TPM10) sulfur content of 15 ppmw. 0.15 G/BHP‐HR
Ultra Low Sulfur Particulate matter, total < sulfur diesel (S15 ULSD) fuel oil with a maximum
Emergency Fire Water Pump 17.21 Diesel 500 HR/YR 315 BHP 2.5 µ (TPM2.5) sulfur content of 15 ppmw. 0.15 G/BHP‐HR
Particulate matter, total
Emergency Diesel Fire Pump, One 600 HP 17.21 ULSD 0 (TPM) 0.15 G/BHP‐HR
ENGINES, IDENTIFIED AS FP01 Particulate matter, COMBUSTION DESIGN CONTROLS AND USAGE
TWO (2) FIREWATER PUMP DIESEL ENGINES 17.21 DIESEL 371 BHP, EACH AND FP02, EXHAUSTING filterable (FPM) LIMITS 0.15 G/BHP‐HR
TWO (2) FIREWATER PUMP DIESEL ENGINES 17.21 DIESEL 371 BHP, EACH AND FP02, EXHAUSTING filterable < 10 µ (FPM10) LIMITS 0.15 G/BHP‐HR
TWO (2) FIREWATER PUMP DIESEL ENGINES 17.21 DIESEL 371 BHP, EACH AND FP02, EXHAUSTING filterable < 2.5 µ (FPM2.5) LIMITS 0.15 G/BHP‐HR 3 HOURS
C42
Particulate matter, total < ULTRA LOW SULFUR DIESEL AND GOOD
EMERGENCY FIRE PUMP 17.21 DIESEL 350 HP 10 µ (TPM10) COMBUSTION PRACTICES 0.15 G/BHP‐HR ANNUAL AVERAGE
Particulate matter, total < ULTRA LOW SULFUR DIESEL AND GOOD
EMERGENCY FIRE PUMP 17.21 DIESEL 350 HP 2.5 µ (TPM2.5) COMBUSTION PRACTICES 0.15 G/BHP‐HR ANNUAL AVERAGE
ULTRA‐LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1500 KW GOOD COMBUSTION filterable (FPM) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR N/A
ULTRA‐LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, total < EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1500 KW GOOD COMBUSTION 10 µ (TPM10) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR N/A
ULTRA‐LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 300 HP GOOD COMBUSTION filterable (FPM) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR N/A
ULTRA‐LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, total < EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 300 HP GOOD COMBUSTION 10 µ (TPM10) GOOD COMBUSTION PRACTICES 0.15 G/BHP‐HR N/A
ULTRA LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, PRACTICES, LIMITED HOURS OF OPERATION, AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 477 HP GOOD COMBUSTION filterable (FPM) DESIGNED TO ACHIEVE EMISSION LIMITS 0.15 G/BHP‐HR
ULTRA LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, total < PRACTICES, LIMITED HOURS OF OPERATION, AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 477 HP GOOD COMBUSTION 10 µ (TPM10) DESIGNED TO ACHIEVE EMISSION LIMITS 0.15 G/BHP‐HR
ULTRA LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, total < PRACTICES, LIMITED HOURS OF OPERATION, AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 477 HP GOOD COMBUSTION 2.5 µ (TPM2.5) DESIGNED TO ACHIEVE EMISSION LIMITS 0.15 G/BHP‐HR
Maximum operation was Particulate matter, TEST PROTOCOL;

Fire Pump 17.21 Diesel 420 HP based on 500 hours per year. filterable (FPM) 0.15 G/BHP‐HR BACT/SIP/NSPS
EU‐FPENGINE: Diesel fuel fired emergency backup fire emergency backup fire mump. Particulate matter, Proper combustion design and ultra low sulfur TEST PROTOCOL WILL
pump 17.21 diesel fuel 315 hp nameplate It has a capacity of 315 hp, filterable (FPM) diesel fuel. 0.15 G/BHP‐HR SPECIFY AVG. TIME
diesel (ultra low Particulate matter, total < Clean burning ULSD fuel and good combusion

FIRE WATER PUMP 17.21 sulfur) 1.86 MMBTU/H 500 H/Yr operation 10 µ (TPM10) practices 0.15 G/BHP‐HR
diesel (ultra low Particulate matter, total < Clean burning ULSD fuel and good combustion

FIRE WATER PUMP 17.21 sulfur) 1.86 MMBTU/H 500 H/Yr operation 2.5 µ (TPM2.5) practices. 0.15 G/BHP‐HR
Ultra‐lowsulfur emergency fire pump engine, Particulate matter, total SHUTDOWN &
Compression ignition RICE emergency fire pump 17.21 diesel (ULSD) 197 HP rated at 197 HP, which shall (TPM) 0.15 G/BHP‐HR MALFUNCTION
Ultra‐lowsulfur emergency fire pump engine, Particulate matter, total < SHUTDOWN &
Compression ignition RICE emergency fire pump 17.21 diesel (ULSD) 197 HP rated at 197 HP, which shall 10 µ (TPM10) 0.15 G/BHP‐HR MALFUNCTION
Ultra‐lowsulfur emergency fire pump engine, Particulate matter, total < SHUTDOWN &
Compression ignition RICE emergency fire pump 17.21 diesel (ULSD) 197 HP rated at 197 HP, which shall 2.5 µ (TPM2.5) 0.15 G/BHP‐HR MALFUNCTION
12‐month rolling period S in Particulate matter, total <
Fire Pump Engine 17.21 ULSD 2.7 MMBTU/H ULSD: ≤0.0015% by weight 10 µ (TPM10) 0.15 G/BHP‐HR 1 HR BLOCK AVERAGE
12‐month rolling period S in Particulate matter, total <
Fire Pump Engine 17.21 ULSD 2.7 MMBTU/H ULSD: ≤0.0015% by weight 2.5 µ (TPM2.5) 0.15 G/BHP‐HR 1 HR BLOCK AVERAGE
Ultra Low Sulfur One 490 hp Airstrip Generator Particulate matter,

Airstrip Generator Engine 17.21 Diesel 490 hp Engine filterable < 10 µ (FPM10) 0.15 G/BHP‐HR
Ultra Low Sulfur One 490 hp Airstrip Generator Particulate matter,

Airstrip Generator Engine 17.21 Diesel 490 hp Engine filterable < 2.5 µ (FPM2.5) 0.15 G/BHP‐HR
Particulate matter,
EMERGENCY FIRE PUMP ENGINE 17.21 DISTILLATE OIL 0 425 HP filterable (FPM) GOOD COMBUSTION PRACTICES 0.16 G/BHP‐HR
EMERGENCY FIRE PUMP ENGINE 17.21 DISTILLATE OIL 0 425 HP 10 µ (TPM10) GOOD COMBUSTION PRACTICES 0.16 G/BHP‐HR
C43
ULTRA LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, total < PRACTICES AND DESIGNED TO ACHIEVE EMISSION
5 EMERGENCY FIRE WATER PUMP ENGINES 17.21 SULFUR DIESEL 350 HP GOOD COMBUSTION 10 µ (TPM10) LIMITS 0.17 G/BHP‐HR
ULTRA LOW LOW‐SULFUR DIESEL FUEL, Particulate matter, total < PRACTICES AND DESIGNED TO ACHIEVE EMISSION
5 EMERGENCY FIRE WATER PUMP ENGINES 17.21 SULFUR DIESEL 350 HP GOOD COMBUSTION 2.5 µ (TPM2.5) LIMITS 0.17 G/BHP‐HR
ULTRAL LOW 40 CFR 60, SUBPART IIII, GOOD Particulate matter, total < GOOD COMBUSTION PRACTICES, LIMITED HOURS FILTERABLE +

EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 350 HP COMBUSTION PRACTICES 10 µ (TPM10) OF OPERATION, AND EXCLUSIVE USE OF ULSD 0.17 G/BHP‐HR CONDENSIBLE
ULTRA‐LOW 63 SUBPART ZZZZ ULTRA LOW‐ Particulate matter, total < EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1490 HP SULFUR DIESEL FUEL, GOOD 10 µ (TPM10) GOOD COMBUSTION PRACTICES. 0.18 G/BHP‐HR
ULTRA‐LOW 63 SUBPART ZZZZ ULTRA LOW‐ Particulate matter, total < EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AN
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1490 HP SULFUR DIESEL FUEL, GOOD 2.5 µ (TPM2.5) DGOOD COMBUSTION PRACTICES 0.18 G/BHP‐HR
ULTRA‐LOW 63 SUBPART ZZZZ, ULTRA LOW‐ Particulate matter, total < EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 305 HP SULFURDIESEL FUEL, GOOD 10 µ (TPM10) GOOD COMBUSTION PRACTICES. 0.18 G/BHP‐HR
ULTRA‐LOW 63 SUBPART ZZZZ, ULTRA LOW‐ Particulate matter, total < EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 305 HP SULFURDIESEL FUEL, GOOD 2.5 µ (TPM2.5) GOOD COMBUSTION PRACTICES 0.18 G/BHP‐HR
DIESEL‐FIRED AUXILIARY (EMERGENCY) ENGINES ULTRA‐LOW GENERATORS (EMERGENCY Particulate matter, total < USE OF ULTRA LOW SULFUR DIESEL AND GOOD
(TWO) 17.21 SULFUR DIESEL 1500 KW GENERATORS), EACH RATED AT 10 µ (TPM10) COMBUSTION PRACTICES. 0.18 G/BHP‐HR
ULTRA‐LOW ENGINE, RATED AT A NOMINAL Particulate matter, total < EXCLUSIVE USE OF ULTRA LOW SULFUR DIESEL FUEL
DIESEL‐FIRED FIRE PUMP ENGINE 17.21 SULFUR DIESEL 300 HP 300‐HORSEPOWER. SUBJECT 10 µ (TPM10) AND GOOD COMBUSTION PRACTICES 0.18 G/BHP‐HR
Emergency engine. BACT = Particulate matter, total
Emergency fire pump engine (300 HP) 17.21 USLD 29 MMBTU/H NSPS IIII. (TPM) Good combustion practice 0.2 G/BHP‐HR
fueled emergency engine Particulate matter,
Emergency Engine ‐‐Diesel Fire Pump (EUFPENGINE) 17.21 Diesel 165 HP manufactured in 2013, iwth a filterable (FPM) Good combustion practices 0.22 G/BHP‐HR TEST PROTOCOL
fueled emergency engine Particulate matter, TEST PROTOCOL WILL
EUFPENGINE (Emergency engine‐‐diesel fire pump) 17.21 diesel 500 H/YR manufactured in 2016 with a filterable (FPM) Good combustion practices. 0.22 G/BHP‐HR SPECIFY AVG TIME
Ultra Low Sulfur ULSD‐fired 102 hp Incinerator Particulate matter,

Incinerator Generator Engine 17.21 Diesel 102 hp Generator Engine filterable < 10 µ (FPM10) 0.22 G/BHP‐HR

Incinerator Generator Engine 17.21 Diesel 102 hp Generator Engine filterable < 2.5 µ (FPM2.5) 0.22 G/BHP‐HR
Cummins 6BTA 5.9F‐1 Diesel Engine Fire Pump 17.21 No. 2 Fuel Oil 182 BHP 10 µ (TPM10) utilize efficient combustion/design technology 0.25 G/BHP‐HR
Cummins 6BTA 5.9F‐1 Diesel Engine Fire Pump 17.21 No. 2 Fuel Oil 182 BHP (TPM) utilize efficient combustion/design technology 0.25 G/BHP‐HR
FWP‐1: 104.0 tons/year (12‐ Particulate matter, total <
DIESEL‐FIRED WATER PUMP 376 bph (1) 17.21 DIESEL FUEL 0 month rolling total) 10 µ (TPM10) Ultra Low Sulfur Diesel/Fuel (15 ppm max) 0.3 G/BHP‐HR PER HR
FWP‐1: 104.0 tons/year (12‐ Particulate matter, total <
DIESEL‐FIRED WATER PUMP 376 bph (1) 17.21 DIESEL FUEL 0 month rolling total) 2.5 µ (TPM2.5) Ultra Low Sulfur Diesel/Fuel (15 ppm max) 0.3 G/BHP‐HR HR
Ultra Low Sulfur ULSD‐fired 98 hp Agitator Particulate matter,

Agitator Generator Engine 17.21 Diesel 98 hp Generator Engine filterable < 10 µ (FPM10) 0.3 G/BHP‐HR

Agitator Generator Engine 17.21 Diesel 98 hp Generator Engine filterable < 2.5 µ (FPM2.5) 0.3 G/BHP‐HR
They are limited to emergency Particulate matter, QP1&QP2 EACH, TEST
4 Diesel‐fired quench pumps 17.21 Diesel fuel 252 HP use and subject to NSPS filterable (FPM) Good combustion practices. 0.4 G/BHP‐HR PROTOCOL
They are limited to emergency Particulate matter, total < QP1&QP2, EACH; TEST
4 Diesel‐fired quench pumps 17.21 Diesel fuel 252 HP use and subject to NSPS 10 µ (TPM10) Good combustion practices. 0.4 G/BHP‐HR PROTOCOL
C44
They are limited to emergency Particulate matter, total < QP1&QP2 EACH; TEST
4 Diesel‐fired quench pumps 17.21 Diesel fuel 252 HP use and subject to NSPS 2.5 µ (TPM2.5) Good combustion practices 0.4 G/BHP‐HR PROTOCOL
Ultra Low Sulfur Particulate matter, sulfur diesel (S15 ULSD) fuel oil with a maximum
Emergency Fire Water Pump 17.21 Diesel 500 HR/YR 315 BHP filterable (FPM) sulfur content of 15 ppmw. 15 G/BHP‐HR
Particulate matter,
emergency engines 17.21 ULSD 0 filterable (FPM) good operating practices 0 G / KWH
FIRE PUMP DIESEL ENGINE 17.21 NO 2 DIESEL 214 kW 10 µ (TPM10) Meets EPA Tier 4 requirements 0.02 G / KWH HR
FIRE PUMP DIESEL ENGINE 17.21 NO 2 DIESEL 214 kW 2.5 µ (TPM2.5) Meets EPA Tier 4 requirements 0.02 G / KWH HR
Particulate matter, Tier IV standards for non‐road engines at 40 CFR
Firewater Pump Engine 17.21 distillate fuel oil 373 hp filterable (FPM) 1039.102, Table 7. 0.1 G / KWH
Particulate matter, total < Tier IV standards for non‐road engines at 40 CFR
Firewater Pump Engine 17.21 distillate fuel oil 373 hp 10 µ (TPM10) 1039.102, Table 7. 0.1 G / KWH
Particulate matter, total < Tier IV standards for non‐road engines at 40 CFR
Firewater Pump Engine 17.21 distillate fuel oil 373 hp 2.5 µ (TPM2.5) 1039.102, Table 7. 0.1 G / KWH
diesel internal combustion Particulate matter, total
Fire Pump Diesel Internal Combustion Engines 17.21 Diesel 252 hp engines. (TPM) Clean Fuel and Good Combustion Practices 0.19 G / KWH 3‐HOUR AVERAGE
diesel internal combustion Particulate matter, total <
Fire Pump Diesel Internal Combustion Engines 17.21 Diesel 252 hp engines. 10 µ (TPM10) Clean Fuel and Good Combustion Practices 0.19 G / KWH 3‐HOUR AVERAGE
diesel internal combustion Particulate matter, total <
Fire Pump Diesel Internal Combustion Engines 17.21 Diesel 252 hp engines. 2.5 µ (TPM2.5) Clean Fuel and Good Combustion Practices 0.19 G / KWH 3‐HOUR AVERAGE
BACT limits equal NSPS IIII Particulate matter, total
Emergency fire pump engine, 300 HP 17.21 Diesel 29 MMBTU/H limits. (TPM) Low‐emitting fuel and certified engine 0.2 G / KWH
Particulate matter,
Emergency Fire Pump Engine (422 hp) 17.21 ULSD 0 Limits equal Subpart IIII limits filterable (FPM) Certified engine 0.2 G / KWH
BACT limits equal to NSPS
Subpart IIII limits. Will use IIII Particulate matter, total
One 422‐hp emergency fire pump engine 17.21 ULSD 0 certified engine. (TPM) Use of clean fuel 0.2 G / KWH
Combustion 17.21 ULSD 493 hp Engines less than 500 hp 2.5 µ (TPM2.5) Good combustion and operating practices. 0.2 G / KWH
Emergency Firewater Pump Particulate matter, total OPERATIONAL RESTRICTION OF 50 HR/YR, OPERATE
EMERGENCY FIREWATER PUMP ENGINE 17.21 DIESEL 135 KW Engine (TPM) AS REQUIRED FOR FIRE SAFETY TESTING 0.2 G / KWH
Emergency Firewater Pump Particulate matter, total < OPERATIONAL RESTRICTION OF 50 HR/YR, OPERATE
EMERGENCY FIREWATER PUMP ENGINE 17.21 DIESEL 135 KW Engine 2.5 µ (TPM2.5) AS REQUIRED FOR FIRE SAFETY TESTING 0.2 G / KWH
EMERGENCY IC ENGINE 17.21 DIESEL 182 HP UNIT IS 135 KW. (TPM) USE ULTRA LOW SULFUR FUEL 0.2 G / KWH
EMERGENCY IC ENGINE 17.21 DIESEL 182 HP UNIT IS 135 KW. 10 µ (TPM10) USE ULTRA LOW SULFUR FUEL 0.2 G / KWH
EMERGENCY IC ENGINE 17.21 DIESEL 182 HP UNIT IS 135 KW. 2.5 µ (TPM2.5) USE ULTRA LOW SULFUR FUEL 0.2 G / KWH
Particulate matter, total (ULSD) fuel oil and GCP & demonstrate compliance
250 Kw Emergency Generator 17.21 ULSD 0 (TPM) in accordance with the procedures given in 40 CFR 0.2 G / KWH
Particulate matter, total < AVERAGE OF 3 STACK TEST
Fire Pump 17.21 diesel fuel 14 GAL/H rated @ 235 KW 2.5 µ (TPM2.5) good combustion practices 0.2 G / KWH RUNS
C45
Particulate matter, total < AVERAGE OF 3 STACK TEST
Fire Pump 17.21 diesel fuel 14 GAL/H rated @ 235 KW 10 µ (TPM10) good combustion practices 0.2 G / KWH RUNS
Particulate matter, total AVERAGE OF 3 STACK TEST
Fire Pump 17.21 diesel fuel 14 GAL/H rated @ 235 KW (TPM) good combustion practices 0.2 G / KWH RUNS
INTERNAL COMBUSTION (CI TIER 3 ENGINE‐BASED, GOOD COMBUSTION
FIRE PUMP ENGINE 17.21 DIESEL 235 KW ICE) Particulate Matter (PM) PRACTICES (GCP) 0.2 G / KWH
ULTRA‐LOW 63 SUBPART ZZZZ ULTRA LOW‐ Particulate matter, EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY GENERATOR 17.21 SULFUR DIESEL 1490 HP SULFUR DIESEL FUEL, GOOD filterable (FPM) GOOD COMBUSTION PRACTICES 0.2 G / KWH
ULTRA‐LOW 63 SUBPART ZZZZ, ULTRA LOW‐ Particulate matter, EXCLUSIVE USE OF ULTRA LOW SULFUR FUEL AND
EMERGENCY DIESEL ENGINE FOR FIRE WATER PUMP 17.21 SULFUR DIESEL 305 HP SULFURDIESEL FUEL, GOOD filterable (FPM) GOOD COMBUSTION PRACTICES 0.2 G / KWH
DIESEL‐FIRED AUXILIARY (EMERGENCY) ENGINES ULTRA‐LOW GENERATORS (EMERGENCY Particulate matter, USE OF ULTRA LOW SULFUR DIESEL AND GOOD
(TWO) 17.21 SULFUR DIESEL 1500 KW GENERATORS), EACH RATED AT filterable (FPM) COMBUSTION PRACTICES 0.2 G / KWH
ULTRA‐LOW ENGINE, RATED AT A NOMINAL Particulate matter, EXCLUSIVE USE OF ULTRA LOW SULFUR DIESEL FUEL
DIESEL‐FIRED FIRE PUMP ENGINE 17.21 SULFUR DIESEL 300 HP 300‐HORSEPOWER. SUBJECT filterable (FPM) AND GOOD COMBUSTION PRACTICES 0.2 G / KWH
emergency fire pump engine Particulate matter,
EUFPENGINE: Fire pump engine 17.21 Diesel 399 BHP with a model year of 2011 or filterable (FPM) State of the art combustion design 0.2 G / KWH HOURLY
Particulate matter, Operate and maintain the engine according to the
Emergency Fire Pump Engine (347 HP) 17.21 ULSD 8700 gal/year Limits equal Subpart IIII limits filterable (FPM) manufacturer's written instructions 0.2 G / KWH
Ultra‐Low Sulfur pump in the firewater system. Particulate matter, total
Firewater Pump Engine 17.21 Diesel 420 horsepower The fuel must meet the (TPM) 0.2 G / KWH
OPERATIONAL LIMITS 1
ULTRA LOW HR/DAY AND 500 HRS/YR FOR Particulate matter, total ENGINE DESIGN AND OPERATION. 15 PPM SULFUR
FIRE BOOSTER PUMP 17.21 SULFUR DIESEL 40 KW PM2.5 NAAQS. (TPM) FUEL. 0.4 G / KWH TEST METHOD
Particulate matter,
Emergency Diesel Generators 17.21 Diesel 250 hp 2 units filterable (FPM) 0.54 G / KWH
2 units at 75 hp, 1 unit at 150 Particulate matter,
Emergency Diesel Generators 17.21 Deisel 150 hp hp filterable (FPM) 1.34 G / KWH
Emergency Diesel Generators 17.21 Deisel 150 hp hp filterable < 10 µ (FPM10) 1.34 G / KWH
Particulate matter,
Emergency Diesel Generators 17.21 Diesel 250 hp 2 units filterable < 10 µ (FPM10) 1.34 G / KWH
C46
Diesel Firewater Pump GHG ‐ RBLC Dataset
Fire Pump 17.21 diesel fuel 14 GAL/H rated @ 235 KW Carbon Dioxide good combustion practices 1.55 G / KWH RUNS
Ultra‐lowsulfur emergency fire pump engine, SHUTDOWN &
Compression ignition RICE emergency fire pump 17.21 diesel (ULSD) 197 HP rated at 197 HP, which shall Carbon Dioxide 2.6 G/BHP‐HR MALFUNCTION
HOURS PER YEAR.
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL Carbon Dioxide GOOD COMBUSTION PRACTICES 527.4 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR.
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL Carbon Dioxide GOOD COMBUSTION PRACTICES 527.4 G/BHP‐HR 3‐HR AVERAGE
DIESEL‐FIRED EMERGENCY WATER PUMP 17.21 NO. 2 FUEL OIL 481 BHP TO 200 HR, Carbon Dioxide GOOD COMBUSTION PRACTICES 527.4 G/BHP‐HR 3‐HR AVERAGE
HOURS PER YEAR.
FIRE PUMP 17.21 500 HP INSIGNIFICANT ACTIVITY, WILL Carbon Dioxide GOOD COMBUSTION PRACTICES 527.4 G/BHP‐HR 3‐HR AVERAGE
500 HOURS PER YEAR.
RAW WATER PUMP 17.21 DIESEL, NO. 2 500 HP INSIGNIFICANT ACTIVITY, WILL Carbon Dioxide GOOD COMBUSTION PRACTICES 527.4 G/BHP‐HR 3‐HR AVERAGE
PROPER OPERATION AND GOOD COMBUSTION
EMERGENCY FIRE PUMP 17.21 DIESEL 350 HP Carbon Dioxide PRACTICES 163 LB/MMBTU
Black start generator, 158 HP Carbon Dioxide Equivalent
Black Start Generator (P007) 17.21 Diesel fuel 158 HP diesel engine. (CO2e) Tier IV engine Good combustion practices 181.7 LB/H
Carbon Dioxide Equivalent
Fire Pump Engine 17.21 Diesel 251 HP Limited to 100 Hours/year. (CO2e) 309 LB/H
617 HP diesel fired Fire Water Carbon Dioxide Equivalent
FWP1‐STK DIESEL FIRED FIRE WATER PUMP 17.21 DIESEL 617 HP Pump. (CO2e) Best Work practice 7027.8 LB/H 30‐DAY ROLLING AVERAGE
12‐month rolling period S in Carbon Dioxide Equivalent
Fire Pump Engine 17.21 ULSD 2.7 MMBTU/H ULSD: ≤0.0015% by weight (CO2e) 162.85 LB/MMBTU
250 hp emergency diesel‐ Carbon Dioxide Equivalent
Emergency diesel‐fueled fire pump (P006) 17.21 Diesel fuel 250 HP fueled fire pump (CO2e) Equipment design and maintenance requirements 163.6 LB/MMBTU
Fire Pump 17.21 diesel fuel 14 GAL/H rated @ 235 KW Methane good combustion practices 0.0001 G / KWH RUNS
EMERGENCY FIRE PUMP 17.21 DIESEL 350 HP Methane PRACTICES 0.0061 LB/MMBTU
EMERGENCY FIRE PUMP 17.21 DIESEL 350 HP Nitrous Oxide (N2O) PRACTICES 0.0014 LB/MMBTU
C47
Fugitive Component Leaks VOC ‐ RBLC Dataset
EMISSION_LIMIT_1_ EMISSION_LIMIT_1_AVG_T
FACILITY_DESCRIPTION PERMIT_NOTES PROCESS_NAME PROCCESS_TYPE PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1 UNIT IME_CONDITION
NOTE: PARTICULATE MATTER
FACILITYWIDE EMISSIONS ARE
PARTICULATE MATTER (FILTERABLE). NATURAL GAS PIPELINE COMPONENTS,
990 MW COMBINED‐CYCLE NATURAL GAS‐ THE FACILITY INCLUDES A WET INCLUDING VALVES, CONNECTORS,
FIRED POWER PLANTNOTE: PARTICULATE MECHANICAL DRAFT COOLING FLANGES, PUMP SEALS AND PRESSURE
MATTER FACILITYWIDE EMISSIONS ARE TOWER (12 CELL) with 0.0005% RELIEF VALVES WITHIN THE FACILITY
PARTICULATE MATTER (FILTERABLE) RECIRCULATING WATER FLOW. EQUIPMENT LEAKS 99.999 BOUNDARY Volatile Organic Compounds (VOC) 0
735 MW COMBINED‐CYCLE NATURAL GAS‐ THE STORAGE TANKS SHALL BE
FIRED POWER PLANT NOTE: PARTICULATE NOTE: PARTICULATE MATTER HORIZONTAL, FIXED‐ROOF TANKS OR
MATTER FACILITYWIDE EMISSIONS ARE FACILITYWIDE EMISSIONS ARE INTEGRAL WITH ENGINE GENERATOR PERIODIC MAINTENANCE ON THE TANKS TO
PARTICULATE MATTER (FILTERABLE) PARTICULATE MATTER (FILTERABLE) FUEL OIL STORAGE TANKS 99.999 BASE FRAME. Volatile Organic Compounds (VOC) MINIMIZE FUGITIVE EMISSIONS 0.1 TON 12‐MONTH ROLLING AVG
C48
Fugitive Component Leaks GHG ‐ RBLC Dataset
PROCCESS EMISSION_LIMIT_1_ EMISSION_LIMIT_1_AVG_

FACILITY_DESCRIPTION PERMIT_NOTES PROCESS_NAME _TYPE PROCESS_NOTES POLLUTANT CONTROL_METHOD_DESCRIPTION EMISSION_LIMIT_1 UNIT TIME_CONDITION
725 MW COMBINED‐CYCLE NATURAL GAS‐ FACILITY‐WIDE PM10 EMISSION IMPLEMENTATION OF AN AUDIO, VISUAL AND
FIRED POWER PLANTFACILITY‐WIDE LIMIT = 96.6 TONS/YR FACILITY‐ OLFACTORY (AVO) PROGRAM ON A WEEKLY
PM10 EMISSION LIMIT = 96.6 TONS/YR WIDE SAM EMISISON LIMIT < 7.0 FUGITIVE GHG EMISSIONS 99.999 Carbon Dioxide Equivalent (CO2e) BASIS 72.7 TONS ANNUAL
735 MW COMBINED‐CYCLE NATURAL GAS‐ NOTE: PARTICULATE MATTER NATURAL GAS PIPELINE IMPLEMENTATION OF AN AUDIO, VISUAL AND
FIRED POWER PLANT NOTE: FACILITYWIDE EMISSIONS ARE COMPONENTS, INCLUDING VALVES, OLFACTORY (AVO) PROGRAM ON FILE AT
PARTICULATE MATTER FACILITYWIDE PARTICULATE MATTER (FILTERABLE) EQUIPMENT LEAKS 99.999 CONNECTORS, FLANGES, PUMP SEALS Carbon Dioxide Equivalent (CO2e) POWER PLANT SITE FOR REVIEW UPON 0
Authorizes FGE to construct a new The Texas Commission on
combined cycle electric generating plant Environmental Quality is the
(FGETP) in Mitchell County, Texas. FGETP permitting authority for the non‐ SF6 Fugitive Emission Sources 99.999 Carbon Dioxide Equivalent (CO2e) 0
Authorizes FGE to construct a new The Texas Commission on
combined cycle electric generating plant Environmental Quality is the Natural Gas Fugitive Emission
(FGETP) in Mitchell County, Texas. FGETP permitting authority for the non‐ Sources 99.999 Carbon Dioxide Equivalent (CO2e) 0
GSEC proposes to construct a gas turbine TCEQ is the permitting authority for The circuit breakers associated with
to expand capacity at an existing power the non‐GHG emissions. See: Fugitive Emissions from SF6 the proposed units will be insulated
plant (Antelope Elk Energy Center) CN602667787 and RN105862510 Circuit Breakers 99.999 with SF6. The capacity of the circuit Carbon Dioxide Equivalent (CO2e) 0 WORK PRACTICE
GSEC proposes to construct a gas turbine TCEQ is the permitting authority for The circuit breakers associated with
to expand capacity at an existing power the non‐GHG emissions. See: Fugitive Emissions from SF6 the proposed units will be insulated
plant (Antelope Elk Energy Center) CN602667787 and RN105862510 Circuit Breakers 99.999 with SF6. The capacity of the circuit Carbon Dioxide Equivalent (CO2e) 0 WORK PRACTICE
GPP proposes to add two (2) new gas‐ The Texas Commission on The circuit breakers associated with
fired simple‐cycle combustion turbines of Environmental Quality is the Fugitive SF6 Circuit Breaker the proposed units will be insulated
227 MW (nominal) electric generating permitting authority for the non‐ Emissions 99.999 with SF6. The capacity of the circuit Carbon Dioxide Equivalent (CO2e) 0
GPP proposes to add two (2) new gas‐ The Texas Commission on Emissions from piping components
fired simple‐cycle combustion turbines of Environmental Quality is the Components Fugitive Leak (valves and flanges) associated with
227 MW (nominal) electric generating permitting authority for the non‐ Emissions 99.999 this project consist of methane (CH4) Carbon Dioxide Equivalent (CO2e) 0
Indeck proposes to construct a peaking The Texas Commission on The circuit breakers associated with
power plant, the Indeck Wharton Energy Environmental Quality is the Fugitive SF6 Circuit Breaker the proposed units will be insulated
Center, generally located south of permitting authority for the non‐ Emissions 99.999 with SF6. The capacity of the circuit Carbon Dioxide Equivalent (CO2e) 0
Indeck proposes to construct a peaking The Texas Commission on Fugitive emissions from piping
power plant, the Indeck Wharton Energy Environmental Quality is the Components Fugitive Leak components (valves and flanges)
Center, generally located south of permitting authority for the non‐ Emissions 99.999 associated with this project consist of Carbon Dioxide Equivalent (CO2e) 0
Invenergy proposes to construct a 330 Texas Commission on
MW peak power plant (known as the Environmental Quality is the Fugitive SF6 Circuit Breaker
Ector County Energy Center Plant (ECEC)), permitting authority for the non‐ Emissions 99.999 Carbon Dioxide Equivalent (CO2e) 0
The use of circuit breakers with totally enclosed
insulation systems equipped with a low
Sulfur hexafluoride (SF6) The facility will consist of Four SF6 pressure alarm and low pressure lockout is
simple cycle electric generation insulated Electrical Equipment 99.999 insulated circuit breakers. Carbon Dioxide Equivalent (CO2e) BACT 34.4 T/YR
weekly checks for leaks using audio, visual, and
simple cycle electric generation Natural Gas Fugitives 99.999 Carbon Dioxide Equivalent (CO2e) olfactory (AVO) sensing for natural gas leaks 693.3 T/YR
The proposed project will be a new,
nominal 1,600 MW combined‐cycle GAS PIPING COMPONENTS‐ Audible/visual/olfactory (AVO) monitoring and
electrical power generating facility FUGITIVE LEAKS 99.999 Carbon Dioxide Equivalent (CO2e) leak repair 0
C49
Natural Gas Fired Simple Cycle Turbine PM10 LAER ‐ RBLC Dataset
turbine generators (CTG). Each Particulate matter, total < AT LOADS OF 80% OR
COMBUSTION TURBINES (NORMAL OPERATION) 15.11 NATURAL GAS 300 MW CTG rated at 100 MW (nominal 10 µ (TPM10) PUC‐QUALITY NATURAL GAS 0.0065 LB/MMBTU (HHV) HIGHER
Combustion Turbines (GEN1 and GEN2) 15.11 Natural Gas 2217 MMBtu/hr heat input rate of 2,217 10 µ (TPM10) Clean fuel and good combustion practices 0.0048 LB/MMBTU TEST AVERAGE
Two Simple Cycle Combustion Turbines 15.11 Natural Gas 190 MW purposes and fired primarily 10 µ (TPM10) turbine design and good combustion practices 0.005 LB/MMBTU 3‐HOUR BLOCK AVERAGE
Particulate matter, USE NATURAL GAS AS PRIMARY FUEL; GOOD 3‐HR AVG FOR NATURAL

PRATT & TWIN‐PAC SIMPLE CYCLE TURBINES 15.11 NATURAL GAS 270.9 MMBTU/H NO. 2 DIESEL OIL BACKUP FUEL filterable < 10 µ (FPM10) COMBUSTION PRACTICES 0.0066 LB/MMBTU GAS
recovery steam generator 15.11 Natural Gas 0 turbines duct burners and heat 10 µ (TPM10) 0.0066 LB/MMBTU
2 COMBUSTION TURBINES 15.11 NATURAL GAS 130 MW TURBINES (CTS) WITH A 10 µ (TPM10) COMBUSTION PRACTICES 0.007 LB/MMBTU AVERAGE, EXCEPT SU/SD

Gas turbines (9 units) 15.11 natural gas 1069 mm btu/hr 10 µ (TPM10) gas 0.0076 LB/MMBTU AVERAGE
Combined cycle combustion turnbine with HRSG and Natural gas burner Max fuel input for CTs Particulate matter, total < THREE(3) HOUR ROLLING
duct firing 15.11 pipeline quality 849 MW and HRSGs 6,714 mmBtu/hr 10 µ (TPM10) Combust only pipeline quality natural gas 0.0088 LB/MMBTU AVERAGE
BOSQUE POWER COMPANY IS BACT IS THE USE OF PIPELINE‐QUALITY NATURAL
SEEKING TO AMEND THEIR GAS AND THE APPLICATION OF GOOD
ELECTRICAL GENERATION 15.11 NATURAL GAS 170 MW EXISTING PERMIT TO Particulate Matter (PM) COMBUSTION CONTROLS. WITH THIS METHOD OF 0.01 LB/MMBTU 3 HR ROLLING PERIOD
Turbines (4), simple cycle, natural gas 15.11 NATURAL GAS 15020 H/YR turbines filterable < 10 µ (FPM10) 0.013 LB/MMBTU ACTUAL HEAT INPUT
TURBINES 15.11 NATURAL GAS 80 MW filterable < 10 µ (FPM10) GOOD COMBUSTION PRACTICES 5 LB/HR EACH TURBINE
(2) 60‐MW SIMPLE CYCLE COMBUSTION TURBINES, WHITNEY GAS TURBINE Particulate matter, total < GOOD COMBUSTION PRACTICES AND USE OF
FIRING NATURAL GAS 15.11 NATURAL GAS 120 MW GENERATOR PACKAGE 10 µ (TPM10) NATURAL GAS 5 LB/HR 3 STACK TEST RUNS
ROYCE, 8 15.11 NATURAL GAS 603 MMBTU/H SIMPLE CYCLE COMBUSTION filterable < 10 µ (FPM10) CONTENT OF 15 PPM. 5 LB/HR
SIMPLE CYCLE (NO WASTE HEAT RECOVERY)(>25 MW) 15.11 NATURAL GAS 5000 MMFT3/YR CYCLE COMBUSTION TURBINE. filterable < 10 µ (FPM10) OIL WITH 15 PPMSULFUR BY WEIGHT AS BACKUP 5 LB/HR AVERAGE OF THREE TESTS
Simple Cycle Stationary Turbines firing Natural gas 15.11 Natural Gas 2143980 MMBTU/YR combustion turbine generators 10 µ (TPM10) Use of Natural gas a clean burning fuel 5 LB/HR TESTS EVERY 5 YR
Particulate matter, Good Combustion Practices as described in the
Normal Mode (without Power Augmentation) 15.11 natural gas 0 filterable < 10 µ (FPM10) permit. 5.4 LB/HR HOURLY
Increase power output by
lowering the outlet air Particulate matter, Good combustion practices as defined in the
Power Augmentation 15.11 natural gas 0 temperatur through water filterable < 10 µ (FPM10) permit. 5.4 LB/HR HOURLY
GE LM6000PC SPRINT Simple cycle combustion turbine 15.11 natural gas 405.3 MMBTU/hr 10 µ (TPM10) fire only pipeline quality natural gas 6 LB/HR AT FULL OAD
SIMPLE CYCLE TURBINE 15.11 Natural Gas 8940000 (HHV) for all six gas turbines. The 6 10 µ (TPM10) Fuel: Natural gas 6 LB/HR AVERAGE OF THREE TESTS
(Commissioning) [SCN0005] 15.11 Natural Gas 2201 MM BTU/hr construction and is not 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
(Commissioning) [SCN0006] 15.11 natural gas 2201 MM BTU/hr construction and is not 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
[EQT0019] 15.11 Natural Gas 2201 MM BTU/hR Limited to 600 hr/yr 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
C50
Natural Gas Fired Simple Cycle Turbine PM10 LAER ‐ RBLC Dataset
[EQT0020] 15.11 Natural Gas 2201 MM BTU/hr limited to 600 hr/yr 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM

(Normal Operations) [EQT0017] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hrs/yr 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM

(Normal Operations) [EQT0018] 15.11 Natural Gas 2201 MM BTU/hr on 7000 hours per year 10 µ (TPM10) sulfur fuels (pipeline quality natural gas) 6.3 LB/HR HOURLY MAXIMUM
gas‐fired, simple cycle CTG Particulate matter, total < Use of pipeline quality natural gas and good AVE OVER STACK TEST
Three simple cycle combustion turbines 15.11 natural gas 799.7 MMBTU/H rated at 799.7 MMBtu per 10 µ (TPM10) combustor design 6.6 LB/HR LENGTH
Turbine is a GE Model PG 7121 Particulate matter, total <
Combustion Turbine 15.11 Natural gas 986 MMBTU/H (7EA) used as a peaking unit. 10 µ (TPM10) Good Combustion Practices 7.3 LB/HR AVERAGE OF 3 TEST RUNS
Simple Cycle Combustion Turbines (SCCT1 to SCCT3) 15.11 Natural Gas 927 MM BTU/h 10 µ (TPM10) Design. 8 LB/HR 3 HOUR AVERAGE
THE PROCESS USES FUEL OIL GOOD COMBUSTION PRACTICES PIPELINE QUALITY 3 HOUR
SIMPLE CYCLE COMBUSTION TURBINE ‐ ELECTRIC FOR BACKUP AT THE RATE OF Particulate matter, total < NATURAL GAS, ULTRA LOW SULFUR DISTILLATE AVERAGE/CONDITION
GENERATING PLANT 15.11 NATURAL GASE 1530 MW 2129 MMBUT/H 10 µ (TPM10) FUEL 9.1 LB/HR 3.3.23
GE LMS‐100 combustion turbines, simple cycle with Particulate matter, total < Utilize only natural gas or ULSD fuel; Limit the time

water injection 15.11 natural gas 1690 MMBTU/H 10 µ (TPM10) in startup or shutdown. 9.1 LB/HR 6‐HR AVERAGE ON NG
Natural Gas Usage:
Burner Firing Natural Gas 15.11 Natural Gas 28169501 MMBTU/YR which includes maximum ultra 10 µ (TPM10) Use of natural gas a clean burning fuel 14.4 LB/HR TESTS
TURBINE EXHAUST STACK NO. 1 & NO. 2 15.11 NATURAL GAS 1900 MM BTU/H EACH 10 µ (TPM10) USE OF PIPELINE NATURAL GAS 17 LB/HR HOURLY MAXIMUM
GE 7FA Simple Cycle Combustion Turbine 15.11 natural gas 1780 MMBTU/HR 10 µ (TPM10) will fire only pipeline quality natural gas 18 LB/HR

firing natural gas 15.11 Natural Gas 0 10 µ (TPM10) Use of natural gas a clean burning fuel 22.6 LB/HR TESTS
Five 200‐MW combustion turbines 15.11 Natural gas 2100 (approx) per year per turbine. Of the 10 µ (TPM10) Clean fuel prevents PM formation 2 GR. S / 100 SCF GAS FUEL RECORD KEEPING
Combustion Turbines 15.11 Natural gas 2262.4 MMBtu/hr gas Natural‐gas is primary fuel. 10 µ (TPM10) Use of clean fuels 2 GR. S / 100 SCF GAS FOR NATURAL GAS
TWO SIMPLE CYCLE COMBUSTION TURBINE ‐ MODEL SULFUR DIESEL WITH A Particulate matter, total < 6‐MINUTE BLOCK BY EPA
7FA 15.11 NATURAL GAS 170 MW MAXIMUM SULFUR CONTENT 10 µ (TPM10) 10 % OPACITY METHOD 9
C51
Natural Gas Fired in‐line Fuel Gas Heater PM10 LAER ‐ RBLC Dataset
will be installed. The Carbon Dioxide Equivalent
Heaters (Gas‐Fired) 13.31 Natural Gas 0 application requested that the (CO2e) Natural Gas Fuel 120 LB/MMBTU
Startup Heater 13.31 natural gas 58.8 MMBTU/H natural gas/yr Carbon Dioxide good operating practices & use of natural gas 117 LB/MMBTU STACK TEST RUNS
Startup Heater 13.31 natural gas 58.8 MMBTU/H natural gas/yr Methane good operating practices & use of natural gas 0.0023 LB/MMBTU STACK TEST RUNS
Startup Heater 13.31 natural gas 58.8 MMBTU/H natural gas/yr Nitrous Oxide (N2O) good operating practices & use of natural gas 0.0006 LB/MMBTU STACK TEST RUNS
PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Carbon Dioxide GOOD OPERATING PRACTICES 117 LB/MMBTU

PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Methane GOOD OPERATING PRACTICES 0.0022 LB/MMBTU
PREHEATER, GALVANIZING LINE SN‐28 13.31 NATURAL GAS 78.2 MMBTU/HR Nitrous Oxide (N2O) GOOD OPERATING PRACTICES 0.0002 LB/MMBTU
C52
Diesel Firewater Pump PM10 LAER‐ RBLC Dataset

Incinerator Generator Engine 17.21 Diesel 102 hp Generator Engine filterable < 10 µ (FPM10) 0.22 G/BHP‐HR

Incinerator Generator Engine 17.21 Diesel 102 hp Generator Engine filterable < 2.5 µ (FPM2.5) 0.22 G/BHP‐HR

Agitator Generator Engine 17.21 Diesel 98 hp Generator Engine filterable < 10 µ (FPM10) 0.3 G/BHP‐HR

Agitator Generator Engine 17.21 Diesel 98 hp Generator Engine filterable < 2.5 µ (FPM2.5) 0.3 G/BHP‐HR
Emergency Diesel Generators 17.21 Deisel 150 hp hp filterable (FPM) 1.34 G / KWH
Emergency Diesel Generators 17.21 Deisel 150 hp hp filterable < 10 µ (FPM10) 1.34 G / KWH
C53
Texas Commission on Environmental Quality
Gas Turbines Rated 20 MW and Greater Electric Output
7/5/2019
This is a list of natural gas-fired turbine projects authorized by TCEQ that generate 20 megawatts (MW) or more greater electric output. It shows their permit numbers, turbine models, number of turbines, power output per turbine and site wide in MW, emissions controls, mode of operation (simple cycle [SC],
combined cycle [CC], or cogeneration), and BACT emission concentrations for NOx and CO.
Pending Air NSR Permits for Criteria or GHG Pollutants GHG Pollutant Permits
Permit No. PSD NA/S/HAP Received Issue Date Company Name City County Turbine Model Number of CTs MW per CT Project MW NOx (1) Control Method CO (1) SC/CC Permit No. Issue Date
157256 S 7/5/19 Pending Avocet Power Center Lufkin Angelina LM6000 3 50 150 25 SCR 24 SC NA NA
(1) BACT, LAER or Std Permit limit (ppmvd @ 15% O2)
Issued Permits GHG Permits
157171 S 6/4/19 6/13/2019 Goodalta Power Center LLC Kerens Navarro LM6000 3 50 150 25 SCR 24 SC NA NA
156710 S 5/1/19 5/21/2019 Altajac Power Center LLC Jacksonville Cherokee LM6000 3 50 150 25 SCR 24 SC NA NA
155895 S 3/7/19 3/18/2019 SJRR Power LLC Houston Harris LM6000 4 50 200
155736 S 2/25/19 3/11/2019 ProEnergy Services LLC Texas City Galveston LM6000 10 50 500 4 SCR +CO+W 9 SC NA NA
155312 intentionally S 1/24/19 3/13/2019 NGO Industrial Holdings LLC Palestine Anderson LM6000 4 50 200 25 SCR 20 SC NA NA
155311 intentionally S 1/24/19 3/17/2019 NGO Industrial Holdings LLC Sealy Austin LM6000 4 50 200 25 SCR 20 SC NA NA
154703 intentionally S 12/6/18 12/20/2018 ProEnergy Services LLC Texas City Galveston LM6000 8 50 400 4 SCR +CO+W 9 SC NA NA
154682 intentionally S 12/4/18 12/20/2018 ProEnergy Services LLC Jacksonville Cherokee LM6000 8 50 400 4 SCR +CO+W 9 SC NA NA
154626 intentionally S 11/30/18 12/12/2018 ProEnergy Services LLC Iowa Colony Brazoria LM6000 4 50 200 4 SCR +CO+W 9 SC NA NA
154565 intentionally S 11/28/18 12/19/2018 ProEnergy Services LLC Santa Fe Gavleston LM6000 6 50 300 4 SCR +CO+W 9 SC NA NA
154465 intentionally S 11/16/18 12/4/2018 ProEnergy Services LLC Thompsons Fort Bend LM6000 8 50 400 4 SCR +CO+W 9 SC NA NA
153484 intentionally S 9/7/18 9/17/2018 ProEnergy Services LLC Houston Harris LM6000 PC 6 40 240 2 SCR + CO + W 2 SC NA NA
152697 intentionally S 7/11/18 8/10/2018 Castleman Power Development LLC Victoria Victoria LM6000 2 50 100 25 SCR 20 SC NA NA
Siemens
152680 intentionally S 7/10/18 8/10/2018 Friendswood Energy Genco LLC Houston Harris W501D 1 129 129 3.4 DLN+ SCR 25 SC NA NA
Mitsubishi †
143912 1510 N256 11/14/16 3/27/2018 Entergy Texas Inc Willis Montgomery 2 368 993 - CC 2 DLN + SCR + CO 2 CC 163 3/27/2018
M501GAC
146823 intentionally S 5/12/17 6/9/2017 Victoria City Power LLC Victoria Victoria LM6000 2 50 100 4 DLN + SCR 20 SC na na
146805 intentionally S 5/12/17 6/15/2017 Victoria Port Power LLC Victoria Victoria LM6000 2 50 100 4 DLN + SCR 20 SC na na
1492 N246
Withdrawn
138152 Withdrawn Withdrawn 12/16/15 2/26/2018 AES Gen Dev LLC Pasadena Harris GE 7FA 2 224 448 5 DLN 9 SC 153
7/5/2017
7/5/2017 7/5/2017
121917 1422 intentionally l 7/14/14 2/2/2018 Southern Pwr Co (Jackson Gen Fac) Ganado Jackson Siemens F(5) 4 230 920 9 DLN 9 SC 118 6/30/2017†
4/11/2012,
72579 1080 12/22/15 Golden Spread El. Coop Mustang Denver City Yoakum GE F7FA 1 168 168 9 DLN 9 SC 138 8/16/17
intentionally l 8/16/2017
9 -15 9 -20
227 -SC 910 - SC DLN - SC
135322 1470 8/24/15 4/28/2017 Southwestern Public Svc Co (Xcel Energy) Seminole Gaines SGT6-5000F5 4 SC SC SC/CC 141 4/28/17
426 - CC 1706 - CC DLN+SCR+CO - CC
intentionally l 2 - CC 2 CC
Formosa Plastics Corporation, Texas (Split
140763 1500 5/18/16 4/17/2017 Point Comfort Calhoun SGT6-2000E 2 117 234 2 DLN + SCR + CO 4 CC/COG na na
CTs 7 & 8 from Pmt 19166 onto own permit)
intentionally l
FGE Eagle Pines, LLC (Different turbines, New GE 7HA /
131316 1454 10/10/16 2/14/2017 Cherokee 6/9 346 / 242 3,408 2 DLN + SCR + CO 2 CC 133* 11/4/15
Alstoms no longer available) Summerfield Siemens 5000F
intentionally l
INEOS USA (Chocolate Bayou, NRG Tx Pwr
123117 1460 N204 8/29/14 2/10/2017 Alvin Brazoria GE LM6000 2 50 100 2.5 DLN + SCR + CO 4 CC/COG 135 2/10/17
LLC)
110025 1364 intentionally l 8/8/16 12/16/2016 FGE Texas (FGE Power, Different Turbines) Westbrook Mitchell SGT6-5000F 4 CTs Iss. 3/14 242 1,448 2 DLN + SCR + CO 2 CC 36 12/12/16
CTs Iss.
107569 1432 8/19/14 3/8/2016 DeCordova II Pwr Co LLC (Luminant) Granbury Hood Add stm turb 310-350 - - - CC 124 10/3/16
intentionally l 8/29/13
GE 7FA.05 or 210 or 730 or
117026 1390 N194 1/27/14 6/18/2015 Eagle Mtn Pwr Co LLC (Luminant) Fort Worth Tarrant 2 2 DLN + SCR + CO 2 CC 115 7/19/16
S GT6-5000F 231 812
GE FA.03, 04,
130051 1450 2/9/15 4/7/2016 Brazos Electric Grandview Hill or 05 4 154 - 232 616 - 928 9 DLN 9 SC 131 4/7/16
intentionally l or SGT6F5ee
GE F.05 or H.01
122003 1424 7/18/14 2/9/2015 Rockwood Energy Center LLC Garwood Colorado MHI 501GAC,or 2 234 - 343 748 - 915 2 DLN + SCR + CO 2 CC 122 3/18/16
intentionally l S SCC6-8000F
138452 intentionally S 1/27/16 3/4/2016 Castleman Pwr Systems Int'l LLC Houston Harris GE LM6000 2 50 100 4 DLN + SCR 20 SC na na
Mitsubishi J
111393 1368 6/27/13 11/20/2014 Southern Power Company Trinidad Henderson 1 450 530 2 DLN+SCR+CO 4 CC 125 3/1/16
intentionally l model
77679 1061M1 intentionally l 1/15/14 10/14/2015 Nacogdoches Pwr LLC (Southern Co.) Cushing Nacogdoches Siemens F5 1 232 232 9 DLN 9 SC 116 3/1/16
121051 1418 intentionally l 6/23/14 10/27/2015 Navasota North Peakers Op Co LLC Van Alstyne Grayson GE 7FA.04 3 183 550 9 DLN 9 SC 119 1/13/16
120973 1420 intentionally l 6/23/14 12/9/2015 Navasota South Peakers Op Co LLC Nixon Wilson GE 7FA.04 3 183 550 9 DLN 9 SC C54117 12/16/15
Page 1 of 6
GE F.03 or.05
122733 8/14/14 12/8/2015 Halyard Energy Henderson LLC LaRue Henderson 2 193-232 386-464 9 DLN 9 SC na na
intentionally intentionally l or S F5ee
125963 1442 intentionally l 11/25/14 10/9/2015 Shawnee Energy Center (repermit w/o SCR) Abbott Hill S GT6-5000F 4 230 920 9 DLN 9 SC 126 11/10/15
120849 1414 intentionally l 6/18/14 5/8/2015 Navasota South Peakers Op Co LLC Seguin Guadalupe GE 7FA.04 3 183 550 9 DLN 9 SC 120 11/10/15
135738 intentionally S 9/15/15 11/6/2015 Powersite LLC Wink Winkler R-R Trent 60 4 58 372 2.5 DLN + SCR 3 CC na na
132827 intentionally intentionally l 5/26/15 11/5/2015 NTE Texas LLC (rev. 117537) Blackwell Nolan GE FA.04 2 184 328 9 DLN 9 SC na na
131316 1454 intentionally l 3/27/15 11/4/2015 FGE Eagle Pines, LLC New Summerfld Cherokee Alstom GT36 6 318 3,408 2 DLN + SCR + CO 2 CC 133* 11/4/15
GE FA.05 210 or 420 or 7.5
130017 2/9/15 10/15/2015 Luminant Gen Co LLC - Permian Basin Sta. Monahans Ward 2 9 DLN SC na na
intentionally intentionally l or S F5ee 231 632 4
GE F.03 or.05
129329 12/22/14 10/9/2015 Halyard Energy Wharton LLC El Campo Wharton 2 193-232 388-464 9 DLN 9 SC na na
intentionally intentionally l or S F5ee
GE 7FA-05 or
102731 1294 5/10/12 12/19/2014 NRG Texas Pwr LLC SR Bertron La Porte Harris Siemens F(5) or 2 255 823 2 DLN+SCR+CO 2 SC/CC 104 9/15/15
M 501GAC
intentionally l
GE 7FA-05 or
NRG Texas Pwr LLC
105810 1308 9/12/12 8/29/2014 Baytown Chambers Siemens F(5) or 2 255-264 728 2 DLN+SCR+CO 2 CC 102 9/15/15
(Cedar Bayou)
M 501GAC
intentionally l
GE FA.05 210 or 420 or 7.5
128432 12/23/14 9/10/2015 Valley NG Pwr Co LLC (Luminant) Savoy Fannin 2 9 DLN SC na na
intentionally intentionally l or S F5ee 231 632 4
133367 intentionally S 6/15/15 7/3/2015 Castleman Pwr Systems Int'l LLC Point Comfort Calhoun GE LM6000 2 50 100 4 DLN + SCR 20 SC na na
109148 1358M1 intentionally l 7/15/14 5/12/2015 Golden Spread El. Coop. - Antelope Elk Sta. Abernathy Hale GE 7FA.05 3 202 600 9 DLN 9 SC 41M1 5/20/15
131873 intentionally S 4/15/15 5/8/2015 NET Power, LLC (demo project) LaPorte Harris Toshiba CO2 1 25 25 * oxyfired * CO2 na na
118549 intentionally intentionally l 3/28/14 5/5/2015 Wharton County Gen LLC (GDF Suez NA) Boling Wharton GE 7FA.05 1 230 230 9 DLN 9 SC na na
119365 1410 intentionally l 4/18/14 4/1/2015 Colorado Bend Energy Center (Exelon) Wharton Wharton GE 7HA.02 2 330 1,160 2 DLN + SCR + CO 4 CC 112 4/1/15
48106 1012M2 intentionally l 9/13/13 3/20/2015 City of Austin - Sand Hill En. Ctr. Del Valle Travis GE 7FA.04 1 173.9 173.9 2 DLN+SCR+CO 2 CC 1012M2GHG 9/29/14
GE 7FA or
111724 1374 6/18/13 2/2/2015 Indeck Wharton, LLC Danevang Wharton 3 220 650 9 DLN 9 SC 1374GHG 5/12/14
Siemens 5000F
intentionally l
108411 1350 intentionally l 2/22/13 4/29/2014 Tenaska Brownsville Partners LLC Brownsville Cameron MHI 501GAC 1 or 2 275 400-800 2 DLN+SCR+CO 2 CC 1350GHG 1/23/15
117537 intentionally intentionally l 2/13/14 12/19/2014 NTE Texas LLC Blackwell Nolan MHI 501GAC 1 273 273 9 DLN 9 SC na na
124811 intentionally S 10/29/14 12/3/2014 Shawnee Energy Center Abbott Hill S GT6-5000F 4 230 920 4 DLN + SCR 2 SC na na
108819 1354 intentionally l 2/22/13 12/2/2014 M & G Resins USA, LLC Corpus Christi Nueces GE LM6000 1 38 38 2 DLN+SCR+CO 2 CC 1354GHG 11/18/14
GE 7FA.04 or
108258 1348 2/14/13 12/1/2014 Victoria WLE LP Victoria Victoria 1 275 450-460 2 DLN+SCR+CO 2 CC 1348GHG 10/8/14
intentionally l equivalent
GE 7FA.05 or
117857 2/27/14 10/27/2014 Lake Creek 3 Pwr Co LLC (Luminant) Riesel McLennan 2 225 or 230 460 9 DLN 9 SC na na
S GT6-5000F(5)
intentionally intentionally l
GE 7FA.05,
114698 1378 10/25/13 9/22/2014 Tenaska Roans Prairie Partners, LLC Shiro Grimes 7FA.04, or 3 169 - 231 507 - 694 9 DLN 9 SC 1378GHG 8/1/14
S GT6-5000F(5)
intentionally l
R-R Trent
122777 S 8/18/14 9/17/2014 Powersite LLC Perrin Jack 4 60.55 372 3 DLN+SCR+CO 3 CC na na
intentionally 60 DLE ISI
19166 760 intentionally l 12/21/12 8/8/2014 Formosa Plastics (add CTs 7&8) Point Comfort Calhoun GE F7E 2 80 2 DLN + SCR 25 CC/COG 1389GHG 8/1/14
110423 1366 5/13/13 8/1/2014 Invenergy Thermal Dev LLC Ector Co En Ctr Goldsmith Ector GE 7FA.03 2 165-193 330-386 9 DLN 9 SC 1366GHG 8/1/14
intentionally l
104840 1302 intentionally l 7/20/12 7/16/2014 Freeport LNG Development, LP Quintana Brazoria GE F7E 1 87 87 2 DLN+SCR+CO 4 CC na na
GE 7FA.05 or
120681 S 6/11/14 7/15/2014 Optim En. Twin Oaks (repowering) Bremond Robertson 2 225 or 230 668 5 DLN+SCR+CO 5 CC na na
intentionally S GT-5000F
108182 intentionally intentionally l 2/6/13 5/20/2014 NRG Tx Pwr LLC (PH Robinson Sta) Bacliff Galveston GE F7E 6 65 390 15 DLN 25 SC na na
109148 1358 intentionally l 4/1/13 4/22/2014 Golden Spread El. Coop. - Antelope Elk Sta. Abernathy Hale GE 7FA.05 1 190 190 9 DLN 9 SC 1358GHG 6/2/14
118876 intentionally S 4/7/14 4/11/2014 Apex Bethel En Ctr LLC (reissue) Tenn. Colony Anderson D-R EA-418 (CAE 2 158 317 2.5 W+SCR+CO 5 CAES 104511GHG 3/13/14
110025 1364 intentionally l 5/6/13 3/24/2014 FGE Power, LLC Westbrook Mitchell Alstom GT24 4 231 1600 2 DLN+SCR+CO 2 CC 1364GHG 4/28/14
GE 7FA.05 or
110357 5/23/13 2/7/2014 Tradinghouse Pwr Co LLC (Luminant) Waco McLennan 2 225-230 450-460 9 DLN 9 SC na na
S GT6-5000F(5)
R-R Trent
115851 S 12/13/13 1/27/2014 Powersite LLC Kenedy Karnes 4 60.55 372 3 DLN+SCR+CO 3 CC na na
intentionally 60 DLE ISI
102294 1290 intentionally l 4/20/12 1/21/2014 El Paso Electric (Reissued as S No. 123471) El Paso El Paso GE LMS100 4 100 400 2.5 W+SCR+CO 4 SC 1290GHG 3/15/14
GE 7FA.05 or
103839 1298 6/22/12 11/12/2013 Pinecrest Energy Center LLC Lufkin Angelina 2 183-225 637-721 2 DLN+SCR+CO 2 CC 1298GHG 7/31/14
intentionally l S GT6-5000F
GE 7FA.03/.04
106011 1310 9/24/12 10/2/2013 Guadalupe Power Partners LP Marion Guadalupe 2 192-227 383-454 9 DLN 9 SC 1310GHG 12/2/14
intentionally l /.05 or S5000F
GE 7FA.05 or
107569 12/27/12 8/29/2013 DeCordova II Pwr Co LLC (Luminant) Granbury Hood 2 225-230 450-460 9 DLN 9 SC na na
intentionally intentionally l S GT6-5000F(5)
108130 intentionally S 2/5/13 2/27/2013 Chamisa CAES at Tulia LLC Tulia Swisher D-R (CAES) 2 135 270 SCR+CO CAES 108130 3/21/14
GE 7FA.04 or
101542 1288 3/15/12 2/7/2013 La Paloma Energy Center Harlingen Cameron 2 183-232 637-735 2 DLN+SCR+CO 2 CC 1288GHG 11/16/13
intentionally l SGT6-5000F
C55
Page 2 of 6
Petra Nova Parish Holdings (aka NRG Tx,
98664 1268 N138 9/19/11 12/21/2012 Thompson Fort Bend GE F7EA 1 80 80 2 DLN+SCR 9 SC/COG na na
WA Parish CO2 proj)
42179 955M1 N021M1 11/3/11 10/15/2012 Calpine - Channel Energy Center LLC Pasadena Harris Siemens 501F 1 180 180 2 DLN+SCR 8 CC 955M1 11/29/12
105567 intentionally S 8/24/12 9/28/2012 Texas En Dev Svcs LLC (CO2) Point Comfort Calhoun GE LMS100 1 116 250 3.4 DLN+SCR CC no no. not @TCEQ
45642 979M2 N036M2 9/1/11 9/26/2012 Calpine - Deer Park Energy Center LLC Deer Park Harris Siemens 501F 1 180 180 2 DLN+SCR 8 CC 979M2 11/29/12
96336 1256 intentionally l 5/27/11 9/12/2012 Calhoun Port Authority - ES Joslin Point Comfort Calhoun GE F7FA 3 185 887 2 DLN+SCR 9 CC no no. not @TCEQ
103230 intentionally S 5/29/12 6/27/2012 Friendswood En. Genco LLC Houston Harris W 501D5 1 128 128 3.4 DLN+SCR 9 SC na na
98073 8/15/11 4/30/2012 Xcel/SWPSC Jones 4 Lubbock Lubbock S GT6-5000F 1 175 175 9 DLN 9 SC na na
93938 1244 intentionally l 10/29/10 9/1/2011 LCRA - TC Ferguson Pwr Plant Horseshoe Bay Llano GE F7FA 2 175 550 2 DLN+SCR+CO 4 CC 1244GHG 11/10/11
92156 3/26/10 11/1/2010 Xcel/SWPSC Jones 3 Lubbock Lubbock S GT6-5000F 1 175 175 9 DLN 9 SC †Separate GHG Permit
87153 877 intentionally l 1/2/09 3/15/2010 Gregory Power (repermit/renew) Gregory San Patricio GE F7FA 2 168 336 9 DLN 20 SC
83638 1110 intentionally l 12/7/07 3/3/2010 Wolf Hollow II Pwr LLC (Exelon) Granbury Hood GE 7HA.02 2 330 1,160 2 DLN + SCR + CO 4 CC
87225 1198 intentionally l 12/22/08 2/3/2010 Panda Sherman Power LLC Sherman Grayson S GT6-5000F 2 200 600 2/9 DLN+SCR 4/15 CC
83801 1117 intentionally l 1/4/08 11/17/2008 Brazos Electric Power Coop Inc Bridgeport Jack GE F7FA 2 172 663 2 DLN+SCR 11 CC
83503 1111 intentionally l 12/3/07 10/10/2008 Panda Temple Power LLC Temple Bell S GT6-5000F 4 200 1000 2 DLN+SCR 9 CC
48106 1012M1 intentionally l 11/29/07 9/24/2008 City of Austin - Sand Hill Units 6 & 7 Del Valle Travis GE LM6000 2 48 96 5 DLN+SCR 9 SC
81903 1095 intentionally l 5/14/07 9/5/2008 City Public Service Elmendorf Bexar GE LM6000 4 50 200 5 DLN+SCR+CO 9 SC
46189 1103 N71 10/4/07 7/29/2008 Thermal Energy (TECO) CHP 1 & 2 Houston Harris GE LM6000 2 50 100 2 DLN+SCR 29 SC
83550 intentionally intentionally l 12/6/07 7/24/2008 East TX Electric Coop Inc Kountze Hardin GE F7EA 2 73 146 9 DLN 25 SC
4415 intentionally intentionally l 3/7/08 6/30/2008 City of Bryan - Dansby Power Plant Bryan Brazos GE LM6000 1 50 50 5 W+SCR+CO 9 SC
83551 intentionally intentionally l 12/6/07 6/26/2008 East TX Electric Coop Inc Shepherd San Jacinto GE F7EA 2 73 146 9 DLN 25 SC
1467 1090 intentionally l 4/4/07 5/22/2008 El Paso Electric Co - Unit 6A-6B El Paso El Paso GE F7EA 2 70 288 3 DLN+SCR+CO 25 CC
83475 intentionally S 11/28/07 12/28/2007 LCRA - Winchester Winchester Fayette GE LM6000 4 50 200 5 DLN+SCR 25 SC
81593 1093 intentionally l 4/10/07 12/18/2007 Barney M. Davis LP Corpus Christi Nueces GE F7FA 2 172 700 5 DLN+SCR+CO 5 CC
81594 1091 intentionally l 4/10/07 12/18/2007 Nueces Bay WLE LP Corpus Christi Nueces GE F7FA 2 172 700 5 DLN+SCR+CO 5 CC
82519 intentionally S 7/30/07 8/17/2007 Laredo WLE, LP Laredo Webb GE LMS1000 2 100 200 5 DLN+SCR 9 SC
80289 1082 10/31/06 7/26/2007 NRG Texas - Cedar Bayou Unit 4 Eldon Chambers S GT6-5000F 2 200 600 3 DLN + SCR 15 CC
80878 S 1/11/07 2/2/2007 Nucoastal Energy Victoria Victoria MHI M501F 1 285 323 5 DLN+SCR 19 CC
76990 1059 intentionally l 9/26/05 2/14/2006 Navasota Odessa Energy Partners LP Odessa Ector GE F7EA 4 75 550 5 DLN+SCR 27 CC
77039 1060 intentionally l 10/3/05 2/9/2006 Navasota Wharton Energy Partners LP Wharton Wharton GE F7EA 4 75 550 5 DLN+SCR 27 CC
72579 intentionally intentionally l 7/2/04 1/10/2005 Golden Spread El. Coop Mustang Unit 4 Denver City Yoakum GE F7FA 1 168 168 9 DLN 9 SC
46306 986M1 N59 4/13/04 12/2/2004 Dow Chemical GT96 (Calpine owner) Freeport Brazoria W 501F 1 180 236 5/3 DLN+SCR 25 CC
55627 intentionally S 6/26/03 9/8/2003 Brownsville PUB Silas Ray Unit 10 Brownsville Cameron GE LM6000 1 50 50 5 SCR 32 SC
52756 1026 intentionally l 9/25/02 7/23/2003 Brazos Elec Pwr (Duke Energy) Jacksboro Jack GE F7FA 2 170 620 5 SCR 20 CC
53284 1027 intentionally l 10/15/02 6/27/2003 City Public Service Leon Creek San Antonio Bexar GE LM6000 4 48 180 5 SCR+CO 12 SC
54162 intentionally S 2/4/03 3/28/2003 City of Bryan - Dansby Power Plant Bryan Brazos GE LM6000PC 1 50 50 5 SCR 32 SC
7647B 276 intentionally l 11/10/00 12/20/2002 OxyVinyls, LP - Unit 3 La Porte Harris GE F7EA 1 87 87 4 DLN+SCR 25 COG
City of Austin - GE LM6000 4 48 5 9 SC
48106 1012 5/30/01 4/12/2002 Del Valle Travis 500 SCR
intentionally l Sand Hill Energy Center GE F7FA 1 164 5 17.5 CC
48070 1011 intentionally l 5/24/01 1/17/2002 South Texas Electric Coop, Inc Nursery Victoria GE LM6000 3 45 180 5 SCR 15 CC
45642 979 N036 9/5/00 8/22/2001 Calpine - Deer Park Energy Ctr Deer Park Harris W 501F 4 180 1060 2.5 SCR 24 CC
46042 981 intentionally l 10/16/00 7/12/2001 BP Amoco Corp Texas City Galveston GE F7FA 3 167 550 3.5 SCR 25 CC
45360 977 intentionally l 8/16/00 5/23/2001 Entergy Power Ventures LP Marshall Harrison GE F7FA 2 170 570 5 SCR 25 CC
19166 760M5 intentionally l 4/20/00 5/3/2001 Formosa Plastics - Add Unit 6 Point Comfort Calhoun GE F7EA 1 83 80 9 DLN 25 CC/COG
21878 intentionally intentionally l 8/30/00 12/19/2000 Air Products, Inc. La Porte Harris GE F6B (Pkg) 4 44 176 15 DLN 15 COG
43890 965 intentionally l 3/20/00 12/15/2000 Cottonwood Energy Co. LP Deweyville Newton GE F7FA 4 170 1200 5 SCR 17.6 CC
43965 966 N026 3/24/00 10/17/2000 Calpine - Brazos Valley (Avista-Steag) Thompsons Fort Bend GE F7FA 2 175 670 3.5 SCR 25 CC
42734 958 intentionally l 11/4/99 7/14/2000 Wise County Power Co LLC Bridgeport Wise W 501G 2 230 560 5 SCR+CO 9 CC
41249 940 intentionally l 4/30/99 3/28/2000 Calpine - Freestone Energy Center Fairfield Freestone GE F7FA 4 175 1070 9 D 20 CC
41941 948 intentionally l 7/28/99 3/22/2000 Coastal Power Company Bastrop Bastrop GE F7FA 2 170 550 9 D 20 CC
42179 955 N021 8/26/99 3/22/2000 Calpine - Channel Energy Center Pasadena Harris W 501F 3 180 740 3.5 SCR 25/15 CC/COG
41953 951 intentionally l 7/29/99 3/6/2000 Next Era - Forney Plt (Cobisa-Forney) Forney Kaufman GE F7FA 6 170 1774 9 D 15 CC
40803 935 intentionally l 3/9/99 2/23/2000 City of Garland Nevada Collin GE F7EA 1 85 85 9 D 25 SC
41996 953 N020 8/2/99 2/11/2000 Calpine - Baytown Energy Center Baytown Chambers W 501F 3 180 750 3.5 D + SCR 15 CC/COG
41166 939 intentionally l 4/22/99 2/7/2000 Exelon Wolf Hollow 1 (AES Aurora) Granbury Hood M 501G 2 254 807 9 SCR 25 CC
41500 943 intentionally l 5/28/99 2/4/2000 Calpine - Corpus Christi En Ctr Corpus Christi Nueces GE F7FA 2 166 500 9 D 15 CC
40620 931 intentionally l 2/11/99 12/20/1999 Calpine - Bosque En Ctr (Mirant, SEI) Whitney Bosque GE F7FA 3 170 650 9 D 9 CC
40363 927 intentionally l 1/21/99 12/15/1999 Ennis-Tractebel Power Co., Inc. Ennis Ellis W 501G 1 250 350 9 SCR 20 CC
41775 946 N017 7/6/99 12/9/1999 Reliant Energy Channelview LP Channelview Harris W 501F 4 183 820 3 D + SCR 23 CC
40867 938 intentionally l 3/17/99 12/3/1999 Rio Nogales Power Project LP Seguin Guadalupe GE F7FA 3 170 780 9 D 7.4 CC
38191 906M1 intentionally l 7/1/99 11/24/1999 GDF Suez/Midlothian En (add #5 & #6 ) Midlothian Ellis ABB GT24 OTC 2 250 550 5 SCR 25 CC
39842 919 intentionally l 11/12/98 11/19/1999 Eastman Cogen LP (Eastex Cogen) Longview Harrison GE F7FA 2 168 460 9 D 7 CC/COG
41008 936 intentionally l 4/5/99 11/19/1999 Odessa-Ector Pwr Partners LP Odessa Ector GE F7FA 4 170 1000 9 D 9 CC
38481 921 intentionally l 5/29/98 10/20/1999 Union Carbide Seadrift Calhoun GE F6B 1 39 39 9 D 25 COG
41437 941 intentionally l 5/21/99 9/30/1999 GenTex Power Corp & Calpine Bastrop Bastrop W 501F 2 183 500 5 SCR 10/25 CC
40496 929 intentionally l 2/1/99 6/22/1999 SRW Cogen LP (EI DuPont) Orange Orange GE F7FA 2 170 440 6 SCR 15 CC/COG C56
40040 923 intentionally l 12/2/98 6/8/1999 GDF Suez - Hays Energy Project San Marcos Hays ABB GT24 OTC 4 175 1080 5 D/SCR 5 (25) CC
Page 3 of 6
40039 925 intentionally l 12/2/98 5/7/1999 Tenaska Gateway Minden Rusk GE F7FA 3 164 888 9 D 25 CC
36644 903 N007 10/12/98 4/21/1999 Fina/BASF Amd - Cogen for Blr Port Arthur Jefferson GE F6B 2 39 78 9 D/SCR 25 COG
38659 922 intentionally l 6/24/98 2/15/1999 Guadalupe Power Partners Marion Guadalupe GE F7FA 4 170 1000 9 D 15 CC
37894 918 intentionally l 3/19/98 1/8/1999 Lubbock Power & Light Lubbock Lubbock GE LM6000PC 2 42 128 15 SCR 25 CC
38284 909 intentionally l 5/1/98 12/31/1998 Calpine - Magic Valley Gen Sta Edinburg Hidalgo W 501G 2 230 700 12/9 SCR 25 CC
38599 914 intentionally l 6/15/98 12/22/1998 Calpine - Hidalgo En Ctr (Duke En) Edinburg Hidalgo GE F7FA 2 175 520 9/12 D 20 CC
38326 916 intentionally l 5/7/98 10/28/1998 Next Era - Lamar Plt (Panda Paris) Paris Lamar GE F7FA 4 170 1000 9 D 18 CC
38183 907 intentionally l 4/20/98 10/14/1998 City Public Service Elmendorf Bexar GE F7FA 2 170 500 9 SCR 25 CC
38191 906 intentionally l 4/13/98 10/2/1998 GDF Suez - Midlothian En (Venus) Midlothian Ellis ABB GT24 OTC 4 275 1080 5 SCR 25 CC
31914 857 intentionally l 12/10/97 9/30/1998 Sweeny Cogen Ltd. Part. Unit 4 Old Ocean Brazoria W 501D5A 1 121 121 25/15 D 10 COG
37283 915 N015 12/18/97 9/30/1998 Calpine - Pasadena Plant Pasadena Harris W 501F 1 160 500 9/6 SCR 25 CC/COG
37391 897 intentionally l 1/13/98 8/7/1998 Tenaska Frontier Partners Shiro Grimes GE F7FA 3 183 830 15 D 13 CC
37613 900 intentionally l 2/12/98 7/31/1998 Frontera Generating LP Mission Hidalgo GE F7FA 2 165 440 15 D 15 CC
735B 908 intentionally l 12/8/97 6/26/1998 BASF - Cogen 15-2-1 Freeport Brazoria GE F7EA 1 83 83 15 D 25 COG
36889 intentionally intentionally l 10/29/97 4/1/1998 Sabine Cogen (was HI Pwr Gen) Orange Orange GE F6B 2 40 110 9/5 SCR+CO Cat 15 CC/COG
32881 875 intentionally l 12/31/96 7/17/1997 Golden Spread El. Coop. - Mustang (LS Pwr) Denver City Yoakum GE F7FA 2 180 550 15 D 15 CC
32096 867 intentionally l 3/11/96 2/5/1997 QUIXX Corp (SPS) Borger Hutchison W 501D5A 2 121 242 15 D + SCR 20 COG
32263 866 intentionally l 4/1/96 12/4/1996 Calpine - Pasadena Cogen LLC Pasadena Harris W 501F 1 180 240 12 S,SCR 20 CC/COG
31914 857 intentionally l 2/12/96 9/9/1996 Sweeny Cogen Ltd. Part. Old Ocean Brazoria W 501D5A 3 121 363 25/15 D 10 COG
9910 731 intentionally l 12/30/94 9/14/1995 Exxon Chemicals GT/HRSG 4 Baytown Harris Siem. V82.2 1 100 100 9 D 15 COG
25738 840 intentionally l 7/15/94 4/21/1995 Brownsville Public Utility Board Brownsville Cameron W 251B 1 45 70 15 D + SCR 10 CC
25034 intentionally intentionally l 5/16/94 1/26/1995 Union Carbide Texas City Galveston GE F6 1 38 38 15 D 25 COG
25384 839 intentionally l 6/20/94 12/6/1994 Tenaska IV Power Partners Ltd Cleburne Johnson W 501F 2 171 500 9 SCR 25 CC
22043 818 intentionally l 11/9/92 7/5/1994 Equistar Chemical (Quantum) Deer Park Harris GE F6 2 36 96 15 D 25 CC/COG
9629 intentionally intentionally l 11/13/92 5/12/1994 E. I. DuPont - SRW Cogen Unit Orange Orange GE F7E 1 80 105 42 S 10 CC/COG
9241A 493M1 intentionally l 11/5/92 11/8/1993 Optim En. Altura (Cogen Lyondell) CT #6 Channelview Harris GE F7EA 1 80 80 15 D 25 COG
22038 815 intentionally l 11/5/92 8/9/1993 Shell Oil Company Deer Park Harris GE F7E 2 75 150 15 D (SCR retro) 25 COG
21394 806 intentionally l 3/3/92 6/16/1993 Brazos Electric Power Coop Gordon Palo Pinto W 501D5 2 104 208 25 W 25 SC
21587 807 intentionally l 5/15/92 5/27/1993 NRG San Jac Station (Hou Ind Inc) LaPorte Harris GE F7EA 2 81 162 15 D 25 COG
1467 intentionally intentionally l 11/2/92 5/7/1993 El Paso Electric (Newman #4 Upgrade) El Paso El Paso W 501-B6 2 70 240 42 W (82 FO) ntentionally CC
GE F7E
21592 intentionally intentionally l 5/14/92 11/12/1992 NRG (Upgrade THWharton 3 + 4) (H Ind Inc) Satsuma Harris 8 57 564 25 D 25 CC
(Hybrid)
21429 intentionally intentionally l 3/11/92 9/14/1992 Air Liquide P Neches ASU Cogen (Big Three) Port Neches Jefferson GE F6 1 37 37 9 LPM+SCR 15 COG
20862 799 intentionally l 5/20/91 5/26/1992 Exxon Mobil Oil - refinery cogen Beaumont Jefferson GE F6 1 37 37 9 S+SCR 10 COG
20869 800 intentionally l 6/3/91 5/20/1992 Dow - Oyster Creek Ltd. Freeport Brazoria GE F7EA 3 85 435 15 D 25 CC/COG
20065 780 intentionally l 4/11/90 8/7/1991 Huntsman (P#20065 consol to P#16909) Port Neches Jefferson GE F6 2 37 74 25 LPM 25 COG
20250 intentionally intentionally l 7/24/90 4/23/1991 Praxair Texas City Galveston GE F6 1 37 37 25 S 46 COG
19764 intentionally intentionally l 10/16/89 4/6/1990 Niject Services Co. Hawkins Wood GE LM2500 1 26 26 25 S ntentionally COG
19166 760 intentionally l 11/7/88 10/13/1989 Formosa Plastics CTs #1-5 ('93 AMD) Point Comfort Calhoun GE F7MNQC 5 80 475 25 S 25 CC/COG
18846 intentionally intentionally l 5/2/88 8/3/1988 Lubbock Pwr & Light (Tx Tech Cogen) Lubbock Lubbock GE LM2500 1 21 21 25 S ntentionally COG
18358 732 intentionally l 9/30/87 7/5/1988 Equistar Chemical, LP Corpus Christi Nueces GE F6 1 37 37 42 S ntentionally COG
18049 725 intentionally l 4/15/87 6/14/1988 Ticona Polymers, Inc (Celanese) Bishop Nueces GE F6 1 37 intentionally l 42 S ntentionally COG
18394 739 intentionally l 10/15/87 5/19/1988 Direct En. Paris Gen. (orig. Tenaska) Paris Lamar GE F7 2 80 244 42 S ntentionally CC/COG
9910 731 intentionally l 8/29/85 3/7/1988 Exxon Chemicals Baytown Harris GE F6 3 37 intentionally l 42 S ntentionally COG
17625 704 intentionally l 9/17/86 8/26/1987 Koch Refining Co. Corpus Christi Nueces GE F6 1 37 intentionally l 42 S ntentionally COG
16840 688 intentionally l 11/22/85 5/1/1987 Fina Oil Port Arthur Jefferson GE F6 2 37 intentionally l 50 S/W ntentionally COG
17369 713 intentionally l 5/29/86 10/27/1986 Exxon Baytown Harris W 251B8 2 43 intentionally l 75 S ntentionally COG
17411 720M3 intentionally l 7/7/86 9/29/1986 Power Resources Big Spring Howard GE F7EA 2 80 200 51 S ntentionally CC/COG
16750 685 intentionally l 10/17/85 6/10/1986 Wichita Falls Energy Wichita Falls Wichita GE LM2500 3 20 77 75 S ntentionally CC
17030 699 intentionally l 2/12/86 5/29/1986 Formosa Plastics Point Comfort Calhoun GE F6 1 37 intentionally l 94 S ntentionally CC/COG
9664 662 intentionally l 3/28/85 2/12/1986 TU Electric - DeCordova SES Granbury Hood GE F7EA 4 65 260 96 W ntentionally SC
9560 intentionally intentionally l 11/26/84 2/11/1986 Invista S.ar.l (orig. E. I. DuPont) Victoria Victoria GE F7 1 80 intentionally l 100 S (SCR retro to 10) ntentionally COG
9668 661 intentionally l 3/28/85 1/29/1986 TU Electric - Morgan Creek SES Colorado City Mitchell GE F7EA 6 65 390 96 W ntentionally SC
9659 663 intentionally l 3/28/85 1/29/1986 TU Electric - Permian Basis SES Monahans Ward GE F7EA 5 65 325 96 W ntentionally SC
9629 intentionally intentionally l 3/6/85 9/27/1985 E. I. DuPont Orange Orange GE F7 1 80 intentionally l 42 S 10 COG
9609A intentionally intentionally l 2/5/85 8/2/1985 Union Carbide Seadrift Calhoun GE F6 2 37 intentionally l 75 S ntentionally COG
9570 650 intentionally l 12/10/84 6/21/1985 Calpine - Texas City Cogen LP Texas City Galveston W 501D5 3 100 400 75 S ntentionally CC/COG
9463 649 intentionally l 5/3/84 4/11/1985 Amoco Oil Company Texas City Galveston GE F7 2 80 intentionally l 75 S ntentionally COG
9517 642 intentionally l 8/28/84 3/12/1985 Ineos USA (orig. Amoco) V 2/09 reiss 95 Alvin Brazoria GE F6 1 37 intentionally l 75 S ntentionally COG
9322 621 intentionally l 4/15/83 2/8/1985 University of Texas Austin Travis W 251 1 40 intentionally l 75 S ntentionally COG
9492B 639 intentionally l 6/20/84 11/26/1984 Occidental Chemical (V - 2005) Deer Park Harris GE F7 1 (retired) 80 intentionally l 75 S ntentionally COG
9340 intentionally intentionally l 7/15/83 6/11/1984 Central & Southwest Newgulf Wharton GE F7 1 80 intentionally l 75 S ntentionally SC
9378 619 intentionally l 10/12/83 3/1/1984 Amoco Chemicals Texas City Galveston GE F6 1 37 intentionally l 75 S ntentionally COG
9344 243M2 intentionally l 7/20/83 2/29/1984 Coastal Refining & Marketing Corpus Christi Nueces GE F5 2 25 intentionally l 112 D ntentionally COG C57
9346 612M2 intentionally l 7/25/83 2/7/1984 Air Liquide (origin. Bayou Cogen) La Porte Harris GE F7 4 80 320 75 S ntentionally COG
Page 4 of 6
Permit No. PSD NA/S/HAP Received Issue Date Company Name City County
Turbine Model Number of CTs MW per CT Project MW NOx (1) Control Method CO (1) SC/CC Permit No. Issue Date
9241A 493M4 intentionally l 7/22/83 10/13/1983 Optim En. Altura (Cogen Lyondell/ARCO) Channelview Harris
GE F7 5 75 500 36 - 24 S ntentionally CC
9292A 605M2 intentionally l 3/4/83 8/10/1983 Calpine - Clear Lake Cogen. Ltd. Pasadena Harris
W 501D 3 100 400 75 W ntentionally CC
9244 intentionally intentionally l 12/14/82 2/7/1983 Motiva Enterprises (Texaco) Port Arthur Jefferson
GE F6 1 37 intentionally l NC s cell intentionally left bntentionally COG
9044 intentionally intentionally l 3/10/82 6/7/1982 Dow Chemical Freeport Brazoria
GE F7 3 (1 retired) 70 intentionally l NC DLN (2) ntentionally CC/COG
W 501D 2 (retired) 100 intentionally l NC s cell intentionally left bntentionally CC/COG
7647B intentionally intentionally l 5/22/79 12/6/1979 Oxy (orig. Diamond Shamrock) La Porte Harris
GE F7 2 80 intentionally l NC DLN (2) ntentionally CC/COG
5409 intentionally intentionally l 6/2/77 8/17/1977 El Paso Electric El Paso El Paso
W 501B4 1 72 72 135 W ntentionally SC
W501A 2 45 intentionally l NC s cell intentionally left bntentionally COG
GE F7C 1 63 intentionally l NC DLN (2) ntentionally COG
BB 11D5
2894 HL&P Greens Bayou Houston Harris 6 60 362 55 W SC
intentionally intentionally n
l tentionallyintentionally l (Trbdn) ntentionally
2094 intentionally intentionally l 2/25/74 3/26/1974 HL&P TH Wharton Houston Harris GE F7C 6 57 342 55 W ntentionally SC
1467 intentionally intentionally n
l tentionallyintentionally l El Paso Electric Unit S4-1/S4-2 El Paso El Paso W501B2 2 60 225 55 W ntentionally CC
445 intentionally intentionally l 11/1/72 12/7/1972 HL&P TH Wharton (now #21592) Houston Harris GE F7B 2 57 STAG 300 55 W ntentionally CC
CODES: Permit information - N# = Nonattainment area permit; S = Standard Permit; HAP = Haz Air Poll. Turbine Model - Pkg = Peaking. FO = Fuel Oil. (CO2) - CO2 capture
Control info - NC = No Controls, W or S = Water or Steam Injection, D or DLN = Dry Low NOx, LPM = Lean Pre-mix, SCR = Selective Catalytic Reduction, CO = CO Catalyst
(1) BACT, LAER or Std Permit limit (ppmvd @ 15% O2) (2) Retrofit for ozone SIP (MECT)
Cycle: Combined Cycle (CC); Simple Cycle (SC); Process steam cogeneration (COG); Compressed air energy storage (CAES); CO2 - closed supercritical CO2 Brayton
* <0.14 lb NOx/MWh and <132 ppmvd CO @ 15%O2
Projects Voided, Withdrawn, Expired, Consolidated or Reissued GHG Permits

PSD
Tradinghouse Pwr Co LLC (Luminant, GE FA.05 210 or 1,440 or Withdrawn
110357 1452 W 3/16/15 Withdrawn Waco McLennan 4 2 DLN + SCR + CO 2 CC 132
switching to CC) or S F5ee 231 1,624 3/4/2019
3/4/2019
118611 3/28/14 V 5/2/2018 Coleto Creek Power LP (GDF Suez NA) Fannin Goliad GE 7FA.05 1 230 230 9 DLN 9 SC na na
116603 intentionally S 1/10/14 V 6/13/18 TXP Winkler, LLC Wink Winkler GE LM6000 3 51.3 154 4 DLN + SCR ntentionally SC na na
116605 intentionally S 1/10/14 V 6/13/18 TXP Sealy, LLC Sealy Austin GE LM6000 3 51.3 154 4 DLN + SCR ntentionally SC na na
116607 intentionally S 1/10/14 V 6/13/18 TXP Reeves, LLC Coyanosa Reeves GE LM6000 3 51.3 154 4 DLN + SCR ntentionally SC na na
122987 intentionally S 8/18/14 V 6/13/18 TXP Ricebird LLC El Campo Wharton GE LM6000 3 51 152 4 DLN + SCR 8 SC na na
GE 7FA.05,
7FA.04, or
114911 1380 11/12/13 V 11/7/2017 Lon C. Hill LP Corpus Christi Nueces 2 195-240 625-740 2 DLN+SCR+CO 2 CC 1380GHG 10/28/14
S SCC6-5000F,
SST6-5000
930 SC 9 SC or DLN SC 9 SC or
122401 1428 8/4/14 3/24/2016 Apex Tx Pwr LLC - Neches Station Cuney Cherokee F Class 4 SC or 2 CC SC/CC 111 3/24/16
794 CC 2 CC DLN + SCR + CO CC 4 CC
GE H.02 MHI
135021 1468 8/12/15 V 5/9/2017 Panda Sherman Power LLC Sherman Grayson 1 287 - 330 470 - 540 2 DLN + SCR + CO 2 CC 144 Void
501JAC,or S
Occidental Chemical (Ingleside): Amend GE FA.04 or Withdrawn
35335 880M1 8/27/15 1/8/1998 Gregory San Patricio 1 185 260 2 DLN + SCR 4 CC/COG 142
project withdrawn 3/31/2017 S SGT6-5000F4 3/31/2017
107055 S 11/26/12 2/6/2013 Apex Matagorda En Ctr Clemville Matagorda D-R EA-418 (CAE 2 158 317 2.5 W+SCR+CO 5 CAES 107055 4/14/14
99181 10/25/11 V 4/25/2016 NRG Tx Pwr LLC - WA Parish Gen Sta Thompson Fort Bend GE F7EA 1 80 80 5 DLN 25 SC na na
GE F7FA or
71739 1043 4/2/04 V 9/23/2015 Cobisa-Greenville LLP (EXP) Greenville Hunt 6 or 4 170 - 230 1800 2 SCR 25 CC na na
W 501F/G
99691 11/21/11 V Golden Spread El. Coop Mustang Unit 6 Denver City Yoakum GE F7FA 1 168 168 9 DLN 8 SC na na
GE 7FA.07 or
84289 1125 N75 3/7/08 8/5/2010 Pondera Dev LLC - King Pwr Station (EXP) Houston Harris 2 230 900 2 DLN+SCR+CO 2 CC na na
HA.01
82426 1100 N69 7/19/07 1/12/2011 Exelon/EXTEX LaPorte Ltd P (EXP) Dallas Dallas S GT6-5000F 2 194 395 2.5 DLN+SCR+CO 8 SC no no. not @TCEQ
87222 1200 HAP53 12/29/08 WD MyPower Corp - Lakeside En Ctr (WD) Fairfield Freestone S GT6-5000F 2 193.5 640 2 DLN+SCR 9
104511 S 7/18/12 9/1/2012 Apex Bethel En Ctr LLC (EXP) reiss. 118876 Tenn. Colony Anderson D-R EA-418 (CAE 2 158 317 2.5 W+SCR+CO 5
GE F7FA or 170 or 620 or
83207 1106 10/25/07 6/22/2009 Lamar Power Partners II LLC (EXP) Paris Lamar 2 2 DLN+SCR 15
M 501G 200 910
110577 S 6/4/13 7/8/2013 Frame Switch En Inc (proj chg to RICE) Hutto Williamson P&W FT4000 2 60 120 3.5 SCR+CO 12.3
109147 1356 4/1/13 WD Golden Spread El. Coop. - Floydada Sta. Floydada Floyd GE 7FA.05 1 190 190 9 DLN 9
100129 1284 N152 12/20/11 WD Freeport LNG Development, L.P. (WD) Freeport Brazoria GE 7EA 1 90 90 2 DLN+SCR+CO 4
17740 716 11/17/86 12/16/1987 Luminant (Encogen One)(decomm) Sweetwater Nolan GE F7E (2), F6 3 80,37 42 S
Gasification
86013 1163 N94 HAP33 9/2/08 V NRG S.R. Bertron IGCC (CO2) La Porte Harris 2 550
Units
85862 1153 8/13/08 V Grimes County En Ctr, LLC Singleton Grimes GE 7FA 4 170 1160 2 DLN+SCR 12
85534 1143 6/27/08 WD Navarro Generating LLC (WD) Richland Navarro F Class 2 232 780 2 DLN+SCR+CO 5
84248 1128 N79 2/28/08 WD NRG Power - SR Bertron La Porte Harris F Class 4 200 1300 3 DLN+SCR+CO 5
83784 1116 N73 1/4/08 5/19/2009 Entergy Lewis Creek Plant (EXP) Willis Montgomery GE F7FA 2 167 500 2 DLN+SCR 12
83690 1113 12/21/07 V Pin Oak Creek Energy LLC Richland Navarro F Class 4 200 1400 2 DLN + SCR 2
83642 1115 12/13/07 6/17/2009 Pattillo Branch Pwr (LS Pwr) (EXP) Savoy Fannin F Class 4 200 1400 2 DLN+SCR+CO 2
83390 1108 11/16/07 10/30/2008 NRG - Cedar Bayou (Unit 5) (EXP) Eldon Chambers F, G, or 7FB 2 200 700 2 DLN+SCR 18
83378 1105 10/31/07 8/18/2009 Madison Bell Partners LP (EXP) Madisonville Madison GE F7E 4 75 550 2 DLN+SCR 17.5
82244 1098 6/21/07 4/18/2008 NavasotaWhartonCol Bend Unit 3(EXP) Wharton Wharton GE F7EA 2 75 225 2 DLN+SCR 27
82303 1099 6/21/07 4/18/2008 Navasota Odessa Unit 3 (EXP) Odessa Ector GE F7EA 2 75 225 2 DLN+SCR 27
C58
Page 5 of 6
81853 1092 5/4/07 WD
Occidental Energy Ventures Corp Denver City Yoakum ???? 3 ??? 700 2 DLN + SCR 15
95 854M2 1/3/07 WD
Ineos USA LLC (deleted from flex P proj) Alvin Brazoria Solar 130S 2 15 30 5 SCR 32
45642 979M1 N036M1 11/10/06 12/21/2007
Calpine Deer Park - Units 5, 6 (EXP) Deer Park Harris SW 501F 2 180 530 2.5 SCR 24
80546 S 12/11/06 12/22/2006
NRG S.R. Bertron(peakers) (EXP) La Porte Harris GE LM6000 4 50 200 5 W + SCR 25
80289 1082 10/31/06 7/26/2007
NRG - Cedar Bayou (peakers) (EXP) Eldon Chambers GE LM6000 8 50 400 5 W + SCR 25
79335 6/30/06 9/22/2006
Wise County Pwr Co LP (EXP) Poolville Wise GE F7EA 4 81 324 9 DLN 25
79133 S 6/6/06 7/6/2006
GoldenSpread Unit 5 (V) Cons in 72579 Denver City Yoakum GE 7FA (PKg) 1 168 168 9 DLN 9
77679 1061 12/22/05 3/1/2007
Nacogdoches Pwr (deleted from proj) Sacul Nacogdoches SW 501F 1 190 330 5 DLN+SCR 21
45642 979M1 N036M1 3/30/04 WD
Calpine Deer Park En (add 2 units) Deer Park Harris W 501F 2 180 360 2.5 SCR 24
55629 S 6/26/03 9/12/2003
Brownsville PUB (V) Brownsville Cameron GE LM6000 1 50 50 5 SCR 32
54114 1031 N055 1/9/03 10/20/2003
Bayport Energy Center LP (EXP) Pasadena Harris GE F6B 2 40 80 3.5 SCR 17.2
49293 1015 9/21/01 12/6/2002
Steag - Sterne Elec Gen Fac (EXP) Sacul Nacogdoches SW 501F 3 190 1000 5 SCR 21
48500 1013 7/16/01 WD
STEAG Power LLC (WD) Ennis Ellis W 501G 4 200 1400 5 SCR 35
46603 4/26/01 5/15/2002
Ridge En Storage & Grid Servs (EXP) Clemville Matagorda DR T6-EA418 4 134 538 9 SCR 25
47318 1009 3/7/01 7/5/2002
Hartburg Power LP (EXP) Deweyville Newton GE F7FA 3 277 800 5 SCR 15
46665 1003 12/14/00 3/24/2003
Ennis Tractebel II LP (V 05/19/04) Ennis Ellis W 501G 2 230 815 5 SCR 9
46536 11/22/00 WD
Texas Bayou En Ctr (WD-PBR) Texas City Galveston GE LM2500 1 25 25 4.2 SCR 25
46532 11/21/00 No Turbines
Celanese, Ltd (Turbines Deleted) Pasadena Harris GE LM6000 6 47 284 5 SCR + CO 5
46470 990 11/17/00 AV & V
STEAG Power LLC (AV & V) Ferris Ellis GE F7FA 4 175 1200 3.5 SCR 20
46192 983 10/24/00 3/24/2003
Innovene (was BP, Amoco) (EXP) Alvin Brazoria GE F6B 2 35 70 3.5 SCR 25 COG
42179 955 N021 11/16/00 WD
Channel Energy (Add 4th Cogen) (V) Pasadena Harris W 501F 1 180 180 3.5 SCR 25
46426 999 11/13/00 10/8/2003
Texas Petrochemicals, LP (not built) Houston Harris GE F7EA 2 81 581 5 SCR 25
43965 966 N026 11/6/00 12/31/2002
Steag/Brazos V. add 2 CCTs (EXP) Thompsons Fort Bend GE F7FA 2 170 660 3.5 SCR 25
45843 982 N037 10/2/00 Calpine Amelia En Ctr (EXP)
3/26/2002 Amelia Jefferson W 501F 3 180 1030 3.5 SCR 22
44174 968 N028 4/13/00 6/20/2001
MC Energy Partners, LP (V) Montgomery Montgomery GE F7FA 2 170 660 3 SCR 25
44175 969 N029 4/13/00 12/21/2000
Cedar Power Partners, LP(EXP) Dayton Liberty GE F7FA 2 175 800 3 SCR 25
43178 962 12/30/99 12/15/2000
Westvaco Texas LP (Expired) Evadale Jasper GE LM6000PC 2 42 84 5 SCR + CO 22
42905 961 N023 11/24/99 WD
Texas Industrial Power (WD) Mt. Belvieu Chambers W 501FD 1 177 193 5 SCR 25
42774 960 11/10/99 7/28/2000
West Texas Energy Ltd Part (EXP) El Paso El Paso ABB-GT24 2 180 500 3.5 SCR 5
42169 954 8/25/99 3/14/2000
Duke Energy Jack, LP (EXP) Jacksboro Jack GE F7FA 2 170 620 5 SCR 20
42086 952 8/16/99 8/18/2000
Palestine Generation LLC (EXP) Palestine Anderson GE F7FA 6 170 1600 5 SCR 15
41802 947 N019 7/12/99 8/31/2000
Chambers Energy Facility (V) Houston Harris ABB GT24 OTC 8 180 2200 3.5 D + SCR + CO 20
41774 945 7/6/99 3/20/2000
Gateway Power Project, LP (EXP) Gilman Upshur GE F7FA 3 170 800 5 SCR 7.4
41606 944 6/14/99 Duke Energy Bell LP (EXP)
2/4/2000 Temple Bell GE F7FA 2 170 520 5 SCR 20
41472 942 5/27/99 1/31/2000
Kaufman Cogen, LP (EXP) Mesquite Kaufman GE F7FA 2 170 620 5 SCR 20
41013 937 4/5/99 1/13/2000
Archer Power Partners LP (EXP) Lakeside City Archer GE F7FA 4 170 1000 5 SCR 9
9241A 493M4 3/4/99 11/5/1999
Cogen Lyondell (Turbine #7) (EXP) Channelview Harris W 501F (Pkng) 1 160 160 25 D 25
40699 932 2/23/99 3/14/2000
ExxonMobil (Cons into 19566) Beaumont Jefferson GE F7FA 3 170 740 5 SCR 10/25
40619 933 2/11/99 3/11/2002
Mirant Parker LLC (SEI) (EXP) Weatherford Parker GE F7FA/F7EA 2/2 170/82 650 9/9 D 9/25
38484 911 N013 5/29/98 WD
Air Products, Inc (V ) La Porte Harris W 501F 1 168 240 9/5 SCR 20
37302 895 12/29/97 8/18/1998
Edinburg Energy (EXP) Edinburg Hidalgo ABB GT-24 4 180 815 15 D 10
37227 894 N005 12/12/97 9/22/1998
Air Liquide America Corp (V ) La Porte Harris GE F7EA 3 81 243 9/5 SCR 25
34824 877 5/9/97 Gregory Pwr (V)(failed to renew)
3/19/1998 Gregory San Patricio GE F7FA 2 168 336 15 D 20
35335 880 4/18/97 1/8/1998
Occidental Chem (V)(failed to renew) Gregory San Patricio GE F7FA 2 170 500 15 D 20
33166 870 7/22/96 12/20/1996
Longview Generating, LP (EXP) Longview Gregg GE F7FA 1 180 180 9 D 8
23962 837 12/3/93 5/2/1994
West Campus Cogeneration (EXP) College Stn. Brazos GE F6 2 37 75 9-14 D
ExxonMobil (originally 40699) (Cons into
19566 932 2/23/99 3/14/2000 Beaumont Jefferson GE F7FA 3 170 740 5 SCR 10/25 CC/COG
49138, 11/24/09)
ExxonMobil Corp - Baytown (Cons into 3452,
9910 731M2 10/4/02 6/13/2003 Baytown Harris GE F7FA 1 170 170 3 SCR 7.4 COG
8/24/05)
CODES: V = Void, AV = Admin Void, EXP = Expired, WD = Withdrawn, DEL = Deleted, Cons = Consolidated, S = Standard Permit, PBR = Permit by Rule
(1) BACT (ppmvd @ 15% O2)
End of worksheet
C59
Page 6 of 6
Recently Issued and Approved BACT from Recently Issued NSR Permits for Relevant Equipment
Equipment
Facility Location Permit Date Control Description Pollutant Emission Rate Units
Description
Abengoa Bioenergy Biomass of Kansas Hugoton, Kansas 1/1/2014 Emergency Fire Pump Good Combustion Practices CO 0.0011 lb/hp‐hr
Good Combustion Practices Nox 0.006 lb/hp‐hr
Good Combustion Practices VOC 0.0002 lb/hp‐hr
Low Sulfur Fuels SO2 0.00059 lb/hp‐hr
combustion Control/Low Ash Fuels PM 0.0002 lb/hp‐hr
CO2e 163.6 lb/MMBtu
FGE Texas Project Mitchell County, Texas 5/1/2013 Fugitives Daily AVO Inspections CO2e 10 tpy
CH4 0.1 tpy
CO2 209 tpy
FGE Texas Project Firewater Pump Engine Appropriate operation of the engines and low CO2 73.96 kg/mmBtu
annual hours of operation are selected as CH4 3.00E‐03 kg/mmBtu
BACT for the Proposed Engine N2O 6.00E‐04 kg/mmBtu
Kings Mountain Energy Center Kings Mountain, North Carolina 7/1/2014 Firewater Pump Engine 40 CFR Part 60 Subpart IIII CO 40 CFR Part 60 Subpart IIII
Nox
VOC
SO2
PM
CO2e
Pleasants Energy Facility Waverly, West Virginia 9/1/2015 Simple Cycle Combustion Turbines Low Nox Burners while combusting Natural NOx 9 ppm
Gas
Water injection while combusting fuel oil
Good Combustion Practices CO 9 ppm
Use of low ash and low sulfur fuels, inlet air PM 20 lb/hr
filtration, and good combustion control
practices
Use of natural gas as a fuel and efficient GHG 1,570 lb CO2/MW‐hr
turbine design
Gaines County Power Plant Seminole, Texas 4/28/2017 Simple Cycle Combustion Turbines Dry low NOx Burners NOx 9 ppm

Dry low NOx Burners and good combustion CO 9 ppm
practices
Good Combustion Practices and Maintenance VOC 2 ppm
Procedures
Pipeline Quality Natural Gas PM/PM10/PM2.5
Low Carbon intensity fuel, efficient SCCT CO2e 1300 lb/MWh
Technology, good combustion and
operating/maintenance practices
Limit duration of MSS events MSS
Gaines County Power Plant Fire Pump Engine limit hours of operation to 100 hours per year CO 40 CFR Part 60 Subpart IIII
and comply with 40 CFR Part 60 Subpart IIII
and use ultra‐low sulfur diesel fuel
Nox
VOC
SO2
PM
CO2e
Gaines County Power Plant SF6 Electrical Equipment Use state‐of‐art enclosed SF6 cirtuit breakers SF6
with low pressure alarm
Gaines County Power Plant Fugitive Emissions Periodic AVO inspections and repairing any VOC
found leaks
CO2e
Jackson County Generating Facility Ganado, Texas 2/2/2018 Simple Cycle Turbine energy efficiency designs, practices, and CO2e 1316 lb/MWh
procedures, CT inlet air cooling, periodic CT
burner maintenance and tuning, reduction in
heat loss, i.e., insulation of the CT,
instrumentation and controls
C60
Recently Issued and Approved BACT from Recently Issued NSR Permits for Relevant Equipment
Equipment
Facility Location Permit Date Control Description Pollutant Emission Rate Units
Description
Jackson County Generating Facility Natural Gas Fired Fuel Gas Heaters Low carbon intensity fuel, good operating and CO2e
maintenance practices, Efficient Design, low
annual capacity
Jackson County Generating Facility Fugitive Emissions Weekly AVO inspections CH4
Jackson County Generating Facility Firewater Pump Engine Good operating and maintenance Procedures, CO2e
efficient design, low annual capacity
Jackson County Generating Facility SF6 Electrical Equipment totally enclosed insulation systems equipped SF6

with a low pressure alarm and low pressure
lockout is BACT
Montgomery County Power Station Willis, Texas 3/27/2018 Fire Pump Engine limit hours of operation to 100 hours per year CO

and comply with 40 CFR Part 60 Subpart IIII Nox
and use ultra‐low sulfur diesel fuel VOC
SO2
PM
CO2e
Montgomery County Power Station Fugitive Emissions Weekly AVO inspections VOC
CH4
C61
Appendix D. PI-1 General Application Workbook
Texas Commission on Environmental Quality Date: ____________
Form PI-1 General Application Permit #: ____________
General Company: ____________
I. Applicant Information
I acknowledge that I am submitting an authorized TCEQ application workbook and any
necessary attachments. Except for inputting the requested data and adjusting row height and
I agree
column width, I have not changed the TCEQ application workbook in any way, including but
not limited to changing formulas, formatting, content, or protections.
A. Company Information
Company or Legal Name: El Paso Electric Company
Permits are issued to either the facility owner or operator, commonly referred to as the applicant or permit holder. List
the legal name of the company, corporation, partnership, or person who is applying for the permit. We will verify the
legal name with the Texas Secretary of State at (512) 463-5555 or at:
https://www.sos.state.tx.us
Texas Secretary of State Charter/Registration
1073400
Number (if given):
B. Company Official Contact Information: must not be a consultant
Prefix (Mr., Ms., Dr., etc.): Mr.
First Name: Daniel
Last Name: Perez
Title: Supervisor, Environmental Compliance
Mailing Address: P.O. Box 982
Address Line 2:
City: El Paso
State: Texas
ZIP Code: 79901
Telephone Number: 915-543-4166
Fax Number:
Email Address: Daniel.perez@epelectric.com
C. Technical Contact Information: This person must have the authority to make binding agreements and
representations on behalf of the applicant and may be a consultant. Additional technical contact(s) can be provided
in a cover letter.
First Name: Bill
Last Name: Jamieson
Title: Director, Air Quality
Company or Legal Name: SWCA Environmental Consultants
Mailing Address: 20 E Thomas Rd
Address Line 2: Suite 1700
City: Phoenix
State: Arizona
ZIP Code: 85012
Fax Number:
Email Address: bjamieson@swca.com
D. Assigned Numbers
The CN and RN below are assigned when a Core Data Form is initially submitted to the Central Registry. The RN is
also assigned if the agency has conducted an investigation or if the agency has issued an enforcement action. If these
numbers have not yet been assigned, leave these questions blank and include a Core Data Form with your application
submittal. See Section VI.B. below for additional information.
Enter the CN. The CN is a unique number given to each business, governmental
body, association, individual, or other entity that owns, operates, is responsible for, CN600352819
or is affiliated with a regulated entity.
Version 4.0 Page 1

Enter the RN. The RN is a unique agency assigned number given to each person,
organization, place, or thing that is of environmental interest to us and where
regulated activities will occur. The RN replaces existing air account numbers. The RN100211309
RN for portable units is assigned to the unit itself, and that same RN should be used
when applying for authorization at a different location.
This cell intentionally left blank
II. Delinquent Fees and Penalties

Does the applicant have unpaid delinquent fees and/or penalties owed to the TCEQ?
This form will not be processed until all delinquent fees and/or penalties owed to the TCEQ or the
Office of the Attorney General on behalf of the TCEQ are paid in accordance with the Delinquent Fee No
and Penalty Protocol. For more information regarding Delinquent Fees and Penalties, go to the TCEQ
Web site at:
https://www.tceq.texas.gov/agency/financial/fees/delin
III. Permit Information

A. Permit and Action Type (multiple may be selected, leave no blanks)
Additional information regarding the different NSR authorizations can be found at:
https://www.tceq.texas.gov/permitting/air/guidance/authorize.html
Select from the drop-down the type of action being requested for each permit type. If that permit type does not
apply, you MUST select "Not applicable".
Provide all assigned permit numbers relevant for the project. Leave blank if the permit number has not yet been
assigned.
Permit Type Action Type Requested Permit Number (if assigned)
(do not leave blank)
Minor NSR (can be a Title V major source): Not
applicable, Initial, Amendment, Renewal, Renewal
Certification, Renewal/Amendment, Not applicable
Relocation/Alteration, Change of Location,
Alteration, Extension to Start of Construction
Special Permit: Not applicable, Amendment,
Renewal, Renewal Certification,
Not applicable
Renewal/Amendment, Alteration, Extension to
Start of Construction
De Minimis: Not applicable, Initial Not applicable
Flexible: Not applicable, Initial, Amendment,

Renewal, Renewal Certification,
Not applicable
Renewal/Amendment, Alteration, Extension to
Start of Construction
PSD: Not applicable, Initial, Major Modification Major Modification 1467 and PSDTX1090
Nonattainment: Not applicable, Initial, Major

Major Modification 1467 and PSDTX1090
Modification
HAP Major Source [FCAA § 112(g)]: Not
Not applicable
applicable, Initial, Major Modification
PAL: Not applicable, Initial, Amendment, Renewal,
Not applicable
Renewal/Amendment, Alteration
GHG PSD: Not applicable, Initial, Major
Major Modification 1467 and PSDTX1090
Modification, Voluntary Update
Version 4.0 Page 2

GHG projects: List the non-GHG applications

(pending or being submitted) that are associated
with the project. Note: All preconstruction
authorizations (including authorization for
emissions of greenhouse gases, if applicable) must
be obtained prior to start of construction.
B. MSS Activities
How are/will MSS activities for sources associated
This permit
with this project be authorized?
C. Consolidating NSR Permits

Will this permit be consolidated into another NSR permit with this action? No
Will NSR permits be consolidated into this permit with this action? No
D. Incorporation of Standard Permits, Standard Exemptions, and/or Permits By Rule (PBR)

To ensure protectiveness, previously issued authorizations (standard permits, standard exemptions, or PBRs)
including those for MSS, are incorporated into a permit either by consolidation or by reference. At the time of renewal
and/or amendment, consolidation (in some cases) may be voluntary and referencing is mandatory. More guidance
regarding incorporation can be found in 30 TAC § 116.116(d)(2), 30 TAC § 116.615(3) and in this memo:
https://www.tceq.texas.gov/assets/public/permitting/air/memos/pbr_spc06.pdf
Are there any standard permits, standard exemptions, or PBRs to
Yes
be incorporated by reference?
If yes, list any PBR, standard exemptions, or standard permits that
45606;114528
need to be referenced:
Are there any PBR, standard exemptions, or standard permits
associated to be incorporated by consolidation? Note: Emission
calculations, a BACT analysis, and an impacts analysis must be No
attached to this application at the time of submittal for any
authorization to be incorporated by consolidation.
E. Associated Federal Operating Permits
Version 4.0 Page 3

Is this facility located at a site required to obtain a site operating permit (SOP) or general operating
Yes
permit (GOP)?
Is a SOP or GOP review pending for this source, area, or site? No
If required to obtain a SOP or GOP, list all
associated permit number(s). If no associated
O80
permit number has been assigned yet, enter
"TBD":
IV. Facility Location and General Information

A. Location
County: Enter the county where the facility is
El Paso
physically located.
TCEQ Region Region 6
County attainment status as of Sept. 23, 2019 Part of this county is Moderate PM10 nonattainment.
Street Address: 4900 Stan Roberts Sr. Avenue
City: If the address is not located in a city, then
enter the city or town closest to the facility, even if El Paso
it is not in the same county as the facility.
ZIP Code: Include the ZIP Code of the physical
facility site, not the ZIP Code of the applicant's 79934
mailing address.
Site Location Description: If there is no street
address, provide written driving directions to the
site. Identify the location by distance and direction
from well-known landmarks such as major highway
intersections.
Use USGS maps, county maps prepared by the Texas Department of Transportation, or an online software application
such as Google Earth to find the latitude and longitude.
Latitude (in degrees, minutes, and nearest second
(DDD:MM:SS)) for the street address or the
destination point of the driving directions. Latitude
is the angular distance of a location north of the 31:58:56 N
equator and will always be between 25 and 37
degrees north (N) in Texas.
Longitude (in degrees, minutes, and nearest
second (DDD:MM:SS)) for the street address or
the destination point of the driving directions.
Longitude is the angular distance of a location west 106:25:50 W
of the prime meridian and will always be between
93 and 107 degrees west (W) in Texas.
Is this a project for a lead smelter, concrete crushing facility, and/or a hazardous waste management
No
facility?
B. General Information
Site Name: Newman Power Station
Area Name: Must indicate the general type of
operation, process, equipment or facility. Include
numerical designations, if appropriate. Examples
are Sulfuric Acid Plant and No. 5 Steam Boiler. Simply Cycle Combustion Turbine Unit 7
Vague names such as Chemical Plant are not
acceptable.
Are there any schools located within 3,000 feet of
No
the site boundary?
Version 4.0 Page 4
C. Portable Facility
Permanent or portable facility? Permanent
D. Industry Type
Principal Company Product/Business: Electric Services
A list of SIC codes can be found at:
https://www.naics.com/sic-codes-industry-drilldown/
Principal SIC code: 4911
NAICS codes and conversions between NAICS and SIC Codes are available at:
https://www.census.gov/eos/www/naics/
Principal NAICS code: 221112
E. State Senator and Representative for this site
This information can be found at (note, the website is not compatible to Internet Explorer):
https://wrm.capitol.texas.gov/
State Senator: Jose Rodriguez
District: 29
State Representative: Joseph E Moody
District: 78
V. Project Information
A. Description
Provide a brief description of the
project that is requested. (Limited
to 500 characters). Install a new simple cycle gas-fired turbine, an emergency firewater pump engine,
forced draft line heater, and associated fugitive emission components.
B. Project Timing
Authorization must be obtained for many projects before beginning construction. Construction is broadly interpreted as
anything other than site clearance or site preparation. Enter the date as "Month Date, Year" (e.g. July 4, 1776).
Projected Start of Construction: July 1, 2021

Projected Start of Operation: May 1, 2023
C. Enforcement Projects
Is this application in response to, or related to, an agency investigation, notice of violation, or
No
enforcement action?
D. Operating Schedule
Will sources in this project be authorized to operate 8760 hours per year? Yes
VI. Application Materials

All representations regarding construction plans and operation procedures contained in the permit application shall be
conditions upon which the permit is issued. (30 TAC § 116.116)
A. Confidential Application Materials
Is confidential information submitted with this application? No
Version 4.0 Page 5

B. Is the Core Data Form (Form 10400) attached? No

https://www.tceq.texas.gov/assets/public/permitting/centralregistry/10400.docx
C. Is a current area map attached? Yes
Is the area map a current map with a true north arrow, an accurate scale, the entire plant property,
the location of the property relative to prominent geographical features including, but not limited to,
highways, roads, streams, and significant landmarks such as buildings, residences, schools, parks, Yes
hospitals, day care centers, and churches?
Does the map show a 3,000-foot radius from the property boundary? Yes
D. Is a plot plan attached? Yes
Does your plot plan clearly show a north arrow, an accurate scale, all property lines, all emission
points, buildings, tanks, process vessels, other process equipment, and two bench mark locations? Yes
Does your plot plan identify all emission points on the affected property, including all emission points
authorized by other air authorizations, construction permits, PBRs, special permits, and standard Yes
permits?
Did you include a table of emission points indicating the authorization type and authorization identifier,
such as a permit number, registration number, or rule citation under which each emission point is Yes
currently authorized?
E. Is a process flow diagram attached? Yes
Is the process flow diagram sufficiently descriptive so the permit reviewer can determine the raw
materials to be used in the process; all major processing steps and major equipment items; individual
emission points associated with each process step; the location and identification of all emission Yes
abatement devices; and the location and identification of all waste streams (including wastewater
streams that may have associated air emissions)?
F. Is a process description attached? Yes
Does the process description emphasize where the emissions are generated, why the emissions must
be generated, what air pollution controls are used (including process design features that minimize Yes
emissions), and where the emissions enter the atmosphere?
Does the process description also explain how the facility or facilities will be operating when the
Yes
maximum possible emissions are produced?
G. Are detailed calculations attached? Calculations must be provided for each source with new
or changing emission rates. For example, a new source, changing emission factors,
decreasing emissions, consolidated sources, etc. You do not need to submit calculations for
sources which are not changing emission rates with this project. Please note: the preferred Yes
format is an electronic workbook (such as Excel) with all formulas viewable for review. It can
be emailed with the submittal of this application workbook.
Are emission rates and associated calculations for planned MSS facilities and related activities
Yes
attached?
H. Is a material balance (Table 2, Form 10155) attached? N/A
Version 4.0 Page 6

Technical Company: ____________
V. Nonattainment Permits
Complete the offsets section of the Federal Applicability sheet of this workbook. Yes
Does the application contain a detailed LAER analysis? (attachment or as notes on the BACT sheet
Yes
of this workbook)
Does the application contain an analysis of alternative sites, sizes, production processes, and control
techniques for the proposed source? The analysis must demonstrate that the benefits of the
Yes
proposed location and source configuration significantly outweigh the environmental and social costs
of that locati+A124on.
Version 4.0 Page 14

VIII. Federal Regulatory Questions

Indicate if any of the following requirements apply to the proposed facility. Note that some federal regulations apply to
minor sources. Enter all applicable Subparts.
A. Title 40 CFR Part 60
Do NSPS subpart(s) apply to a
Yes
facility in this application?
List applicable subparts you will
demonstrate compliance with (e.g. Subpart A, Subpart IIII, Subpart KKKK, Subpart TTTT
Subpart M)
B. Title 40 CFR Part 61
Version 4.0 Page 15

Do NESHAP subpart(s) apply to a

No
C. Title 40 CFR Part 63

Do MACT subpart(s) apply to a
Yes
List applicable subparts you will
demonstrate compliance with (e.g.
Subpart ZZZZ
Subpart VVVV)
IX. Emissions Review

A. Impacts Analysis
Any change that results in an increase in off-property concentrations of air contaminants requires an air quality
impacts demonstration. Information regarding the air quality impacts demonstration must be provided with the
application and show compliance with all state and federal requirements. Detailed requirements for the information
necessary to make the demonstration are listed on the Impacts sheet of this workbook.
Does this project require an impacts analysis? Yes
B. Disaster Review
If the proposed facility will handle sufficient quantities of certain chemicals which, if released accidentally, would cause
off-property impacts that could be immediately dangerous to life and health, a disaster review analysis may be required
as part of the application. Contact the appropriate NSR permitting section for assistance at (512) 239-1250. Additional
Guidance can be found at:
https://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/disrev-factsheet.pdf
Does this application involve any air contaminants for which a disaster review is required? No
C. Air Pollutant Watch List

Certain areas of the state have concentrations of specific pollutants that are of concern. The TCEQ has designated
these portions of the state as watch list areas. Location of a facility in a watch list area could result in additional
restrictions on emissions of the affected air pollutant(s) or additional permit requirements. The location of the areas
and pollutants of interest can be found at:
https://www.tceq.texas.gov/toxicology/apwl/apwl.html
Is the proposed facility located in a watch list area? Yes
Does this application include a pollutant of concern for the applicable area on the APWL? No
D. Mass Emissions Cap and Trade

Is this facility located at a site within the Houston/Galveston nonattainment area (Brazoria, Chambers,
No
Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties)?
Version 4.0 Page 16

Unit Types - Emission Rates Company: ____________
Permit primary industry (must be selected for workbook to function) Combustion this cell is intentionally left blank
Include these
emissions in Consolidated Consolidated Short-Term
Action Requested (only annual (tpy) Facility ID Number Emission Point Current Short- Current Long- Current Short- Current Long- Proposed Short- Proposed Long- Difference Long-Term Unit Type (Used for reviewing BACT and
1 action per FIN) summary? (FIN) Number (EPN) Source Name Pollutant Term (lb/hr) Term (tpy) Term (lb/hr) Term (tpy) Term (lb/hr) Term (tpy) (lb/hr) Difference (tpy) Monitoring Requirements)
Mitsubishi M501 GAC
New/Modified Yes SC-7 SC-7 NOx 25.2 120.58 25.2 120.58 Turbine: Simple Cycle, Natural Gas
High Load Operation
CO 18.4 237.02 18.4 237.02
VOC 7 30.66 7 30.66
PM 7 30.66 7 30.66
PM10 7 30.66 7 30.66
PM2.5 7 30.66 7 30.66
SO2 1.54 6.75 1.54 6.75
NH3 18.7 81.91 18.7 81.91
H2SO4 1.41 6.18 1.41 6.18
HAPs 1.4 6.33 1.4 6.33
CO2 Equivalent 301305 1333499 301305 1333499
Mitsubishi M501 GAC
New/Modified No SC-7 SC-7 NOx 58.5 58.5 0 Turbine: Simple Cycle, Natural Gas
MSS
CO 555.67 555.67 0
VOC 312.92 312.92 0
CO2 2.09 2.09 0
CO2 Equivalent 294159 294159 0
Emergency Diesel
New/Modified Yes FIRE-2 FIRE-2 NOx 0.6 0.028 0.6 0.028 Engine: Emergency, Diesel
Firewater Pump Engine
CO 0.13 0.007 0.13 0.007
VOC 0.05 0.003 0.05 0.003
PM 0.03 0.002 0.03 0.002
PM10 0.03 0.002 0.03 0.002
PM2.5 0.03 0.002 0.03 0.002
SO2 0.004 0.0002 0.004 0.0002
HAPs 0.0026 0.0001 0.0026 0.0001
CO2 Equivalent 113.4 5.67 113.4 5.67
Forced Draft Line
New/Modified Yes LH-1 LH-1 NOx 0.118 0.515 0.118 0.515 Heater ≤ 40 MMBtu/hr
Heater
CO 0.145 0.635 0.145 0.635
VOC 0.031 0.137 0.031 0.137
PM 0.019 0.083 0.019 0.083
PM10 0.019 0.083 0.019 0.083
PM2.5 0.019 0.083 0.019 0.083
SO2 0.004 0.017 0.004 0.017
HAPs 0.007 0.032 0.007 0.032
CO2 Equivalent 459.2 1824.61 459.2 1824.61
New/Modified Yes FUG-7 FUG-7 Unit 7 Piping Fugitives VOC 0.029 0.13 0.029 0.13 Fugitives: Piping and Equipment Leak
CO2 Equivalent 38.81 169.97 38.81 169.97
NH3 0.36 1.58 0.36 1.58
Westinghouse W-501-
Not New/Modified Yes S4-1 S4-1 NOx 174 613 174 613 0 0 Turbine: Combined Cycle, Natural Gas
B6 with Duct Burner
CO 420 833 420 833 0 0
VOC 12 44 12 44 0 0
PM 2 6 2 6 0 0
PM10 2 6 2 6 0 0
PM2.5 2 6 2 6 0 0
SO2 17 12 17 12 0 0
Westinghouse W-501-
Not New/Modified Yes S4-2 S4-2 NOx 174 613 174 613 0 0 Turbine: Combined Cycle, Natural Gas
B6 with Duct Burner
CO 420 833 420 833 0 0
VOC 12 44 12 44 0 0
PM 2 6 2 6 0 0
PM10 2 6 2 6 0 0
PM2.5 2 6 2 6 0 0
SO2 17 12 17 12 0 0
GE Frame 7EA w/out
Not New/Modified No SC-S6A SC-S6A Duct Burner High Load NOx 174 174 0 0 Turbine: Simple Cycle, Natural Gas
Operation
CO 233 233 0 0
VOC 8 8 0 0
PM 9 9 0 0
PM10 9 9 0 0
PM2.5 9 9 0 0
SO2 14 14 0 0
H2SO4 2 2 0 0
Version 4.0 Page 17

Include these
GE Frame 7EA w/out
Not New/Modified No SC-S6A SC-S6A Duct Burner SU/SD NOx 180 180 0 0 Turbine: Simple Cycle, Natural Gas
and Low Load
CO 386 386 0 0
VOC 5 5 0 0
PM 9 9 0 0
PM10 9 9 0 0
PM2.5 9 9 0 0
SO2 14 14 0 0
H2SO4 2 2 0 0
Annual Emissions from
Not New/Modified Yes SC-S6A SC-S6A NOx 286 286 0 0 Turbine: Simple Cycle, Natural Gas
EPN SC-S6A
CO 363 363 0 0
VOC 8 8 0 0
PM 29 29 0 0
PM10 29 29 0 0
PM2.5 29 29 0 0
SO2 13 13 0 0
H2SO4 2 2 0 0
GE Frame 7EA w/out
Not New/Modified No SC-S6B SC-S6B Duct Burner High Load NOx 174 174 0 0 Turbine: Simple Cycle, Natural Gas
Operation
CO 233 233 0 0
VOC 8 8 0 0
PM 9 9 0 0
PM10 9 9 0 0
PM2.5 9 9 0 0
SO2 14 14 0 0
H2SO4 2 2 0 0
GE Frame 7EA w/out
Not New/Modified No SC-S6B SC-S6B Duct Burner SU/SD NOx 180 180 0 0 Turbine: Simple Cycle, Natural Gas
and Low Load
CO 386 386 0 0
VOC 5 5 0 0
PM 9 9 0 0
PM10 9 9 0 0
PM2.5 9 9 0 0
SO2 14 14 0 0
H2SO4 2 2 0 0
Not New/Modified Yes SC-S6B SC-S6B NOx 286 286 0 0 Turbine: Simple Cycle, Natural Gas
EPN SC-S6B
CO 363 363 0 0
VOC 8 8 0 0
PM 29 29 0 0
PM10 29 29 0 0
PM2.5 29 29 0 0
SO2 13 13 0 0
H2SO4 2 2 0 0
GE Frame 7EA with
Not New/Modified No CC-S6A CC-S6A Duct Burner High Load NOx 42 42 0 0 Turbine: Combined Cycle, Natural Gas
Operation
CO 326 326 0 0
VOC 18 18 0 0
PM 15 15 0 0
PM10 15 15 0 0
PM2.5 15 15 0 0
SO2 20 20 0 0
H2SO4 3.8 3.8 0 0
NH3 20 20 0 0
GE Frame 7EA with
Not New/Modified No CC-S6A CC-S6A Duct Burner SU/SD NOx 180 180 0 0 Turbine: Combined Cycle, Natural Gas
and Low Load
CO 518 518 0 0
VOC 18 18 0 0
PM 15 15 0 0
PM10 15 15 0 0
PM2.5 15 15 0 0
SO2 20 20 0 0
H2SO4 3.8 3.8 0 0
Not New/Modified Yes CC-S6A CC-S6A NOx 165 165 0 0 Turbine: Combined Cycle, Natural Gas
EPN CC-S6A
CO 456 456 0 0
VOC 25 25 0 0
PM 38 38 0 0
PM10 38 38 0 0
Version 4.0 Page 18

Include these
PM2.5 38 38 0 0
SO2 16 16 0 0
H2SO4 3.1 3.1 0 0
NH3 50 50 0 0
GE Frame 7EA with
Not New/Modified No CC-S6B CC-S6B Duct Burner High Load NOx 42 42 0 0 Turbine: Combined Cycle, Natural Gas
Operation
CO 326 326 0 0
VOC 18 18 0 0
PM 15 15 0 0
PM10 15 15 0 0
PM2.5 15 15 0 0
SO2 20 20 0 0
H2SO4 3.8 3.8 0 0
NH3 20 20 0 0
GE Frame 7EA with
Not New/Modified No CC-S6B CC-S6B Duct Burner SU/SD NOx 180 180 0 0 Turbine: Combined Cycle, Natural Gas
and Low Load
CO 518 518 0 0
VOC 18 18 0 0
PM 15 15 0 0
PM10 15 15 0 0
PM2.5 15 15 0 0
SO2 20 20 0 0
H2SO4 3.8 3.8 0 0
Not New/Modified Yes CC-S6B CC-S6B NOx 165 165 0 0 Turbine: Combined Cycle, Natural Gas
EPN CC-S6B
CO 456 456 0 0
VOC 25 25 0 0
PM 38 38 0 0
PM10 38 38 0 0
PM2.5 38 38 0 0
SO2 16 16 0 0
H2SO4 3.1 3.1 0 0
NH3 50 50 0 0
Not New/Modified Yes FIRE FIRE Firewater Pump Engine NOx 9.3 0.9 9.3 0.9 0 0 Engine: Emergency, Diesel
CO 2 0.2 2 0.2 0 0
VOC 0.8 0.1 0.8 0.1 0 0
PM 0.7 0.1 0.7 0.1 0 0
PM10 0.7 0.1 0.7 0.1 0 0
PM2.5 0.7 0.1 0.7 0.1 0 0
SO2 0.1 0.1 0.1 0.1 0 0
H2SO4 0.1 0.1 0.1 0.1 0 0
Storage Tank (1): Fixed roof with capacity < 25
Not New/Modified Yes OTD-1 OTD-1 Diesel Storage Tank VOC 0.1 0.1 0.1 0.1 0 0
Mgal or TVP < 0.50 psia
Gas Turbine GT-6A
Not New/Modified Yes LO-1 LO-1 VOC 0.1 0.2 0.1 0.2 0 0 Process Vent
Lube Oil Vent
PM 0.1 0.2 0.1 0.2 0 0
PM10 0.1 0.2 0.1 0.2 0 0
PM2.5 0.1 0.2 0.1 0.2 0 0
Gas Turbine GT-6B
Lube Oil Vent
PM 0.1 0.2 0.1 0.2 0 0
PM10 0.1 0.2 0.1 0.2 0 0
PM2.5 0.1 0.2 0.1 0.2 0 0
Steam Turbine Lube
Oil Vent
PM 0.1 0.2 0.1 0.2 0 0
PM10 0.1 0.2 0.1 0.2 0 0
PM2.5 0.1 0.2 0.1 0.2 0 0
Not New/Modified Yes FUG-6 FUG-6 Unit 6 Piping Fugitives VOC 0.3 1.5 0.3 1.5 0 0 Fugitives: Piping and Equipment Leak
H2S 0.1 0.1 0.1 0.1 0 0
NH3 0.5 2.2 0.5 2.2 0 0
Cl2 0.1 0.4 0.1 0.4 0 0
Ammonia Storage Storage Tank (1): Fixed roof with capacity < 25
Not New/Modified Yes OTA-1 OTA-1 NH3 0.1 0.4 0.1 0.4 0 0
Tank 1 Mgal or TVP < 0.50 psia
Not New/Modified Yes CT-1467-4 CT-1467-4 Cooling Tower 4 PM 1.49 6.51 1.49 6.51 0 0 Cooling Tower
PM10 0.1 0.42 0.1 0.42 0 0
PM2.5 0.002 0.01 0.002 0.01 0 0
Version 4.0 Page 19

Include these
HOCL 0.1 0.1 0.1 0.1 0 0
Not New/Modified Yes FUG-4 FUG-4 Unit 4 Fugitives VOC 0.5 2.2 0.5 2.2 0 0 Fugitives: Piping and Equipment Leak
Cl2 0.08 0.35 0.08 0.35 0 0
MSS Fugitive
Not New/Modified Yes MSSFUG MSSFUG NOX <0.01 <0.01 <0.01 <0.01 0 0 MSS Activities
Emissions
CO <0.01 <0.01 <0.01 <0.01 0 0
PM <0.01 <0.01 <0.01 <0.01 0 0
PM10 <0.01 <0.01 <0.01 <0.01 0 0
PM2.5 <0.01 <0.01 <0.01 <0.01 0 0
VOC 7 1.07 7 1.07 0 0
NH3 <0.01 <0.01 <0.01 <0.01 0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
0 0
Version 4.0 Page 20

Stack Parameters Company: ____________
Emission Point Discharge Parameters

UTM Coordinates Height Stack Exit Fugitives -
Included in East North Building Above Diameter Velocity Temperature Fugitives - Fugitives - Axis
EPN EMEW? Zone (Meters) (Meters) Height (ft) Ground (ft) (ft) (FPS) (°F) Length (ft) Width (ft) Degrees
SC-7 Yes
FIRE-2 Yes
LH-1 Yes
FUG-7 Yes
S4-1 Yes
S4-2 Yes
SC-S6A Yes
SC-S6B Yes
CC-S6A Yes
CC-S6B Yes
FIRE Yes
OTD-1 Yes
OTD-2 Yes
OTD-3 Yes
LO-1 Yes
LO-2 Yes
LO-3 Yes
FUG-6 Yes
OTA-1 Yes
CT-1467-4 Yes
FUG-4 Yes
MSSFUG Yes
Version 4.0 Page 29

Public Notice Company: ____________
I. Public Notice Applicability

A. Application Type
Is this an application for a new or major modification of a PSD (including GHG), Nonattainment, or HAP permit?
Yes
B. Project Increases and Public Notice Thresholds (for Initial and Amendment Projects)
For public notice applicability, the agency does not include consolidation or incorporation of any previously authorized facility or
activity (PBR, standard permits, etc.), changes to permitted allowable emission rates when exclusively due to changes to
standardized emission factors, or reductions in emissions which are not enforceable through the amended permit. Thus, the total
emissions increase would be the sum of emissions increases under the amended permit and the emissions decreases under the
amended permit for each air contaminant.
The table below will generate emission increases based on the values represented on the "Unit Types - Emission Rates" sheet.
Use the "yes" and "no" options in column B of the "Unit Types - Emission Rates" worksheet to indicate if a unit's proposed change
of emissions should be included in these totals.
Notes:
1. Emissions of PM, PM10, and/or PM2.5 may have been previously quantified and authorized as PM, PM10,and/or PM2.5. These
emissions will be speciated based on current guidance and policy to demonstrate compliance with current standards and public
notice requirements may change during the permit review.
2. All renewals require public notice.

This row is optional. If you do not think
the table below accurately represents
public notice applicability increases for
your project, provide discussion here
(1000 characters).
Do the facilities handle, load, unload, dry, manufacture, or process grain, seed, legumes, or
No
vegetable fibers (agricultural facilities)?
Version 4.0 Page 30

Project Change
Current Long- Consolidated Proposed Long- Notice
Pollutant in Allowable PN Threshold
Term (tpy) Emissions (tpy) Term (tpy) required?
(tpy)
VOC 159.77 0.00 190.70 30.93 5 Yes
PM 153.22 0.00 183.97 30.75 5 Yes*
PM10 147.13 0.00 177.88 30.75 5 Yes*
PM2.5 146.72 0.00 177.47 30.75 5 Yes*
NOx 2128.91 0.00 2250.03 121.12 5 Yes
CO 3304.21 0.00 3541.87 237.66 50 Yes
SO2 82.10 0.00 88.87 6.77 10 No
Pb 0.00 0.00 0.00 0.00 0.6 No
NH3 102.61 0 186.1 83.49 5 Yes
H2SO4 10.3 0 16.48 6.18 5 Yes
HAPs 0 0 6.3621 6.3621 5 Yes
CO2 Equivalent 0 0 1335499.25 1335499.25 ** Yes
CO2 0 0 0 0 5 No
H2S 0.1 0 0.1 0 5 No
Cl2 0.75 0 0.75 0 5 No
HOCL 0.1 0 0.1 0 5 No
* Notice is required for PM, PM10, and PM2.5 if one of these pollutants is above the threshold.
** Notice of a GHG action is determined by action type. Initial and major modification always require notice. Voluntary updates
require a consolidated notice if there is a change to BACT. Project emission increases of CO2e (CO2 equivalent) are not relevant
for determining public notice of GHG permit actions.
C. Is public notice required for this project as represented in this workbook? Yes
If no, proceed to Section III Small Business Classification.
Note: public notice applicability for this project may change throughout the technical review.
D. Are any HAPs to be authorized/re-authorized with this project? The category "HAPs" must Yes
be specifically listed in the public notice if the project authorizes (reauthorizes for renewals) any
HAP pollutants.
II. Public Notice Information

Complete this section if public notice is required (determined in the above section) or if you are not sure if public notice is required.
A. Contact Information
Enter the contact information for the person responsible for publishing. This is a designated representative who is responsible
for ensuring public notice is properly published in the appropriate newspaper and signs are posted at the facility site. This person
will be contacted directly when the TCEQ is ready to authorize public notice for the application.
First Name: Daniel
Last Name: Perez
Title: Supervisor - Environmental Compliance
Company Name: El Paso Electric Company
Version 4.0 Page 31
Mailing Address: P.O. Box 982

Address Line 2:
City: El Paso
State: Texas
ZIP Code: 79901
Fax Number:
Email Address: Daniel.perez@epelectric.com
Enter the contact information for the Technical Contact. This is the designated representative who will be listed in the public notice
as a contact for additional information.
First Name: Bill
Last Name: Jamieson
Title: Director, Air Quality
Company Name: SWCA Environmental Consultants
Mailing Address: 20 E Thomas Rd
City: Phoenix
State: Arizona
ZIP Code: 85012
Fax Number:
Email Address: bjamieson@swca.com
B. Public place
Place a copy of the full application (including all of this workbook and all attachments) at a public place in the county where the
facilities are or will be located. You must state where in the county the application will be available for public review and comment.
The location must be a public place and described in the notice. A public place is a location which is owned and operated by public
funds (such as libraries, county courthouses, city halls) and cannot be a commercial enterprise. You are required to pre-arrange
this availability with the public place indicated below. The application must remain available from the first day of publication through
the designated comment period.
If this is an application for a PSD, nonattainment, or FCAA §112(g) permit, the public place must have internet access available for
the public as required in 30 TAC § 39.411(f)(3).
If the application is submitted to the agency with information marked as Confidential, you are required to indicate which specific
portions of the application are not being made available to the public. These portions of the application must be accompanied with
the following statement: Any request for portions of this application that are marked as confidential must be submitted in
writing, pursuant to the Public Information Act, to the TCEQ Public Information Coordinator, MC 197, P.O. Box 13087,
Austin, Texas 78711-3087.
Name of Public Place: TCEQ Regional Office
Physical Address: 401 East Franklin Avenue
Address Line 2: Ste. 560
City: El Paso
ZIP Code: 79901-1212
County: El Paso
Has the public place granted authorization to place the application for public
Yes
viewing and copying?
Does the public place have Internet access available for the public? No
Version 4.0 Page 32

C. Alternate Language Publication

In some cases, public notice in an alternate language is required. If an elementary or middle school nearest to the facility is in a
school district required by the Texas Education Code to have a bilingual program, a bilingual notice will be required. If there is no
bilingual program required in the school nearest the facility, but children who would normally attend those schools are eligible to
attend bilingual programs elsewhere in the school district, the bilingual notice will also be required. If it is determined that alternate
language notice is required, you are responsible for ensuring that the publication in the alternate language is complete and accurate
in that language.
Is a bilingual program required by the Texas Education Code in the School
Yes
District?
Are the children who attend either the elementary school or the middle school
closest to your facility eligible to be enrolled in a bilingual program provided by Yes
the district?
If yes to either question above, list which language(s) are required by the
Spanish
bilingual program?
D. PSD and Nonattainment Permits Only

If this is an application for emissions of GHGs, select either "Separate Public Notice" or
"Consolidated Public Notice". Note: Separate public notices requires a separate application. Consolidated Public Notice
We must notify the applicable county judge and presiding officer when a PSD or Nonattainment permit or modification application is
received. This information can be obtained at:
https://www.txdirectory.com
Provide the information for the County Judge for the location where the facility is or will be located.
The Honorable: Ricardo A. Samaniego
Mailing Address: 500 E San Antonio
City: El Paso
State: Texas
ZIP Code: 79901
Provide the information for the Presiding Officer(s) of the municipality for this facility site. This is frequently the Mayor.
First Name: Donald
Last Name: Margo
Title: Mayor
Mailing Address: 300 N Campbell
Address Line 2:
City: El Paso
State: Texas
ZIP Code: 79901
Are the proposed facilities located within
100 km or less of an affected state or No
Class I Area?
Version 4.0 Page 33

III. Small Business Classification

Complete this section to determine small business classification. If a small business requests a permit, agency rules (30 TAC §
39.603(f)(1)(A)) allow for alternative public notification requirements if all of the following criteria are met. If these requirements are
met, public notice does not have to include publication of the prominent (12 square inch) newspaper notice.
Does the company (including parent companies and subsidiary companies) have fewer than 100 employees or
No
less than $6 million in annual gross receipts?
Small business classification: No
Version 4.0 Page 34

Federal Applicability Company: ____________
I. County Classification
Does the project require retrospective review? No
County (completed for you from your response on the General sheet) El Paso
If applicable, is this facility located within the portion of the county that is in
nonattainment? Yes
This project will be located in an area that is in attainment for ozone as of

Sept. 23, 2019. Select from the drop-down list to the right if you would like
the project to be reviewed under a different classification.
This project will be located in a county with a Moderate PM10 nonattainment

classification. Complete the nonattainment section below and provide an analysis with
Determination: the application.
II. PSD and GHG PSD Applicability Summary

Is netting required for the PSD analysis for this project? No
Pollutant Project Increase Threshold PSD Review Required?
CO 237.66 100 Yes

NOx 121.12 40 Yes
PM 30.74 25 Yes
PM2.5 30.74 10 Yes

SO2 6.76 40 No
Ozone (as VOC) 114.26 40 Yes
Ozone (as NOx) 121.12 40 Yes
Pb 0 0.6 No
H2S 0 10 No
TRS 0 10 No
Reduced sulfur compounds (including H 2S) 0 10 No
H2SO4 6.18 7 No
Fluoride (excluding HF) 0 3 No
CO2e 1211545 75000 Yes
III. Nonattainment Applicability Summary

Is netting required for the nonattainment analysis for this project? No
Pollutant Project Increase Threshold NA Review Required?
Version 4.0 Page 35

Fees Company: ____________
I. General Information - Non-Renewal

Is this project for new facilities controlled and operated directly by the federal government? No
(30 TAC § 116.141(b)(1) and 30 TAC § 116.163(a))
A fee of $75,000 shall be required if no estimate of capital project cost is included with the
permit application. (30 TAC § 116.141(d)) Select "yes" here to use this option. Then skip Yes
sections II and III.
Select Application Type Major Application
Version 4.0 Page 37

In signing the "General" sheet with this fee worksheet attached, I certify that the total estimated
capital cost of the project as defined in 30 TAC §116.141 is equal to or less than the above figure. I
further state that I have read and understand Texas Water Code § 7.179, which defines Criminal
Offenses for certain violations, including intentionally or knowingly making, or causing to be made,
false material statements or representations.
Your estimated capital cost: Maximum fee appies.

Permit Application Fee: $75,000.00
VI. Total Fees

Note: fees can be paid together with one payment or as two separate payments.
Non-Renewal Fee $75,000.00
Total $75,000.00
VII. Payment Information

A. Payment One (required)
Was the fee paid online? Yes
Enter the fee amount: $ 75,000.00
Enter the check, money order, ePay Voucher, or other transaction
1284043
number:
Enter the Company name as it appears on the check: El Paso Electric Company
Version 4.0 Page 2

C. Total Paid $75,000.00

VIII. Professional Engineer Seal Requirement

Is the estimated capital cost of the project above $2 million? Yes
Is this project subject to an exemption contained in the Texas Engineering Practice Act No
(TEPA)? (30 TAC § 116.110(f))
Is the application required to be submitted under the seal of a Texas licensed P.E.? Yes
Note: an electronic PE seal is acceptable.
Version 4.0 Page 39

Impacts Company: ____________
Does this pollutant How will you demonstrate that this

Pollutant require PSD project meets all applicable Notes
review? requirements?
Protocol (required for all PSD projects,

Ozone Yes Attach a protocol meeting all requirements listed on the TCEQ website.
excluding GHG PSD)
This pollutant is not a part of this project or does not require an impacts
VOC No Not applicable
analysis.

NOx Yes Attach a protocol meeting all requirements listed on the TCEQ website.
excluding GHG PSD)

CO Yes Attach a protocol meeting all requirements listed on the TCEQ website.
excluding GHG PSD)

PM Yes Attach a protocol meeting all requirements listed on the TCEQ website.
excluding GHG PSD)
PM10 No Modeling: screen or refined Attach a completed "Electronic Modeling Evaluation Workbook" (EMEW).

PM2.5 Yes Attach a protocol meeting all requirements listed on the TCEQ website.
excluding GHG PSD)
SO2 No Modeling: screen or refined Attach a completed "Electronic Modeling Evaluation Workbook" (EMEW).
Attach a detailed description of which MERA step was met for each species
MERA analysis, steps 0-2 only or using in the project. Include speciated emission rates with the total VOC and/or
NH3 No
screening tables PM species corresponding to the short-term and long-term differences
represented on the Unit Types-Emission Rates sheet.
H2SO4 No Modeling: screen or refined Attach a completed "Electronic Modeling Evaluation Workbook" (EMEW).
Provide a detailed description of how the project meets all applicable

HAPs No Qualitative analysis impacts requirements using the Additional Notes column of this worksheet
or as an attachment.
CO2 Equivalent No Not applicable
analysis.
CO2 No Not applicable
analysis.
H2S No Not applicable
analysis.
Cl2 No Not applicable
analysis.
HOCL No Not applicable
analysis.
Version 4.0 Page 40

BACT Company: ____________
FINs Unit Type Pollutant Current Tier I BACT Confirm Additional Notes
5.0 to 9.0 ppmvd at 15% O2, typically achieved with dry low NOX burner, water/steam
SC-7 Turbine: Simple Cycle, Natural Gas NOx injection, limiting fuel consumption, or SCR. Specify numeric value and proposed Yes 2.5 ppmvd @ 15% O2
technique.
9-25 ppmvd at 15% O2, typically achieved with good combustion practices and/or
SC-7 Turbine: Simple Cycle, Natural Gas
CO oxidation catalyst. Specify numeric value and control technique. A detailed analysis is Yes 3 ppmvd @ 15% O2
required if >9 ppmvd is proposed.
VOC 2 ppmvd at 15% O2 achieved through good combustion practices. Yes

The emission reduction techniques for PM10 and PM2.5 will follow the technique for PM.
PM Yes
Good combustion practices. Fuel limited to firing pipeline quality natural gas.
Good combustion practices. Fuel limited to firing pipeline quality natural gas (low sulfur
SO2 fuel). Sulfur content of fuel will not exceed 2 to 5 grains per 100 scf on an hourly basis Yes
and 0.5 to 1 gr/100 scf on an annual basis.
7-10 ppmvd at 15% O, achieved by controlling the ammonia injection system to minimize
NH3 Yes
ammonia slip
Good combustion practices. Fuel limited to firing pipeline quality natural gas (low sulfur
H2SO4 fuel). Sulfur content of fuel will not exceed 5 grains per 100 scf on an hourly basis and 1 Yes
gr/100 scf on an annual basis.
HAPs See additional notes: Yes Good Combustion Practices, oxidation catalyst
Complies with NSPS TTTT requirements. Good combustion practices to
CO2 Equivalent See additional notes: Yes

limit CH4 emissions.
Minimizing the duration of MSS activities and operating the facility in accordance with
MSS Yes
best management practices and good air pollution control practices.
Meeting the requirements of 40 CFR Part 60, Subpart IIII. Firing ultra-low sulfur diesel
fuel (no more than 15 ppm sulfur by weight). Limited to 100 hrs./yr. of non-emergency
FIRE-2 Engine: Emergency, Diesel NOx Yes
operation. Have a non-resettable runtime meter.
FIRE-2 Engine: Emergency, Diesel
CO Yes
VOC Yes
PM Yes
No visible emissions shall leave the property. Visible emissions shall be determined by a
standard of no visible emissions exceeding 30 seconds in duration in any six-minute
period as determined using EPA TM 22 or equivalent
SO2 Yes
HAPs See additional notes: Yes Good Combustion Practices

CO2 Equivalent See additional notes: Yes Good combustion practices to limit CH4 emissions.
MSS Minimize duration and occurrence of MSS activities. Yes
Version 4.0 Page 42

BACT Company: ____________
FINs Unit Type Pollutant Current Tier I BACT Confirm Additional Notes
Burners with the best NOx performance given the burner configuration and gaseous fuel
LH-1 Heater ≤ 40 MMBtu/hr NOx used. Specify the proposed emission rate (performance is an annual average) and Yes Low NOx Burner with NOx emission rate of 0.03 lb/MMBtu.
provide justification if NOx>0.01 lb/MMBtu.
LH-1 Heater ≤ 40 MMBtu/hr
CO 50 ppmv corrected to 3% O2 Yes

Firing pipeline quality natural gas and good combustion practices. Specify if firing a
VOC Yes Only Firing Pipeline Quality Natural gas

different fuel.
PM Yes
Maximum opacity 5%
Maximum 0.6% sulfur content any liquid fuel or 5 grains for pipeline quality sweet natural
SO2 Yes The fuel will contain less than 5 grains of sulfer per dscf.
gas. Provide details.
HAPs See additional notes: Yes Good Combustion Practices

CO2 Equivalent See additional notes: Yes Good combustion practices to limit CH4 emissions.
MSS Same as normal operation BACT requirements.
Provide details about applicable option:

1. Uncontrolled VOC emissions < 10 tpy - no control required
2. 10 tpy < uncontrolled VOC emissions < 25 tpy - 28M LDAR program. 75% credit.
3. Uncontrolled VOC emissions > 25 tpy - 28VHP LDAR program. 97% credit for valves,
85% for pumps and compressors. 1. Emissions are low in VOC due to pipeline quality natural gas low VOC
FUG-7 Fugitives: Piping and Equipment Leak VOC Yes
4. VOC vapor pressure < 0.002 psia - no inspection required, no fugitive emissions content.
expected.
For emissions of chlorine and other approved odorous compounds: AVO inspection twice
per shift.
Piping fugitivies have same control method for GHG as for VOC. Circuit
FUG-7 Fugitives: Piping and Equipment Leak
CO2 Equivalent See additional notes: Yes breakers will be enclosed, pressurized SF6 circuit breakers with pressure
monitoring.
NH3 AVO inspection Yes

Same as normal operation BACT requirements. Best management practices (BMPs) will
be used to minimize emissions, including using proper design of fuel delivery and
MSS handling, good air pollution control practices, and safe operating practices. Estimate Yes
fugitive emissions of sources such as natural gas, diesel, and ammonia. Leak detection
and repair program as required for minimizing VOC leaks.
Version 4.0 Page 43

Date: ____________
Texas Commission on Environmental Quality Permit #: ____________
Form PI-1 General Application Company: ____________
Monitoring
Press TAB to move input areas Press UP or DOWN ARROW in column A to read through the document On this sheet if a FIN is not listed in the first column of the table the remainder of the table is complet This cell intentionally left blank
Monitoring
This sheet provides the minimum acceptable requirements to demonstrate compliance through monitoring for each pollutant proposed to be emitted from each FIN. This sheet also includes measuring techniques for source
of significant emissions in the project.
Instructions:
1. The unit types listed under Unit Type (column B) include all new, modified, consolidated, and/or renewed sources as indicated on the "Unit Types - Emission Rates" sheet. Each new, modified, consolidated, and/or
renewed source must address how compliance will be demonstrated.
2. The pollutants listed in Pollutant (column C) include the pollutants indicated on the "Unit Types - Emission Rates" sheet.
Monitoring (30 TAC § 116.111(a)(2)(G))

3. The minimum acceptable monitoring is automatically populated for each unit type and pollutant.
- Additional monitoring may be required, particularly for Title V sources, and will be included in the NSR and/or Title V permits.
4. Fully expand the Minimum Monitoring Requirements (column D) by increasing the row heights so all text is visible. (Place the cursor on the bottom of the number line to the far left of the screen, click and drag
downward until all text is visible.)
5. Review the monitoring and confirm that you will meet all representations listed on the sheet and any additional attachments by entering or selecting "Yes" in Confirm (column E).
6. Add additional notes as necessary in Additional Notes for Monitoring (column F), limited to 500 characters or fewer. Examples include the following:
- Proposed monitoring for pollutants or units that list "See additional notes:";
- Details requested in the populated data;
- Alternative monitoring you are proposing; and
- Any additional information relevant to the minimization of emissions.
7. Cap EPNs do not need monitoring (leave those rows blank).
Measurement of Emissions (30 TAC § 116.111(a)(2)(B))

Note: this section will be greyed out if this project does not require PSD or nonattainment review, as represented on the General sheet.
7. For each pollutant with a project increase greater than the PSD significant emission rate, select the proposed measurement technique using the dropdown (column G).
8. For each pollutant with a project increase less than the PSD significant emission rate: leave blank.
9. If selecting "other", provide details in Additional Notes for Measuring (column H).
10. You may also use the Additional Notes for Measuring (column H) to provide more details on a selection.
Click here to return to Cover Sheet. This cell intentionally left blank
Important Note: The permit holder shall maintain a copy of the permit along with records containing the information and data sufficient to demonstrate compliance with the permit, including production records and operating
hours. All required records must be maintained in a file at the plant site. If, however, the facility normally operates unattended, records shall be maintained at the nearest staffed location within Texas specified in the
application. The site must make the records available at the request of personnel from the commission or any air pollution control program having jurisdiction in a timely manner. The applicant must comply with any additional
recordkeeping requirements specified in special conditions in the permit. All records must be retained in the file for at least two years following the date that the information or data is obtained. Some permits are required to
maintain records for five years. [30 TAC § 116.115(b)(2)(E)]
Proposed Measurement Technique (only complete for

FIN Unit Type Pollutant Minimum Monitoring Requirements Confirm Additional Notes for Monitoring pollutants with a project increase above the PSD Additional Notes for Measuring:
threshold)
SC-7 Turbine: Simple Cycle, NOx CEMS. Data collected four times per hour and averaged hourly. Yes CEMS
CO CEMS. Data collected four times per hour and averaged hourly. Yes CEMS
VOC Continuous fuel flow monitor data used to calculate emission rate. Yes Record keeping
PM The emission monitoring techniques for PM10 and PM2.5 will follow Yes Record keeping
SO2 Continuous fuel flow monitor data used to calculate emission rate. Yes
NH3 If this pollutant is applicable, monthly AVO inspections of the Yes

H2SO4 If this pollutant is applicable, quarterly visible emission observation Yes

HAPs See additional notes: Yes Continuous fuel flow monitor to calculate emission rate.
Compliance with NSPS TTTT monitoring requirements and records Record keeping
of maintenance of the unit in accordance with manufacturer's

recommendations to keep the unit at peak generating efficiency and
ensure complete combustion of CH4.
FIRE-2 Engine: Emergency, Diese NOx Use of portable analyzer designed to measure the concentration in Yes Record keeping
CO Use of portable analyzer designed to measure the concentration in Yes Record keeping
VOC Fuel usage monitoring, and recordkeeping. Yes Record keeping

SO2 Records of fuel delivery indicating date and quantity of fuel deliveredYes
HAPs See additional notes: Yes Fuel usage monitoring and recordkeeping
Maintain and operate unit to ensure complete combustion of Record keeping

methane.
LH-1 Heater ≤ 40 MMBtu/hr NOx Stack sampling, fuel usage monitoring, and recordkeeping. Yes Record keeping
CO Stack sampling, fuel usage monitoring, and recordkeeping Yes Record keeping
VOC Stack sampling if other than natural gas AP42 factor initially Yes Record keeping
Stack sampling if other than natural gas 5 gr S/100 dscf factor
SO2 Yes
initially represented. Fuel usage monitoring and recordkeeping.
HAPs See additional notes: Yes Fuel monitoring and recordkeeping

Maintain and operate unit to ensure complete combustion of Record keeping

methane.
FUG-7 Fugitives: Piping and VOC Fugitive Programs (i.e. AVO, 28VHP, 28MID, etc.) Yes AVO Record keeping
CO2 Equivalent See additional notes: Yes AVO Record keeping

NH3 May be applicable depending on process. If so, use AVO fugitive Yes AVO Record keeping
Version 4.0 Page 49

Materials Company: ____________
Item How submitted Date submitted

A. Administrative Information
Form PI-1 General Application Email
Hard copy of the General sheet with original (ink) signature Mail
Professional Engineer Seal Email
B. General Information
Copy of current permit (both Special Conditions and MAERT)
Core Data Form
Area map Not applicable
Plot plan Email
Process description Email
Process flow diagram Email
List of MSS activities Email
State regulatory requirements discussion Email
C. Federal Applicability
Summary and project emission increase determination - Tables 1F and 2F Email
Netting analysis (if required) - Tables 3F and 4F as needed
D. Technical Information
BACT discussion, if additional details are attached Email
Monitoring information, if additional details are attached Email
Material Balance (if applicable)
Calculations Email
E. Impacts Analysis
Qualitative impacts analysis Email
MERA analysis Email
Electronic Modeling Evaluation Workbook: SCREEN3 Not applicable
Electronic Modeling Evaluation Workbook: NonSCREEN3 Email
PSD modeling protocol Email
F. Additional Attachments
Version 4.0 Page 57

Appendix E. Texas Professional Engineer (P.E.) certification statement

EPE NSR Permit Application V1.17-Min

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EL PASO ELECTRIC COMPANY

NEWMAN GENERATING STATION

SWCA Project No. 55480

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2 Project Description ............................................................................................................................... 3

3 Project Emissions ................................................................................................................................. 9

4 Air Quality Regulatory Review ......................................................................................................... 13

5 Air Pollution Control Evaluation ...................................................................................................... 22

6 Air Quality Impacts Analysis ............................................................................................................ 41

7 Nonattainment New Source Review.................................................................................................. 42

7.1.3 Compliance History Review ............................................................................................. 42

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2.1 General Site Information

Table 1. Site Location

El Paso El Paso 31.98342 -106.42824 4,056 feet

Table 2. Existing Emission Unit Authorizations

B2 Unit 2 Boiler 45606

B3 Unit 3 Boiler 45606

B4CA Unit 4, Combustion Turbine GT-1 1467,PSDTX1090

B4CB Unit 5, Combustion Turbine GT-2 1467,PSDTX1090

B4DA Unit 4, GT-1 Duct Burner and HRSG 1467,PSDTX1090

B4DB Unit 4, GT-2 Duct Burner and HRSG 1467,PSDTX1090

CT-1467-4 Cooling Tower 1467,PSDTX1090

CT-1467-6 Cooling Tower 1467,PSDTX1090

CT-1 Cooling Tower 45606

CT-2 Cooling Tower 45606

CT-3 Cooling Tower 45606

New Source Review

DB-6B Duct Burner 6B 1467,PSDTX1090

DB-S4-1 Duct Burners Unit S4-1 114528

DB-S4-2 Duct Burners Unit S4-2 114528

FIRE Firewater Pump Engine 1467,PSDTX1090

FUG Piping Fugitives 1467,PSDTX1090

GEN Emergency Generator Engine 1467,PSDTX1090

GT-6A Combustion Turbine GT-6A 1467,PSDTX1090

GT-6B Combustion Turbine GT-6B 1467,PSDTX1090

LO-1 Gas Turbine GT-6A Lube Oil Vent 1467,PSDTX1090

LO-2 Gas Turbine GT-6B Lube Oil Vent 1467,PSDTX1090

LO-3 Steam Turbine Lube Oil Vent 1467,PSDTX1090

OT-1 Fuel Storage Tank 1 (TK1) 45606

OT2 Fuel Storage Tank 2 (TK2) 45606

OT6 Residual Oil Tank (Old TK1) 45606

OTD-1 Diesel Storage Tank 1 1467,PSDTX1090

OTD-2 Diesel Storage Tank 2 1467,PSDTX1090

OTD-3 Diesel Storage Tank 3 1467,PSDTX1090

S1 Stack, Unit 1 Boiler 45606

S2 Stack, Unit 2 Boiler 45606

S3 Stack, Unit 3 Boiler 45606

S4-1 Stack, Unit 4, Combustion Turbine and HRSG, GT-1 1467,PSDTX1090

S4-2 Stack, Unit 4, Combustion Turbine and HRSG, GT-2 1467,PSDTX1090

UL-1 Tank Truck Unloading Station for Diesel Fuel 45606

Fran klin Mou nta in s

Service Layer Credits: Sources: Esri, HERE, Garmin,

Site Location Review Area

Wetland 0 200 400 600 Meters

2.2 Proposed Project

Table 3. Proposed Project Emission Units

SC-7 SC-7 Unit 7 Simple Cycle Turbine

LH-1 LH-1 Line Heater