Pre-Construction Review
and
Preliminary Determination
of Approval for
Entergy Mississippi LLC, Delta Blues Advanced Power Station
Facility No. 2800-00142

Technical Review
by
Clinton Gentry

Air Quality Analysis
By
Katherine Mertes

March 5, 2025
I.	General Information
Entergy Mississippi LLC (“Entergy”), Delta Blues Advanced Power Station (“DBAPS”),  located at 221 Stokes King Road, Greenville, Mississippi 38701, (501) 658-1851 (Russell McLaren, Environmental Manager), has submitted a complete air permit application for a Prevention of Significant Deterioration Construction Permit to construct a greenfield 1x1 combined cycle power plant.
II.	Project Description
Entergy’s proposed DBAPS will be a new 750-MW natural gas fired 1x1 combined cycle base-load power plant. The DBAPS is intended to replace operations at the existing Gerald Andrus power plant, located 1.2 miles away. 
Gas Turbine, Duct Burner, and Steam Turbine Operations
The power generation equipment proposed for Delta Blues includes a Mitsubishi Model M501JAC Gas Turbine (GT) equipped with supplementary-fired duct burners and a Heat Recovery Steam Generator (HRSG). To boost the thermal efficiency of the gas turbine, the combustion air fed to the GT compressor can be saturated with water in an evaporative cooler at various times, predominantly during warm weather conditions. In addition to power from a generator turned by the gas turbine shaft, additional power is produced by a steam turbine generator which is fed steam generated in the HRSG. Final condensation of steam exiting the steam turbine is accomplished using air-cooled condensers, so no cooling towers will be present at Delta Blues. At the 59° F ISO design case, the Delta Blues 1x1 combined cycle unit will have an efficient net heat rate of 6,584 Btu/kWh, which equates to a relatively high net thermal efficiency of 51.8%. The maximum firing rates of the GT and duct burner are 4,120 MMBtu/hr-HHV, and 863 MMBtu/hr-HHv, respectively, at a cold weather ambient temperature firing condition of 10° F. The gas turbine and duct burners will be permitted to operate continuously (8,760 hr/yr). Numerous performance scenarios are presented in Table A-2 in Appendix A of the Prevention of Significant Deterioration Construction Permit Application and associated emissions have been calculated for each operating scenario. 
Proposed emissions controls for the gas turbine/duct burner flue gas include an ammonia-based Selective Catalytic Reduction (SCR) system to reduce NOx emissions and a catalytic oxidation unit to reduce CO and VOC emissions. Emissions of GHGs are limited by using natural gas as a fuel and installing a power generation system with high thermal efficiency. GT and duct burner combustion flue gas exit the main stack after passing through the emission control equipment. 
Lube Oil Recirculation Systems
The new combustion turbine and steam turbine will each be equipped with a dedicated lubrication system. Lubrication oil will be circulated through each turbine’s machinery from the system’s oil sumps. The oil sumps will be equipped with a vent that will be controlled by an oil mist eliminator. Emissions from the oil mist eliminators are based on lube oil replacement rates for similar units equipped with mist eliminators. Both VOCs and PM emissions are expected to be emitted from the combustion turbine lube oil vent and the steam turbine lube oil vent. The lube oil vent will be permitted to operate continuously (8,760 hr/yr).
Natural Gas System and Dewpoint Heater Operations
Pipeline quality natural gas will be delivered to the site via pipeline where it is metered and piped to the natural gas-fired units. To prevent liquid droplets from entering the GT, the natural gas fuel to the GT will be indirectly heated in a small natural gas fired dewpoint heater). The dewpoint heater will be permitted to operate continuously (8,760 hr/yr).
Combined Cycle Unit Startup/Shutdown Operations
Startup/Shutdown (“SUSD”) of the proposed combined cycle unit will occur infrequently as DBAPS will be a base load power plant. Startup is defined as the period beginning when the gas turbine receives a “turbine start” signal and an initial flame detection signal is recorded in the plant’s control system and ending when the combustion turbine output reaches minimum sustainable load (50% load), which is typically the point at which the unit reaches the lean pre-mix operating mode. The shutdown period is defined as the period beginning when the gas turbine receives a “turbine stop” command and the generator output drops below the minimum stable load (50% load) and ending when a flame detection signal is no longer recorded in the plant’s control system. SUSD emissions from the combined cycle unit are emitted from the main stack (DBAPS-1A) and are accounted for in the annual emission limits for this point source. The SCR and catalytic oxidation units will be coming up to temperature and not fully operational during SUSD; therefore, SUSD are not controlled. 
Higher-than-normal emissions from the main stack may occur during gas turbine tuning and optimization maintenance activities. In addition to gas turbine optimization during the commissioning period, the gas turbine’s fuel system requires periodic tuning, including after major overhauls, to maintain compliance with manufacturer’s specifications for emissions and combustion dynamics. The turbine tuning is conducted across the combustor’s load range and according to manufacturer recommendations to minimize NOx and CO production while ensuring combustor stability. During these gas turbines tuning and optimization activities, the gas turbine CO and NOx emissions will be limited to the same levels as SUSD.
Diesel-fired Emergency Internal Combustion Engines
The DBAPS will have two emergency diesel-fired IC engines. The engines will be limited to 100 hr/yr of operation or less in non-emergency operating modes due to the engines’ emergency classification status. The engines will not be constrained by an operating limit for legitimate emergency operating modes. 
One emergency diesel-fired IC engine is a 2,180-kilowatt (kW) emergency standby generator. The proposed engine is a Mitsubishi Model S16R-Y2PTAW2-1 with a 2,932 BHP rating. The engine will only fire Ultra Low Sulfur Diesel (ULSD) with a maximum sulfur content of 15 parts per million weight (ppmw). The engine will be a USEPA-certified Tier 2 engine.
The other emergency diesel-fired IC engine is a 235-kW emergency fire water pump. The proposed engine is a John Deere Model 6068HFC48A with a 282 BHP rating. The engine will only fire ULSD with a maximum sulfur content of 15 ppmw. The engine will be a USEPA-certified Tier 2 engine. 
Diesel and Ammonia Storage Tanks
DBAPS is proposing to have two fixed-roof diesel storage tanks. Each tank will provide ULSD fuel to one of the two emergency IC engines. The tank that will supply ULSD to the emergency generator is a 99 barrel (bbl) (4,150 gallon) white, horizontal fixed-roof tank. The tank will supply ULSD to the emergency fire water pump is a 12 bbl (500gal) white, horizontal fixed-roof tank. 
Ammonia will be stored in a 40,000-gallon pressurized tank with no routine air emissions. Therefore, no emission point ID is assigned to the ammonia storage tank.
Fugitive Emissions
The proposed site will have piping in natural gas, diesel and ammonia service. Potential fugitive emissions from piping components (valves, flanges, connectors, pumps, open-ended lines, and relief valves) are calculated based on a count of components and emissions factors associated with the liquid or gas/vapor service of the components. Equipment components are either in natural gas, diesel or ammonia service. The fugitive emission sources are defined by their service as follows:
•	Emission Point AA-005 – addresses fugitive emissions of equipment components in natural gas service. 
•	Emission Point AA-006 – addresses fugitive emissions of equipment components in ammonia service.
•	Emission Point AA-007- addresses fugitive emissions of equipment components in diesel service. 
III.	Federal Regulations

40 CFR 60, Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal Combustion Engines
This subpart establishes standards and compliance schedules for manufacturers, owners, and operators of stationary compression ignition (CI) internal combustion engines (ICE). Emission Points AA-002 and AA-003 meet the definition of new, stationary RICE. As such, these emissions points are subject to this subpart.
40 CFR 60, Subpart KKKK – Standards of Performance for Stationary Combustion Turbines
This subpart establishes standards and compliance schedules for the control of emissions from stationary combustion turbines that commenced construction, modification, or reconstruction after February 18, 2005. Emission Point AA-001 meets the definition of a new, stationary combustion turbine under this subpart and as such, is subject to this subpart.
40 CFR 60, Subpart TTTTa – Standards of Performance for Greenhouse Gas Emissions for Modified Coal-Fired Steam Electric Generating Units and New Construction and Reconstruction Stationary Combustion Turbine Electric Generating Units
This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a coal-fired steam generating unit or integrated gasification combined cycle facility (IGCC) that commences modification after May 23, 2023. This subpart also establishes emission standards and compliance schedules for the control of GHG emissions from a stationary combustion turbine that commences construction or reconstruction after May 23, 2023. An affected coal-fired steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected electric generating unit (EGU). Emission Point AA-001 meets the definition of a new, stationary combustion turbine under this subpart and as such, is subject to this subpart.
40 CFR 63, Subpart ZZZZ – National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines
This subpart establishes national emission limitations and operating limitations for hazardous air pollutants (HAP) emitted from stationary reciprocating internal combustion engines (RICE) located at major and area sources of HAP emissions. This subpart also establishes requirements to demonstrate initial and continuous compliance with the emission limitations and operating limitations. Emission Points AA-002 and AA-003 meet the definition of new, stationary RICE located at an area source of HAP in which construction was commenced after June 12, 2006. As such, these emission points are subject to this subpart. However, compliance with 40 CFR 63, Subpart ZZZZ will be achieved by complying with all applicable requirements under 40 CFR 60, Subpart IIII since these engines are considered “new or reconstructed RICE located at an area source”. As such, no further requirements apply for such engines under 40 CFR 63, Subpart ZZZZ.
IV.	Best Available Control Technology (BACT) Analysis

Table 1. PSD Applicability
Pollutant	Project-Related Increases
(TPY)	Significant Emission Rate
(TPY)	Netting Analysis Required?
(Yes/No)	Contemporaneous Emissions
(TPY)	Total Net Emissions
(TPY)	PSD Review Required?
(Yes/No)	
PM	167.94	25	No	0.00	167.94	Yes	
PM10	248.31	151	No	0.00	248.31	Yes	
PM2.5	248.31	10	No	0.00	248.31	Yes	
NOX1,2	801.85	40	No	0.00	801.85	Yes	
SO21	61.26	40	No	0.00	61.26	No	
VOC2	124.68	40	No	0.00	124.68	Yes	
CO	812.58	100	No	0.00	812.58	Yes	
1 As of April 28, 2011, both NOx and SO2 are precursors for PM2.5.  Therefore, if NOx or SO2 exceed 40 TPY, the project is considered major for PM2.5.
2 Both NOx and VOC are considered precursors for ozone with a significant emission rate of 40 TPY each.	

In accordance with PSD requirements listed in 40 CFR 51.166(j) and 52.21(j) and 11 Miss. Admin. Code Pt. 2, Ch. 5. Rule 5.1, a new major stationary source must apply BACT for the control of each regulated air pollutant emitted in significant quantities. Therefore, Entergy completed a BACT analysis for VOC, PM, NOx, and CO.
BACT is defined in the federal PSD regulation at 40 CFR 52.21(b)(12) as follows:
	Best available control technology (BACT) means an emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR 60, 61, or 63. If the administrator determines the technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the requirement for the application of best available control technology. Such standards shall, to the degree possible, set for the emissions reduction achievable by implementation of such design, equipment, work practice or operation, and shall provide for compliance by means which achieve equivalent results. 
The selection of BACT requires consideration of cost, environmental, and energy impacts. In the USEPA’s draft document New Source Review Workshop Manual (USEPA, October 1990), USEPA recommends a “top-down” approach when evaluating commercially available and demonstrated air pollution control technologies for BACT. Note that a top-down approach is suggested by policy and not by regulation. For certain small emission sources, the BACT demonstration may depend on what is typically used in industrial applications as detailed in the RBLC information in Appendix C. According to the definition of BACT, if a facility is subject to a NSPS or NESHAP standard, the selected BACT must never result in an emission limit that is less stringent than any applicable NSPS and/or NESHAP rule. 
The first step in the “top down” approach is to determine, for the emissions unit and the PSD pollutant in question, the most stringent demonstrated control technology available for a similar or identical source or source category. If it can be shown that this level of control is technically or economically infeasible for this project, the next most stringent level of control is then determined and similarly evaluated. This process continues until a control technology and associated emission level is determined that cannot be eliminated by any technical or economic infeasibility. The “top-down” approach has been employed in this analysis to evaluate available pollution controls for the proposed DBAPS. The following sections describe the pollutant-by-pollutant BACT for all emissions units at the proposed Delta Blues facility. 
A.	Gas Turbine/Duct Burner Combustion Main Stack
The power generation equipment proposed for Sawgrass includes a Mitsubishi Model M501JAC GT equipped with supplementary-fired duct burners and a HRSG.  The BACT demonstration for the GT/duct burner main stack is presented as follows for each NSR regulated pollutant emitted from SPS-1A.
(1)	Nitrogen Oxides (NOX) BACT Analysis
NOx is generally formed during combustion by thermal oxidation of nitrogen in the combustion air (thermal NOx) and the oxidation of nitrogen in the fuel (fuel-bound NOx). Natural gas contains relatively small amounts of fuel-bound nitrogen and NOx formation through the fuel NOx mechanism is expected to be insignificant. The main variables affecting NOx generation in the gas turbine/duct burner installations are temperature, the availability of nitrogen, the availability of oxygen, and the extent of contact between nitrogen and oxygen during the combustion process. NOx formation is maximized in zones of high combustion temperatures.
Step 1: Identify Available Control Technologies 
Available NOx control technologies for gas turbine/duct burner installations include: 
• Wet Injection: The injection of water directly into the combustion chamber lowers the flame temperature by absorbing heat necessary to vaporize the water and raise the temperature of the steam to that of the combustion temperature. Steam injections utilize the same principle, although heat can only be absorbed by the steam in raising the steam’s temperature to that of combustion. Injection of either water or steam results in lower “thermal NOx” formation. This technology can achieve a flue gas NOx concentration of 42 ppmvd @ 15% O2. 
• Dry Low-NOx Combustor/Burner Design: One method of reducing “thermal NOx” formation is by utilizing a dry low-NOx (DLN) combustor that premixes the air and fuel prior to entering the primary combustion chamber. This allows for a lower flame temperature due to the homogeneity of the air/fuel mix, and the lack of a flame front. Advanced combustor design also includes reducing the combustion zone residence time and limiting the oxygen available to combine with nitrogen to form NOx. Entergy’s proposed gas turbine and duct burner include DLN combustors. This technology can achieve a flue gas NOx concentration between 9 and 25 ppmvd @ 15% O2. 
• Selective Catalytic Reduction (SCR): SCR is similar to SNCR except that with SCR, a catalyst is present during the chemical reactions that produce nitrogen and water vapor from NOx. Like SNCR, SCR requires ammonia injection to participate in the NOx reduction chemical reactions. Entergy proposes to utilize SCR for this gas turbine/duct burner installation. By itself, this technology can achieve a flue gas NOx concentration between 2 and 3 ppmvd @ 15% O2. In conjunction with DLN burners, this technology can achieve a flue gas NOx concentration of 2 ppmvd @ 15% O2. 
• Selective Non-Catalytic Reduction (SNCR): SNCR is a process in which ammonia or urea is injected directly into the exhaust gas stream to produce nitrogen and water vapor from NOx. The chemical reactions take place without the presence of a catalyst, and due to reaction temperature considerations, the ammonia or urea injection must occur in a location where the exhaust gas temperatures are between approximately 1,600°F and 2,000°F. The exhaust gas temperature range for the proposed units does not allow for SNCR to be a feasible control technology, as the exhaust temperature for this project will be considerably below this range. 
• Non-Selective Catalytic Reduction (NSCR): NSCR is a process that utilizes a catalyst to produce nitrogen and water vapor from NOx without the presence of a reducing agent. This technology has not yet been developed for large-scale combustion turbine applications and is currently only utilized in reciprocating internal combustion engines. Thus, NSCR is considered technically infeasible for this application. 
Step 2: Eliminate Technically Infeasible Options
Two available NOx control technologies were determined not to be technically feasible. As described above, these technically infeasible NOx control technologies include SNCR and NSCR. 
Step 3: Rank Remaining Options by Control Effectiveness
The available and technically feasible NOx control technologies for gas turbine/duct burner installations are ranked in order in Table 7.1. 
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top control technology. 
Step 5: Select BACT 
Entergy proposes to accept the top control technology in Table 7.1. The GT/duct burner system will utilize dry low-NOx combustors and an ammonia-based SCR control system which will yield a vendor-guaranteed flue gas NOx concentration of 2.0 ppmvd NOx @ 15% O2 (24-hr-average basis). A review of RBLC confirms this control system represents the top available and technically feasible NOx control technology for GT/duct burner systems. Of the 58 RBLC entries with a PSD BACT limit of 2.0 ppmvd @ 15% O2, 22 of those entries had a primary limit averaging period 24-hr which was the most common averaging period.
Table 7.1: GT/DB NOX Technically Feasible Control Options	
Ranking	GT/DB NOX Control Technology	NOX Concentration                (PPMVD @ 15% O2)	
1	SCR + Dry Low NOX Combustors/Burners	2.0	
2	SCR	2 – 3	
3	Dry Low NOX Combustors/Burners	9 – 25	
4	Water/Steam Injection	42	

(2)	Carbon Monoxide (CO) BACT Analysis
Carbon monoxide forms in combustion devices as a product of incomplete combustion. Production of CO results when there is a lack of oxygen and insufficient residence time at high enough temperatures to complete the final step in oxidation. Controlling these factors to decrease CO, however, also tends to result in increased emissions of NOx. Conversely, a lower NOx emission rate achieved through flame temperature control may result in higher levels of CO emissions. Thus, a balance must be established, whereby the flame temperature, residence time and excess oxygen are set to achieve the lowest NOx emission rate possible to comply with BACT while keeping CO emissions to an acceptable level.
Step 1: Identify Available Control Technologies
The two available CO control options for gas turbine/duct burner installations include:
• Combustion Controls/Good Combustion Techniques, and
• Catalytic Oxidation Add-on Control Device
CO combustion control performance (good combustion techniques) is a function of available oxygen, combustion temperature, turbulence, and residence time. Formation of CO is a result of incomplete combustion of the fuel. Adequate fuel residence time and high temperature in the combustion zone can ensure minimal CO formation. A properly designed combustion system is effective at limiting CO formation by maintaining the optimum combustion zone temperature and amount of excess oxygen. Unfortunately, the addition of excess air and maintenance of high combustion temperatures for control of CO emissions may lead to increased NOx emissions. Consequently, typical practice is to design the combustion system such that CO emissions are reduced as much as possible without causing NOx levels to significantly increase.
The only add-on control device that is commercially available for controlling CO emissions from gas turbine/duct burner installations is an oxidation catalyst. The catalyst lowers the activation energy necessary for CO to react with available oxygen in the exhaust to produce CO2. Oxidation catalysts operate optimally at a temperature range of 500° to 700° F and can also reduce volatile organic compounds (VOC) emissions.
Step 2: Eliminate Technically Infeasible Options
The two available CO control technologies for gas turbine/duct burner installations are both technically feasible. Entergy is proposing to employ both of these CO control technologies for this gas turbine/duct burner system.
Step 3: Rank Remaining Options by Control Effectiveness
The top CO control technology is identified as good combustion techniques along with an add-on catalytic oxidation. In conjunction, these two technologies will result in a flue gas CO concentration of 2.0 ppmvd CO @ 15% O2 (24-hr-average basis).
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top CO control technology.
Step 5: Select BACT
The GT/duct burner system will utilize good combustion techniques and an add-on catalytic oxidation control system. This will yield a vendor-guaranteed flue gas CO concentration of 2.0 ppmvd CO @ 15% O2 (24-hr-average basis). Based on a review of RBLC, this control system represents the “top” available and feasible CO control technology for GT/duct burner systems. There were 108 RBLC entries with a primary CO limit ranging up to 50 ppmvd with the majority of limits set at 2.0 ppmvd. As a result, catalytic oxidation with a CO performance level of 2.0 ppmvd CO @ 15% O2 (24-hr-average basis) is selected as BACT for CO.
(3)	Volatile Organic Compounds (VOC) BACT Analysis
Like CO, VOC emissions result from incomplete combustion. VOC is unburned and emitted from the stack when there is a lack of oxygen and insufficient residence time at high enough temperatures to complete the final step in oxidation. 
Step 1: Identify Available Control Technologies 
Similar to CO, there are two available VOC control options for gas turbine/duct burner installations: 
• Combustion Controls/Good Combustion Techniques, and 
• Catalytic Oxidation Add-on Control Device. 
Step 2: Eliminate Technically Infeasible Options 
The two available VOC control technologies for gas turbine/duct burner installations identified above are both technically feasible. Entergy is proposing to employ both of these VOC control technologies for this gas turbine/duct burner system. 
Step 3: Rank Remaining Options by Control Effectiveness 
The top VOC control technology is identified as good combustion techniques along with an add-on catalytic oxidation. In conjunction, these two technologies will result in a flue gas VOC concentration of 1.5 ppmvd @ 15% O2 (annual-average basis). 
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts 
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top VOC control technology. 
Step 5: Select BACT 
The GT/duct burner system will utilize good combustion techniques and a catalytic control system which will yield a vendor-guaranteed flue gas VOC concentration of 1.5 ppmvd VOC @ 15% O2 (annual-average basis). Based on a review of RBLC, this control system represents the “top” available and feasible VOC control technology for GT/duct burner systems. As a result, catalytic oxidation with a VOC performance level of 1.5 ppmvd VOC @ 15% O2 (annual-average basis) is selected as BACT for VOC. Because the “top” control technology is selected, no further VOC BACT analysis is required.
(4)	Particulate Matter (PM10 and PM2.5) BACT Analysis
Particulate matter (PM) emissions, which include both PM10 and PM2.5 emissions, from combined cycle turbine/duct burner installations are the result of unburned trace constituents in the fuel, unburned hydrocarbons, and the inlet air supply that may contain dust particles. PM emissions can also result from the formation of sulfates and nitrates, which are formed when certain sulfur- and nitrogen-oxide compounds react with ammonia. The following section describes control technologies that can be applied to reduce PM emissions from this gas turbine/duct burner installation.
Step 1: Identify Available Control Technologies
The control technologies that can potentially be used to control PM emissions include:
• Fabric Filter (Baghouse);
• Electrostatic Precipitator (ESP);
• Use of Clean Gaseous Fuels (e.g., pipeline quality natural gas); and
• Good Combustion Practices.
Step 2: Eliminate Technically Infeasible Options
The two available add-on PM control technologies identified above, baghouses and ESPs, were determined not to be technically feasible. The concentration of PM in the flue gas from a gas turbine/duct burner installation is low. Further, the sizes of particles in the flue gas stream are very small. Due to the high volumetric flow rates and low particulate concentrations in the exhaust stream from the gas turbine/duct burner installation, use of a baghouse or ESP is considered technically infeasible and are eliminated from further BACT consideration. There are no known existing natural gas fired gas turbine/duct burner installations that utilize add-on PM control equipment.
Step 3: Rank Remaining Options by Control Effectiveness
The use of good combustion practices and clean gaseous fuels are both technically feasible options, and the use of both options is what is selected for BACT for this installation.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top control technology.
Step 5: Select BACT
By virtue of firing clean-burning pipeline natural gasPM10 and PM2.5 are emitted in small quantities from the GT/duct burner. The use of a catalytic oxidation system results in additional PM emissions, but this tradeoff is acceptable to further control emissions of VOC and CO. The expected flue gas PM concentration exiting the stack will still be very dilute. The selected PM BACT is the use of low sulfur pipeline natural gas and good combustion practices such that PM emissions will be limited to 0.0095 lb PM/MMBtu (annual-average basis). Good combustion practices include proper GT/duct burner design, performing recommended maintenance, and proper operation of the system to promote efficient combustion.
(5)	Sulfuric Acid Mist (SAM) BACT Analysis
Emissions of SO2 occur from the oxidation of sulfur in the gaseous fuel fired in the GT/duct burner system. Most fuel sulfur is converted to SO2. A portion of the SO2 will be further converted to H2SO4, also referred to as (SAM), which will exit from the main stack.
Step 1: Identify Available Control Technologies
The two available control technologies to control SAM emissions include:
• Wet scrubbing of SAM, and
• Use of clean burning, low sulfur natural gas fuel.
Step 2: Eliminate Technically Infeasible Options
Because the sulfur content in pipeline natural gas is extremely low, the SAM concentration in the flue gas will be very dilute. For this reason, wet scrubbing of SAM emissions is technically infeasible and is eliminated from BACT consideration. Additionally, wet scrubbing would have the negative impact of generating an additional wastewater stream.
Step 3: Rank Remaining Options by Control Effectiveness
The only available and technically feasible SAM control technology is the use of clean-burning, low sulfur natural gas fuel.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top control technology.
Step 5: Select BACT
The proposed BACT for SAM emissions includes minimizing the formation of SO2 and H2SO4 by using pipeline-quality natural gas with sulfur content not exceeding 1.0 grains S/100 scf on a short-term basis, and not exceeding 0.5 grains S/100 scf on an annual-average basis. Additionally, by employing a highly efficient combined cycle power generation system, the quantity of natural gas fuel required per unit of power output is minimized to the extent reasonably possible.
(6)	Greenhouse gas (GHG) BACT Analysis
For the GT/duct burner system, GHG emissions will be released from the main stack in the form of CO2, methane (CH4) and nitrous oxide (N2O). The primary GHG is CO2, and the combined GHGs are expressed as CO2 equivalents (CO2e) using the procedure in the federal GHG reporting rule found at 40 CFR 98.
Important Note: Since this GT/duct burner GHG BACT demonstration was originally submitted to MDEQ on April 9, 2024, EPA promulgated a new NSPS GHG regulation which impacts this installation. In the May 9, 2024, Federal Register, EPA published 40 CFR 60 Subpart TTTTa (NSPS TTTTa), which establishes GHG standards for Stationary Combustion Turbine Electric Generating Units built after May 23, 2023. NSPS TTTTa implements a phased-in GHG control approach. The new regulation focuses only on CO2 emissions and not any other GHG constituents. EPA’s reason for phasing in GHG limits for this source category was that some of the necessary GHG control technologies are not currently commercially available. For Entergy’s proposed new base load GT/duct burner facility, the applicable phased-in CO2 emission limits from Table 1 of NSPS TTTTa include:
• From the start of operation until December 31, 2031, a CO2 emissions performance level of less than 800 lb CO2/MWh gross energy output (12-operating month average).
• For all operations after December 31, 2032, a CO2 emissions performance level of less than 100 lb CO2/MWh of gross energy output (12-operating month average).
These NSPS TTTTa requirements replace and supersede the requirements of NSPS TTTT described in the original PSD application provided for this proposed installation.
Step 1: Identify Available Control Technologies
The available control technologies to lower GHG emissions from GT/duct burner installations include:
• Carbon Capture and Sequestration (CCS);
• Combustion of fuel containing hydrogen; and
• Operating a system that has a high thermal efficiency with relatively low-carbon natural gas fuel.
Research has been performed by the U.S. Department of Energy and others to limit GHG emissions from combined cycle units by employing CCS. In a CCS system, CO2 emissions are captured, scrubbed, condensed, and routed via pipeline to an underground formation where the CO2 is stored indefinitely (sequestered). Currently, CCS is not readily available in a commercial sense for a combined cycle system being proposed by Entergy. Once the CO2 is separated from the flue gases, it must be transported to a suitable sequestration or storage facility. Storage opportunities typically would include disposing of the CO2 in a Class 2 well used for enhanced oil recovery or disposing of the CO2 in a Class 6 well which is used to inject CO2 into deep rock formations, as part of a process called Geologic Sequestration. Using CO2 for Enhanced Oil Recovery is unstable because the demand for the CO2 fluctuates significantly depending on the price of oil and natural gas. It should be noted that the Sawgrass combined cycle system is being designed such that a CCS retrofit could be accommodated in the future. For these reasons, CCS is rejected as GHG BACT for this installation. However, Entergy will consider CCS when planning for operation of the facility to meet the NSPS TTTTa CO2 emission limit that becomes effective on January 1, 2032.
The use of hydrogen as a fuel reduces CO2 emissions because the product of hydrogen combustion is water. Studies by GT manufacturers indicate that with current GT technology, the quantity of hydrogen fuel a GT can accommodate is approximately 30%. The remaining balance of the fuel fired must be natural gas. At the time the proposed GT/duct burner installation commences operation, the infrastructure to even partially fire hydrogen fuel is not readily available (e.g., there is no hydrogen pipeline near the site to obtain hydrogen fuel). For this reason, hydrogen combustion is rejected as GHG BACT for this installation. However, Entergy will consider hydrogen combustion when planning for operation of the facility to meet the NSPS TTTTa CO2 emission limit that becomes effective on January 1, 2032.
Step 2: Eliminate Technically Infeasible Options
All of the control options identified in Step 1 are technically feasible. As described above, at the time of the application and hydrogen combustion is not currently available as a GHG control options because of infrastructure limitations (see Step 1). However, these options may be available by the 2032 timeframe. The only remaining GHG control options are CCS and building and operating a system that has a high thermal efficiency while burning a relatively low-carbon natural gas fuel.
Step 3: Rank Remaining Options by Control Effectiveness
CCS is the top technically feasible control technology. The remaining option is building and operating a system that has a high thermal efficiency while firing a relatively low-carbon natural gas fuel.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
Currently, the initial costs of installing a CCS system are estimated at nearly $1.3 billion. For this reason, CCS is considered economically infeasible.
Step 5: Select BACT
The remaining option for GHG BACT is to employ a GT/duct burner combined cycle system with a high thermal efficiency that is fired by relatively low-carbon natural gas fuel. This is consistent with recent BACT determinations for combined cycle systems presented in USEPA’s RBLC database as shown in Appendix C. The minimum acceptable GHG BACT limit of 800 lb CO2/MWh gross power output is established by 40 CFR 60 Subpart TTTTa. This NSPS TTTTa CO2 limit will represent GHG BACT for this installation. This selection will place Sawgrass in the group of the top performing combined cycle units identified in USEPA’s RBLC database presented in Appendix C. Based on this, the proposed GHG BACT for the GT/duct burner system is use of natural gas fuel with efficient power generation system with a GHG performance level of 800 lb CO2e/MWh of gross power output.

B.	Diesel-fired Emergency Internal Combustion Engines
The DBAPS proposes to have two emergency diesel-fired IC engines. The engines will be limited to 100 hr/yr of operation or less in non-emergency operating modes due to the engines’ emergency classification status. One emergency diesel-fired IC engine powers a 2,180 kW emergency standby generator (DBAPS-EMGEN). The engine is a Mitsubishi Model S16R-Y2PTAW2-1 with a 2,923 BHP rating. The other emergency diesel-fired IC engine powers a 235 kW emergency fire water pump (DBAPS-FWP). The engine is a John Deere Model 6068HFC48A with a 282 BHP rating. As required by regulation, the engines will only fire ULSD with a maximum sulfur content of 15 ppmw. The emergency standby generator is a USEPA-certified Tier 2 engine, and the emergency fire water pump is a USEPA-certified Tier 3 engine. Both are approved by regulation for emergency service operations.
(1)	Nitrogen Oxides (NOX) BACT Analysis
Step 1: Identify Available Control Technologies
The control technologies that are available for emergency diesel-fired IC engines include:
• Selective Catalytic Reduction (SCR);
• Selective Non-Catalytic Reduction (SNCR); and
• Use of an IC engine that is certified to meet the applicable NOx emission limits in 40 CFR 60 Subpart IIII, the NSPS for Compression Ignition IC engines (NSPS IIII).
Step 2: Eliminate Technically Infeasible Options
Add-on NOx controls, such as SCR and/or SNCR systems are not technically feasible for emergency engines. Because of the infrequent operation, it is very difficult operate add-on NOx control systems for short periods of emergency operation. Total annual NOx emissions from the two engines combined are very small and can be found in Tables A-8 and A-9 in Appendix A. Because of this, add-on NOx controls are rejected as NOx for the two emergency engines.
Step 3: Rank Remaining Options by Control Effectiveness
The only available and technically feasible NOx control technology is use of an IC engine that is certified to comply with the applicable NOx emission limits in NSPS IIII. This becomes the top option.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top control technology.
Step 5: Select BACT
The proposed NOx BACT for the emergency engines is a Tier 2 or Tier 3 engine NOx performance level specified in NSPS IIII. This corresponds to the NOx limit for emergency service engines in 40 CFR 60 Subpart IIII, the NSPS for Compression Ignition Internal Combustion Engines. Both engines will be subject to and will comply with all applicable NSPS Subpart IIII NOx requirements for engines that maintain an emergency classification. For the diesel-fired Emergency Standby Generator, NOx BACT is proposed as the Tier 2 NOx performance level of 5.36 g NOx/kWh for engines of this power rating. For the diesel-fired Emergency Fire Water Pump (DBAPS-FWP) NOx BACT is proposed as the Tier 3 NOx performance level of 3.31 g NOx/kWh for engines of this power rating.
(2)	Carbon Monoxide (CO) BACT Analysis
Step 1: Identify Available Control Technologies
The CO control technologies that are available include:
• Catalytic oxidation of CO and
• Good combustion practices using an IC engine that is certified to meet NSPS Subpart IIII CO emission limits.
Step 2: Eliminate Technically Infeasible Options
Both options identified above are technically feasible.
Step 3: Rank Remaining Options by Control Effectiveness
Catalytic oxidation provides the best control effectiveness, followed by use of an engine certified to meet applicable NSPS IIII CO emission limits.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
Although an add-on catalytic control system is technically feasible for the two subject emergency engines, the cost of controlling CO for this application is economically prohibitive. Total annual CO emissions from the two engines combined are very small and can be found in Tables A-8 and A-9 in Appendix A of the PSD application. This is due to engine operations being limited to 100 hr/yr/engine. For both engines, as shown in the control equipment cost calculations presented in Appendix D of the PSD application, the annualized cost for controlling CO emissions using a catalytic oxidizer exceeds $100,000 per ton of CO controlled. For this reason, catalytic oxidation is rejected as BACT for CO.
Step 5: Select BACT
The proposed CO BACT for the emergency engines is a manufacturer performance guarantee CO performance level using engines certified to meet NSPS IIII CO emission limits. Both engines will be subject to and will comply with all applicable NSPS Subpart IIII CO requirements for engines that maintain an emergency classification. For the diesel-fired Emergency Standby Generator, CO BACT is proposed as a manufacturer guarantee of 0.60g CO/kWh which is more stringent than the Tier 2 CO performance level of 3.5 g CO/kWh for engines of this power rating. For the diesel-fired Emergency Fire Water Pump, CO BACT is proposed as a manufacturer guarantee of 0.60 g CO/kWh which is more stringent than the Tier 3 CO performance level of 3.5 g CO/kWh for engines of this power rating.
(3)	Volatile Organic Compounds (VOC) BACT Analysis
Step 1: Identify Available Control Technologies
The VOC control technologies that are available include:
• Catalytic oxidation of VOC and
• Good combustion practices using an IC engine that is certified to meet NSPS Subpart IIII VOC emission limits.
Step 2: Eliminate Technically Infeasible Options
Both options identified above are technically feasible.
Step 3: Rank Remaining Options by Control Effectiveness
Catalytic oxidation provides the best control effectiveness, followed by use of an engine certified to meet applicable NSPS IIII VOC emission limits.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
Although an add-on catalytic control system is technically feasible for the two subject emergency engines, the cost of controlling VOC for this application is economically prohibitive. Total annual VOC emissions from the two engines combined are very small and can be found in Tables A-8 and A-9 in Appendix A of the PSD application. This is due to engine operations being limited to 100 hr/yr/engine. For both engines, as shown in the control equipment cost calculations presented in Appendix D of the PSD application, the annualized cost for controlling VOC emissions using a catalytic oxidizer exceeds $100,000 per ton of VOC controlled. For this reason, catalytic oxidation is rejected as BACT for VOC.
Step 5: Select BACT
The proposed VOC BACT for the emergency engines is the use of Tier 2 or Tier 3-compliant engines with manufacturer guaranteed performance levels which are more stringent than the NSPS Subpart IIII requirements. Both engines will be subject to and will comply with all applicable NSPS Subpart IIII requirements for engines that maintain an emergency classification. For the diesel-fired Emergency Standby Generator, VOC BACT is proposed as the manufacturer’s guaranteed VOC performance level of 0.56 g VOC/kWh. For the diesel-fired Emergency Fire Water Pump VOC BACT is proposed as the manufacturer’s VOC performance level of 0.11 g VOC/kWh.
(4)	Particulate Matter (PM10 and PM2.5) BACT Analysis
Step 1: Identify Available Control Technologies
The control technologies that can potentially be used to control PM emissions include:
• Fabric Filter (Baghouse);
• Electrostatic Precipitator (ESP); and
• Good combustion practices using an IC engine that is certified to meet NSPS Subpart IIII PM emission limits.
Step 2: Eliminate Technically Infeasible Options
Because operation of the two engines are so infrequent (< 100 hr/yr) and the PM concentration in the engine flue gas is so dilute, it is technically infeasible to use PM add-on control equipment such as a fabric filter or ESP.
Step 3: Rank Remaining Options by Control Effectiveness
The only remaining option is employing good combustion practices using an IC engine that is certified to meet NSPS Subpart IIII PM emission limits. This becomes the top technology.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top  technically feasible control technology.
Step 5: Select BACT
The proposed PM BACT for the emergency engines is a Tier 2 or Tier 3 engine PM performance level using engines certified to meet NSPS IIII. This corresponds to the PM limit for emergency engines in 40 CFR 60 Subpart IIII, the NSPS for Compression Ignition Internal Combustion Engines. Both engines will be subject to and will comply with all applicable NSPS Subpart IIII PM requirements for engines that maintain an emergency classification. For the diesel-fired Emergency Standby Generator PM BACT is proposed as the Tier 2 PM performance level of 0.173 g PM/kWh for engines of this power rating. For the diesel-fired Emergency Fire Water Pump PM BACT is proposed as the Tier 3 PM performance level of 0.10 g PM/kWh for engines of this power rating.
(5)	Greenhouse Gas (GHG) BACT Analysis
Step 1: Identify Available Control Technologies
The GHG control technologies considered this case include:
• Carbon Capture and Sequestration (CCS) and
• Good combustion practices and the use of engines that are certified to meet NSPS IIII emission limits, and the complying with NSPS IIII work practice requirements.
There are no known CCS applications commercially available for emergency diesel-fired IC engines. Therefore, CCS is rejected as BACT.
Step 2: Eliminate Technically Infeasible Options
The use of CCS is neither available nor technically feasible. This leaves the only remaining option, which is employing good combustion practices and using engines that are certified to meet NSPS IIII emission requirements.
Step 3: Rank Remaining Options by Control Effectiveness
The only remaining option is the top technically feasible technology. This requires employing good combustion practices and the use of engines that are certified to meet NSPS IIII emission requirements.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top technically feasible control technology.
Step 5: Select BACT
Total GHG emissions for these two engines is calculated in Table A-25 of Appendix A. The proposed GHG BACT for both engines is the use of efficient NSPS IIII-compliant USEPA-certified Tier 2 and Tier 3 engines with a GHG emissions performance levels specified in Tables C-1 and C-2 of 40 CFR Part 98, the mandatory GHG reporting rule as shown in Table A-25 of Appendix A.
C.	Natural Gas Dewpoint Heater
To prevent liquid water droplets from entering the GT and to enhance thermal efficiency, the natural gas fuel to the GT is indirectly heated in a small natural gas-fired dewpoint heater that has a rated firing rate of 3.63 MMBtu/hr-HHV. The dewpoint heater will be permitted to operate continuously (8,760 hr/yr).
(1)	Nitrogen Oxides (NOX) BACT Analysis
Step 1: Identify Available Control Technologies
The NOx control technologies that are available for this small gas-fired heater include:
• Selective Catalytic Reduction (SCR);
• Selective Non-Catalytic Reduction (SNCR); and
• Use of Ultra-Low NOx Burners
Step 2: Eliminate Technically Infeasible Options
The use of add-on NOx controls such as SCR or SNCR is not technically feasible for this small heater. SCR and SNCR are control technology typically used on heaters with ratings greater than 100 MWh with this heater having a rating of 1.06 MWh. The use of add-on NOx controls for this application is therefore rejected as BACT.
Step 3: Rank Remaining Options by Control Effectiveness
The only available and technically feasible NOx control technology for this heater is the use of ULNBs with a manufacturer’s guaranteed NOx performance level of 0.011 lb NOx/MMBtu. This becomes the top technology.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the technically feasible top control technology.
Step 5: Select BACT
NOx emissions from this small heater can be found in Table A-10 of Appendix A of the PSD application. NOx BACT for this heater is proposed to be the use of ultra-low NOx burner technology with a manufacturer’s guaranteed NOx performance level of 0.011 lb NOx/MMBtu.
(2)	Carbon Monoxide (CO) BACT Analysis
Step 1: Identify Available Control Technologies
The CO control technologies that are available for this small gas-fired heater include:
• Oxidation catalysts and
• Employing good combustion techniques with a manufacturer’s guaranteed CO performance level.
Step 2: Eliminate Technically Infeasible Options
The use of add-on CO controls such as an Oxidation Catalyst Unit is not technically feasible for this small heater. Oxidation catalysts are usually used on heaters with a rating greater than 100 MWh with this heater having a rating of 1.06 MWh. The use of add-on CO controls for this application is therefore rejected as BACT.
Step 3: Rank Remaining Options by Control Effectiveness
The only available and technically feasible CO control technology remaining for this heater is employing good combustion techniques with a manufacturer’s guaranteed burner CO performance level of 0.037 lb CO/MMBtu. This becomes the top technology.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the technically feasible top control technology.
Step 5: Select BACT
CO emissions from this small heater can be found in Table A-10 of Appendix A. CO BACT for this heater is proposed to be the use of good combustion practices to achieve a manufacturer’s guaranteed CO performance level of 0.037 lb CO/MMBtu.
(3)	Volatile Organic Compounds (VOC) BACT Analysis
Step 1: Identify Available Control Technologies
The VOC control technologies that are available for this small gas-fired heater include:
• Oxidation catalysts; and
• Employing good combustion techniques with a manufacturer’s guaranteed VOC performance level.
Step 2: Eliminate Technically Infeasible Options
The use of add-on VOC controls such as an Oxidation Catalyst Unit is not technically feasible for this small heater. The use of add-on VOC controls for this application is therefore rejected as BACT.
Step 3: Rank Remaining Options by Control Effectiveness
The only available and technically feasible VOC control technology remaining for this heater is employing good combustion techniques with a manufacturer’s guaranteed burner VOC performance level of 0.008 lb VOC/MMBtu. This becomes the top technology.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the technically feasible top control technology.
Step 5: Select BACT
VOC emissions from this small heater can be found in Table A-10 of Appendix A of the PSD application. The use of add-on VOC controls such as an oxidation catalyst system is not technically feasible for this small heater. VOC BACT for this heater is proposed to be the use of good combustion practices to achieve a manufacturer’s guaranteed VOC performance level of 0.008 lb VOC/MMBtu.
(4)	Particulate Matter (PM10 and PM2.5) BACT Analysis
Step 1: Identify Available Control Technologies
The control technologies that can potentially be used to control PM10/PM2.5 (PM) emissions from this very small heater include:
• Fabric Filter (Baghouse);
• Electrostatic Precipitator (ESP); and
• Good combustion practices using clean low-sulfur pipeline natural gas as a fuel with a burner manufacturer’s guarantee to have low PM emissions.
Step 2: Eliminate Technically Infeasible Options
Because the heater is very small and the PM concentration in the heater flue gas is so dilute, it is technically infeasible to use PM add-on control equipment such as a fabric filter or ESP. Further, there are no known commercial applications of add-on PM controls for natural gas fired heaters, so this control option is also not “available”.
Step 3: Rank Remaining Options by Control Effectiveness
The only remaining option is employing good combustion practices and by using clean natural gas as a fuel and with a burner manufacturer’s guarantee to have low PM emissions. This becomes the top technology.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the  technically feasible top control technology.
Step 5: Select BACT
PM10/PM2.5 emissions from this small natural gas-fired heater can be found in Table A-10 of Appendix A of the PSD application. PM10/PM2.5 BACT for this heater is proposed to be the use of low sulfur pipeline natural gas and good combustion practices to achieve a manufacturer’s guaranteed PM performance level of 0.0048 lb PM/MMBtu.
(5)	Greenhouse Gas (GHG) BACT Analysis
Step 1: Identify Available Control Technologies
The GHG control technologies that are considered in this case include:
• Carbon Capture and Sequestration (CCS) and
• Good combustion practices use a thermally efficient heater that is fired by relatively low-carbon emitting natural gas fuel.
There are no known CCS applications commercially available for small natural gas-fired heaters. Therefore, CCS is rejected as BACT for this application.
Step 2: Eliminate Technically Infeasible Options
The use of CCS is neither available nor technically feasible for this application. This leaves the only remaining option, which is employing good combustion practices with a thermally efficient heater that is fired by relatively low-carbon emitting natural gas fuel.
Step 3: Rank Remaining Options by Control Effectiveness
The only remaining option is the top technology for this application. This requires employing good combustion practices with a thermally efficient heater that is fired by relatively low-carbon emitting natural gas fuel.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the technically feasible  top control technology.
Step 5: Select BACT
Total GHG emissions for this small heater can be found in Table A-23 of Appendix A. It is not technically feasible to use CCS technology in this application. The proposed GHG BACT for this small heater is the use of clean burning and efficient pipeline natural gas fuel and the employment of good combustion practices with GHG emissions performance levels specified in Tables C-1 and C-2 of 40 CFR 98, the mandatory GHG reporting rule (see Table A-23 of Appendix A).
D.	Storage Tanks
The DBAPS proposes to have two horizontal fixed-roof diesel storage tanks. Each tank is dedicated to providing ULSD fuel to the two emergency IC engines. The tank that will supply ULSD to the emergency generator will be a 99 bbl (4,150 gal) white, horizontal fixed-roof tank. The tank that will supply ULSD to the emergency fire water pump will be a 12 bbl (500 gal) white, horizontal fixed-roof tank.
(1)	Volatile Organic Compounds (VOC) BACT Analysis
Step 1: Identify Available Control Technologies
The VOC control technologies that are considered in this case include:
• Use of pressurized storage tanks;
• Use of an internal floating roof tank;
• Use of an external floating roof tank;
• Use of a fixed roof tank with the tank vent routed to and add-on VOC control device; and
• Use of a fixed roof tank with a submerged fill pipe and an atmospheric vent.
ULSD has a very low vapor pressure of 0.014 psia at storage conditions. As a result, the combined annual VOC emission from these two tanks will be very small. Due to the size of the proposed fixed roof tanks, the fixed roof will control fugitive emissions at a similar rate to the other tanks listed above, while being much more mechanically simple. As such, fixed roof tanks with a submerged fill pipe and an atmospheric vent are the industry standard for tanks of this size storing liquids with very low vapor pressures. The proposed BACT for these two tanks is the use of white horizontal fixed-roof storage vessels with a submerged fill pipe and an atmospheric vent.
Step 2: Eliminate Technically Infeasible Options
The best available control technology for ULSD storage is use of a fixed roof tank with a submerged fill pipe and an atmospheric vent.
Step 3: Rank Remaining Options by Control Effectiveness
The best available control technology for ULSD storage is use of a fixed roof tank with a submerged fill pipe and an atmospheric vent.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top control technology.
Step 5: Select BACT
Because ULSD has a very low vapor pressure of 0.014 psia at storage conditions, the combined annual VOC emission from these two small tanks combined will be very low. Therefore, the proposed BACT for these two tanks is the use of white horizontal fixed-roof storage vessels with a submerged fill pipe and an atmospheric vent.
E.	Lube Oil System Vents
The new combustion turbine and new steam turbine will each be equipped with a dedicated lubrication system. Lubrication oil will be circulated through each turbine’s machinery from the systems’ oil sumps. The oil sumps will be equipped with a vent that will be controlled by an oil mist eliminator. Emissions from the oil mist eliminators are based on lube oil replacement rates for similar units equipped with mist eliminators. Both VOCs and PM are expected to be emitted from for the combustion turbine lube oil vent and the steam turbine lube oil vent. The lube oil vent will be permitted to operate continuously (8,760 hr/yr).
(1)	Volatile Organic Compounds (VOC) BACT Analysis
Step 1: Identify Available Control Technologies
The VOC control technologies that are considered in this case include:
• Atmospheric vent with a built-in mist eliminator and
• Atmospheric vent with no controls.
Step 2: Eliminate Technically Infeasible Options
Both options identified above are technically feasible.
Step 3: Rank Remaining Options by Control Effectiveness
The vent with a built-in mist eliminator represents the highest level of control. This becomes the top option.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top control technology.
Step 5: Select BACT
The combined VOC emissions from both lube oil vents can be found in Table A-15 in Appendix A. Use of a mist eliminator is the only feasible VOC control technology for these small VOC sources. Therefore, use of a mist eliminator is proposed as VOC BACT for the two lube oil vents 
(2)	Particulate Matter (PM10 and PM2.5) BACT Analysis
Step 1: Identify Available Control Technologies
The PM control technologies that are considered in this case include:
• Atmospheric vent with a built-in mist eliminator and
• Atmospheric vent with no controls.
Step 2: Eliminate Technically Infeasible Options
Both options identified above are technically feasible.
Step 3: Rank Remaining Options by Control Effectiveness
The vent with a built-in mist eliminator represents the highest level of control. This becomes the top option.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
No evaluations of cost or other impacts are required because Entergy is proposing to accept the top control technology.
Step 5: Select BACT
The combined PM emissions from both lube oil vents can be found in Table A-15 in Appendix A. Use of a mist eliminator is the only feasible PM control technology for these small PM sources. Therefore, use of a mist eliminator is proposed as PM10/PM2.5 BACT for the two lube oil vents. 
F.	Fugitive Emissions
The proposed equipment at SPS has the potential to leak VOC and GHG from equipment components. These components include valves, flanges and connectors, pumps, etc. For the natural gas fugitives (Emission Point AA-005), the VOC composition of the natural gas is only 1.58 wt%. The total annual fugitive VOC emissions from this source can be found in Table A-12 in Appendix A of the PSD application. Methane in natural gas is a GHG. Fugitive GHG emissions for AA-005 represents 0.01% of the facility-wide GHG annual emission rate. The GHG emissions for AA-005 can be found in Table A-24 of Appendix A of the PSD application and the facility-wide GHG annual emission rate can be found in Table A-21 of Appendix A of the PSD application. For the diesel fugitives (Emission Point AA-007), annual fugitive VOC emissions is low due to the limited number of components in diesel service and that diesel is a low-emitting heavy liquid. The emissions from this source can be found in Table A-14 in Appendix A of the PSD application. There currently are no NSPS or NESHAP regulations which require a Leak Detection and Repair (LDAR) program for the fugitive sources (Emission Points AA-005and AA-007). If an LDAR program were implemented at Sawgrass, it would monitor both VOC and GHG (methane) emissions.
(1)	Volatile Organic Compounds (VOC) BACT Analysis
Step 1: Identify Available Control Technologies
The available VOC control technologies for fugitive VOC emissions include:
• Implementing a traditional Leak Detection and Repair (LDAR) program using a portable hydrocarbon monitor and
• Implementing an Audio-Visual-Olfactory (AVO) LDAR program.
Step 2: Eliminate Technically Infeasible Options
Both LDAR program options identified above are technically feasible.
Step 3: Rank Remaining Options by Control Effectiveness
An LDAR program using a portable hydrocarbon detector is expected to have better control than an AVO LDAR program.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
Implementing a traditional LDAR program using a portable hydrocarbon detector is technically feasible, but for the minor amount of VOC control offered by an LDAR program, the VOC emission reduction achieved would be cost prohibitive. As shown in the BACT cost estimates in Appendix D of the PSD application, the cost for implementing a sitewide VOC LDAR program with a portable hydrocarbon detector would result in a control cost of over $30,000/ton VOC emissions reduced. For this reason, implementing an LDAR program is rejected as VOC BACT. The use of an AVO LDAR program becomes the top available option.
Step 5: Select BACT
Most fugitive VOC is emitted from natural gas components (DBAPS-NGFUG). Because pipeline natural gas is odorized with a small quantity of mercaptan, an Audio-Visual-Olfactory (AVO) program to detect and repair leaks is technically feasible, highly effective and is the top remaining control option. For this reason, an AVO program is proposed for VOC BACT for.
(2)	Greenhouse Gas (GHG) BACT Analysis
Step 1: Identify Available Control Technologies
The primary GHG fugitive pollutant will be methane from equipment in natural gas service. The available methane control technologies for fugitive methane emissions include:
• Implementing a traditional Leak Detection and Repair (LDAR) program using a portable hydrocarbon monitor and
• Implementing an Audio-Visual-Olfactory (AVO) LDAR program.
Step 2: Eliminate Technically Infeasible Options
Both LDAR program options identified above are technically feasible.
Step 3: Rank Remaining Options by Control Effectiveness
An LDAR program using a portable hydrocarbon detector is expected to have better control than an AVO LDAR program.
Step 4: Evaluate Most Effective Controls for Cost, Energy and Other Impacts
An LDAR program that uses a portable hydrocarbon detector is technically feasible, but for the minor amount of GHG control offered by this LDAR program, the GHG emission reduction achieved would be cost prohibitive. As shown in the BACT cost estimates in Appendix D, the cost for implementing a sitewide GHG LDAR program would result in a control cost of over $578/ton CO2e emissions reduced. For this reason, implementing an LDAR program is rejected as GHG BACT. The use of an AVO LDAR program becomes the top available option.
Step 5: Select BACT
Most fugitive methane is emitted from natural gas components (DBAPS-NGFUG). Because
pipeline natural gas is odorized with a small quantity of mercaptan, an Audio-Visual-Olfactory
(AVO) program to detect and repair leaks is technically feasible, highly effective and is the top
remaining control option. For this reason, an AVO program is proposed for GHG BACT for Emission Points AA-005 and AA-007.
V.	Source Impact Analysis
The owner or operator of a proposed source or modification is required to demonstrate that allowable emission increases from the proposed source or modification, in conjunction with all other applicable emissions increases or reductions (including secondary emissions), will not cause or contribute to air pollution in violation of: 1) any national ambient air quality standard in any air quality control region; or 2) any applicable maximum allowable increase over the baseline concentration in any area.
The modeled concentrations used to determine compliance with any NAAQS and PSD increment depend on 1) the type of standard, i.e., deterministic or statistical, 2) the available length of record of meteorological data, and 3) the averaging time of the standard being analyzed.  When the analysis is based on 5 years of National Weather Service meteorological data, the following estimates are used:
•	For deterministically based standards (e.g., SO2), the highest, second-highest short term estimate and the highest annual estimate; and
•	For statistically based standards (e.g., PM10), the highest, sixth-highest estimate and highest 5-year average estimate.
A.	Existing Air Quality
Any application for a permit under the Prevention of Significant Deterioration program is required to contain an analysis of ambient air quality in the area that the major stationary source or major modification would affect for each of the following pollutants: a) for the source, each pollutant that it would have the potential to emit in a significant amount; b) for the modification, each pollutant for which it would result in a significant net emissions increase.

The existing ambient air quality is defined by the natural and human-generated sources of air pollution. The area surrounding the Washington County facility is considered rural and in attainment for all regulated pollutants. The pollutants that result in a significant net emission increase as a result of the proposed project and under consideration in this analysis are NOx, CO, PM, PM10, PM2.5, volatile organic compounds (VOCs), H2SO4. VOCs and nitrogen oxides (NOx) combine in the atmosphere to form ozone and, therefore, are called precursor emissions. Any significant emissions increase from an emission unit or net emissions increase at a major stationary source that is significant for VOC or NOx, which are precursor pollutants for ozone shall be considered significant for ozone (O3). Under current guidance if one precursor for a pollutant exceeds the threshold, then all precursors for that pollutant must be taken into consideration and used in calculations.

MDEQ operates an ambient air quality network throughout the state of Mississippi and report their findings in the “Mississippi Department of Environmental Quality Air Quality Data Summary.” This report looks at the reported levels of the criteria pollutants at various monitoring sites located across the State and compares these levels to the NAAQS to determine how the state is doing in meeting these standards. There is one primary and secondary ozone standard, the 8-hour average.  The level of the 8-hour Ozone standard is 70 ppb. MDEQ monitors ozone continuously from March 1 through October 31 each year at the monitoring sites with the exception for the MDEQ NCORE site located in Jackson, MS which monitors ozone year around.

10  Year Ozone Monitoring Trends All Mississippi Sites

B.	Modeling Procedure
All estimates of ambient concentrations are to be based upon applicable air quality models, databases and other requirements specified in EPA’s Guideline on Air Quality Models in Appendix W of 40 CFR Part 51.

The EPA Memorandums, “Guidance on the Development of Modeled Emission Rates for Precursors (MERPs) as a Tier I Demonstration Tool for Ozone and PM2.5 under the PSD Permitting Program,” dated April 30, 2019, and “Guidance for Ozone and Fine Particulate Matter Permit Modeling” dated July 29, 2022 reflect EPA’s recommendation for how agencies conduct air quality modeling and related technical analyses to satisfy compliance demonstration requirements for ozone and PM2.5 under the PSD Permitting Program. In accordance with the above-mentioned Guidance and the Revisions to the Guideline on Air Quality Models (40 CFR Part 51, Appendix), EPA recommends that an applicant use a “two-tiered” demonstration approach to address single-source impacts on ozone and secondary PM2.5. The first tier involves the use of existing technical information to evaluate the relationships between precursor emissions and a source’s impacts. The second tier involves the application of more sophisticated case-specific chemical transport models (CTMs) (e.g., photochemical grid models).

Using the Tier I Demonstration approach for PSD compliance, the emissions of the individual precursor pollutants are not added together to determine if there is an exceedance but looked at individually. If an exceedance occurs for one individual precursor, the precursor pollutants are compared to the hypothetical source’s modeled emission rate and impacts (MERPs). The EPA provides access to its MERPs values on its MERPs VIEW Qlik website (https://www.epa.gov/scram/merps-view-qlik). If there is an exceedance of an individual precursor, then upon calculating the potential impacts, all precursors of either ozone or PM2.5 are taken into consideration when calculated.

Should the Tier I Demonstration find the critical air quality threshold, or significant impact level (SIL), would not be exceeded when considering the impact of the ozone precursor emissions of VOC and NOx, the proposed project will not cause ozone concentrations exceeding the ozone SIL. No further analysis or modeling will be required.

Ozone
The Tier I Demonstration for Entergy Mississippi, LLC – Delta Blues Advanced Power Station proposed project of constructing new natural gas-fired combined cycle power plant has an anticipated increase of 1.684 ppb. 

These results were obtained by using the EPA’s Smith County hypothetical source (CUS 9) is located within the same airshed as the DBAPS. The majority of project-related NOX, SO2, and VOC emissions exhaust through the 61-meter-tall stack. This height is more similar to the “High” (90-meter) hypothetical source than the “Low” (10-meter) hypothetical source. The “High” Smith County hypothetical source MERP values were used for this analysis. The proposed project includes an (annualized daily) increase of 313 tons per year (tpy) NOX emissions and 56 tpy SO2 emissions. These emissions are closer to the modeled emissions for the EPA’s 500 tpy hypothetical source than the EPA’s 1,000 tpy or 3,000 tpy hypothetical source emission rates. The 500 tpy NOX and SO2 hypothetical source MERP values were used for this analysis. The proposed project includes an (annualized daily) increase 883 tpy VOC emissions. These emissions are closer to the modeled emissions for the EPA’s 1,000 tpy hypothetical source than the EPA’s 500 tpy or 3,000 tpy hypothetical source emission rates. The 1,000 tpy VOC hypothetical source MERP values were used for this analysis. This is not below the SIL threshold of 1.0ppb; therefore, additional modeling or analysis is required.

Model Versions
The American Meteorological Society/Environmental Protection Agency Regulatory Model (AERMOD), Version 23132, was used to perform the dispersion modeling in this AQA. AERMOD is the latest generation of atmospheric dispersion models suitable for industrial sources and is the model preferred by the USEPA for such applications. To facilitate the running of AERMOD, the Providence/ORIS, LLC’s “BEE-Line BEEST for Windows” graphic user interface (Version 12.10) was used. Additionally, AERMET version (22112) and BPIPPRM subroutine (version 04274) were used.

The following model options were used in the application of the AERMOD modeling:
•	Regulatory default option was enabled for all pollutants.
•	Elevated terrain was used for modeling the area around DBAPS.
•	DBAPS sources were modeled at their actual release heights. None of the DBAPS stacks exceed the calculated GEP height or 65 meters, whichever is greater.
•	The NAD83 datum was used for source, structure, and receptor location coordinates.
•	Modeling receptors were placed to a distance that clearly identifies the area of impact.

Receptor Grid Spacing
The receptor coverage utilized for the preliminary impact analyses consisted of the following:
•	1,000-meter spaced receptors to a distance of 30 km from the DBAPS fence line to ensure that (1) the maximum predicted concentration is located, (2) all locations with predicted concentrations greater than the SILs were identified, and (3) that concentration gradients associated with the project related emissions clearly decrease in magnitude outside of the AOIs,
•	500-meter spaced receptors to a distance of 5 km from the DBAPS fence line,
•	100-meter spaced receptors to a distance of 1 km from the DBAPS fence line,
•	25-meter spaced receptors to a distance of 300 meters from any DBAPS fence line and
•	25-meter spaced receptors along the DBAPS fence line.

Meteorological Data
Current MDEQ guidance was followed concerning meteorological data for AERMOD modeling for sources located in Washington County. The MDEQ has created county-specific preprocessed meteorological data sets using AERMET for use in AERMOD air dispersion modeling. Pre-processed meteorological data was obtained from the MDEQ. Washington County is located within the Lower Delta regions of the State. Pre-processed meteorological data consisted of surface data from the Mid Delta Regional Airport meteorological station (KGLH) and upper air data from the Jackson International station. The MDEQ processed the data using AERMET version 22112 and incorporates the AERMINUTE data along with the low wind speed threshold of 0.5 m/s. The most recent five years of representative NWS meteorological data available from the MDEQ on the date of the AQA (2018, 2019, 2020, 2021, and 2022) will be utilized in the NAAQS and PSD increment analyses. The base elevation for the Mid Delta Regional Airport station is 37.7 meters.

The surface characteristics at the DBAPS are similar to those at the Mid Delta Regional Airport. The available surface roughness lengths can vary between 0.001 m to 1.5 meters. The surface roughness at these locations are both at the lower end of this range. Additionally, surface roughness at most airports are lower than non airport locations due to the runway surfaces. 

Additionally, the Mid Delta Regional Airport is the nearest surface station to the DBAPS. Both the surface station and the DBAPS are located in Greenville, Mississippi. The land use immediately surrounding each location is rural in nature. The terrain surrounding each location and the terrain between each location is flat. The meteorology at each location will be similar.

Point Source Stack Parameters

Volume Source Parameters

Modeled Emission Rates

C.	Air Quality Monitoring Requirements
The ambient air quality analysis is required to contain continuous air quality monitoring data. This data is gathered for purposes of determining whether emissions of any pollutant would cause or contribute to a violation of the standard or any maximum allowable increase. The facility must establish existing air quality in the area and air monitoring is required for each criteria pollutant that is proposed to be emitted at or above the de minimis. This requirement can be satisfied by either: 1) establishing a site-specific ambient monitoring network, or 2) using existing ambient monitoring data. If either the predicted modeled impact from an emission increase or the existing ambient concentration is less than the monitoring de minimis concentration, MDEQ has the discretionary authority to exempt an applicant from preconstruction ambient monitoring.  

Preconstruction de Minimus Chart

No de minimis air quality level is provided for ozone. However, any net emissions increase of 100-tpy or more of VOC or NOx (the precursors for ozone formation) make the proposed PSD project required to perform an ambient impact analysis, including the gathering of ambient air quality data. The proposed project has a proposed emissions increase of 882.6 tpy VOC and 313.4 tpy NOx. Since the proposed project VOC emissions does exceed 100 tpy, Delta Blues must establish existing air quality in the facility project area. To meet this requirement, Delta Blues proposes to use an existing air quality monitor as opposed to establishing their own site-specific ambient monitoring network. 

	Ambient Air
Estimates for the current ambient air background concentrations at the proposed project site may be required for two distinct and separate purposes: (1) to demonstrate that the ambient air concentrations of PSD-significant pollutants are currently in compliance with the NAAQS and (2) for use in a full impact NAAQS modeling analysis. Based on draft Preliminary Impact Determination results, background ambient air concentration data may be required for 24-hour PM2.5 and O3. EML proposes to use ambient air quality data from existing air quality monitoring stations to establish representative background concentrations for these contaminants. This facility will be fenced.

Monitor Selection and Justification
Delta Blues proposes using data collected at the following monitoring stations to establish representative background concentrations and for use in the NAAQS compliance demonstrations:
•	PM2.5 – Crossett (Crossett, AR) (EPA ID 05-003-0005)
•	O3 – Cleveland Delta State (Cleveland, MS) (EPA ID 28-011-0002)

The O3 concentration was calculated using data obtained from annual summary tables obtained on the USEPA website. The PM2.5 concentrations were calculated using the daily monitor PM2.5 concentration data records for the Crossett monitor obtained on the USEPA website. The data collected from these monitors meet the EPA requirements for completeness.

There are no PM2.5, or O3 monitors located within Washington County. The proposed O3 monitor is the nearest to the project site. The DBAPS location and the locations near each of the proposed monitors have similar topography. The areas surrounding each location (within several kilometers) are relatively flat.

Ozone is formed through photochemical reactions involving the emission of precursor compounds such as NOX and VOC. These chemical transformations occur in the atmosphere gradually over time. Due to the required formation distances, direct comparison of nearby ozone precursor emissions is not appropriate. The Cleveland Delta State monitoring station is located within the same ozone air shed as the DBAPS.

There are two monitors PM2.5 monitors located near the project site – Cleveland Delta State in Mississippi and Crossett in Arkansas. The emissions from electrical power generating facilities located near each of these monitors was compared with those near the project site. The USEPA’s Power Plants and Neighboring Communities Map website was used to identify power plants within 100 km of each monitoring station and their emissions. This USEPA database does not provide the PM2.5 emissions associated with these power plants. However, the provided NOX and SO2 pollutants are precursors to secondary PM2.5 emissions. This comparison shows that the emissions near the Crossett monitor are greater than those near the Cleveland Delta State monitor. Additionally, SO2 emissions near the Cleveland Delta State are lower than those near the project site. EML believes the Crossett monitor provides conservative and representative estimates for the background PM2.5 concentration at the project site.

D.	PSD Preliminary Analysis Modeling Impacts
In the preliminary analysis, only the significant increase in potential emissions of a pollutant from a proposed new source, or the significant net emission increase of a pollutant from a proposed modification is modeled. A full impact analysis for a particular pollutant is not required when emissions of that pollutant from a proposed source or modification would not increase ambient concentrations by more than prescribed significant ambient impact levels.

In accordance with the Revisions to the Guideline on Air Quality Models (40 CFR Part 51, Appendix W) EPA recommends that an applicant use a “two-tiered” demonstration approach to address single-source impacts on ozone and secondary PM2.5. The first tier involves the use of existing technical information to evaluate the relationships between precursor emissions and a source’s impacts. The second tier involves the application of more sophisticated case-specific chemical transport models (CTMs) (e.g., photochemical grid models). The April 30, 2019, Memorandum, “Guidance on the Development of Modeled Emission Rates for Precursors (MERPs) as a Tier 1 Demonstration Tool for Ozone and PM2.5 under the PSD Permitting Program”, reflected EPA’s recommendations on how to conduct an air quality modeling and related technical analyses to satisfy compliance demonstration requirements for Ozone and Secondary PM2.5 for permit related assessment under the PSD Program.

For ozone, the modeled air quality impact of an increase in precursor emissions from the hypothetical source is expressed in units of ppb or ppm. Consistent with the modeled emissions rates that are input to the air quality model to predict a change in pollutant concentration, MERPs are expressed as an annual emissions rate in tons per year (tpy). 

A Tier 1 approach was used to estimate the secondary PM2.5 and O3 impacts associated with the precursor emissions. The secondary PM2.5 and ozone impacts were estimated using guidance from the EPA’s Development of Modeled Emission Rates for Precursors (MERPs) as a Tier 1 Demonstration Tool for Ozone and PM2.5 under the PSD Permitting Program, December 2, 2016, and Guidance on the Development of Modeled Emission Rates for Precursors (MERPs) as a Tier 1 Demonstration Tool for Ozone and PM2.5 under the PSD Permitting Program, April 30, 2019. MERPs derived using the EPA’s photochemical modeling results for hypothetical sources located in Mississippi were used to estimate the air quality of secondary PM2.5 and ozone impacts associated with project-related emissions of NOX, SO2, and VOCs. These secondary PM2.5 and ozone impacts were included in the preliminary impact determination, full impact NAAQS, and full impact PSD increment consumption analyses.

The USEPA hypothetical source photochemical modeling and the MERP analysis are both based on annual project emission rates. The maximum daily project emissions were converted to ton per year (tpy) values for use in this analysis. The turbine emission contributions are based on one hot startup each day and the remainder of the day at the turbine load scenario with the maximum hourly emission rates (base load operation with maximum duct burner firing at a 10 °F ambient temperature day). This is extremely conservative since most days will not have a hot startup and the load scenario chosen for this analysis has higher emissions than those associated with alternative load scenarios.

The EPA’s Smith County hypothetical source (CUS 9) is located within the same airshed as the DBAPS. The majority of project-related NOX, SO2, and VOC emissions exhaust through the 61- meter-tall stack. This height is more similar to the “High” (90 meter) hypothetical source than the “Low” (10-meter) hypothetical source. The “High” Smith County hypothetical source MERP values were used for this analysis. The proposed project includes an (annualized daily) increase of 313 tons per year (tpy) NOX emissions and 56 tpy SO2 emissions. These emissions are closer to the modeled emissions for the EPA’s 500 tpy hypothetical source than the EPA’s 1,000 tpy or 3,000 tpy hypothetical source emission rates. The 500 tpy NOX and SO2 hypothetical source MERP values were used for this analysis. The proposed project includes an (annualized daily) increase 883 tpy VOC emissions. These emissions are closer to the modeled emissions for the EPA’s 1,000 tpy hypothetical source than the EPA’s 500 tpy or 3,000 tpy hypothetical source emission rates. The 1,000 tpy VOC hypothetical source MERP values were used for this analysis.

Tier 1 Demonstration for Ozone

VOC MERP Calculation:

 

NOx MERP Calculation:

The recommended ozone SIL of 1-ppb was chosen to represent the critical air quality threshold. The SIL represents a de-minimis impact level, that is, if the maximum concentration of ozone due to a single source is less than the SIL, then it can be concluded that the source has an insignificant contribution to ozone formation. The hypothetical source’s modeled emission rate and impacts along with the ozone SIL were used to calculate the MERPs values below:

The modeled Air Quality Impact is not below the Ozone significant impact level. The proposed project will cause ozone concentrations exceeding the recommended significant impact level for ozone. Further analysis is required.

PM2.5 Secondary Impact Assessment

PM2.5 24-Hour
SO2 MERP Calculation:

NOx MERP Calculation:

 

The modeled Air Quality Impact is not below the 24-hour PM2.5 significant impact level of 1.2 ug/m3. Further analysis is required.

PM2.5 Annual
SO2 MERP Calculation:

NOx MERP Calculation:

This value is below the SIL of 0.13 ug/m3. Therefore no further analysis is required.
PM2.5 At and Past 50+ km

PM2.5 24-Hour
SO2 MERP Calculation:

NOx MERP Calculation:

 

This value is below the SIL of 0.27 ug/m3. Therefore no further analysis is required.

PM2.5 Annual
SO2 MERP Calculation:

NOx MERP Calculation:

This value is below the SIL of 0.03 ug/m3. Therefore no further analysis is required.

Increment Consumption
PSD increment consumption limits currently exist for NO2, SO2, PM10, and PM2.5. Compliance with the PSD increment consumption limits must be demonstrated for sources with PSD significant emissions.

A preliminary impacts determination was first conducted using project-related emissions to determine if a detailed PSD increment consumption analysis is required. A full impact analysis was then performed for applicable NO2, PM10, and PM2.5 emissions for comparison to the PSD increment consumption limits. This analysis will include PSD increment-consuming emissions from sitewide DBAPS sources and from PSD increment-consuming emission sources affecting the project’s impact area. The full impact modeling analysis utilized receptor grids following the MDEQ guidelines. Only receptors with predicted concentrations equal to or greater than the SIL in the preliminary modeling analysis were used.

A preliminary impact determination is conducted to determine if the predicted off property concentrations associated with the proposed increase in PSD-significant emissions are greater than the EPA’s SILs. No further modeling is required to demonstrate compliance if the maximum predicted concentration is below the SIL. 

If the maximum predicted concentration is equal to or greater than the SIL, all on site sources must be included in a full impact modeling analysis. Contributions from off-site sources that may impact the AOI are accounted for using ambient air monitoring data or by direct inclusion in the full impact modeling analysis. The AOI is defined as all locations with predicted concentrations that are equal to or greater than the established SILs. An ambient background concentration is added to the full impact modeling results to complete the NAAQS demonstration.

Preliminary impact determination modeling was conducted for PSD-significant emissions of NOX, CO, PM10, and PM2.5 to determine whether a full impact modeling analysis is required for each pollutant and averaging period. The modeling results were used to determine whether the predicted concentrations are greater than the SIL for each pollutant and averaging period. The estimated ozone impacts obtained using the MERP analysis was used to determine whether a full impact modeling analysis is required for this pollutant. The MERP results were used to determine whether the project-related impacts are greater than the SIL.

The predicted NO2, CO, PM10, and PM2.5 NAAQS concentrations are less than their respective SILs. Additionally, the annual PM2.5 increment concentration is less than the SIL. No additional modeling is required for these pollutants and averaging periods. The predicted 24-hour PM2.5 increment and 8-Hour O3 concentrations are greater than their respective SILs. Therefore, full impact modeling analysis is required for these pollutants and averaging periods.
E.	PSD Full Impact Analysis Modeling Impacts
A full impact analysis is required for any pollutant for which the proposed source’s estimated ambient pollutant concentrations exceed prescribed significant ambient impact levels. This analysis expands the preliminary analysis in that it considers emissions from: the proposed source; existing sources; residential, commercial, and industrial growth that accompanies the new activity and the new source or modification.  For SO2, PM10, PM2.5 and NO2, the full impact analysis consists of separate analyses for the NAAQS and PSD increments.
The impact area is a circular area with a radius extending from the source to (1) the most distant point where approved dispersion modeling predicts a significant ambient impact will occur, or (2) a modeling receptor distance of 50 km, whichever is less.
Minor Source Baseline
Minor Source Baseline Date means the earliest date after the trigger date on which a new major stationary source or a major modification to an existing source subject to PSD submits a complete application. The minor source baseline date is pollutant and geographically specific. The trigger date for PM2.5 is October 20, 2011. Delta Blues establishes the minor source baseline date in Washington County for PM2.5.
1)	NAAQS
The NAAQS are maximum concentration “ceilings” measured in terms of the total concentration of a pollutant in the atmosphere.  For a new or modified source, compliance with any NAAQS is based upon the total estimated air quality, which is the sum of the ambient estimates resulting from existing sources of air pollution and the modeled ambient impact caused by the applicant’s proposed emissions increase and associated growth. The applicant is required, at a minimum, to explicitly model all nearby sources as part of the NAAQS analysis.  The modeling guideline defines a “nearby” source as any point source expected to cause a significant concentration gradient in the vicinity of the proposed new source or modification.  For PSD purposes, “vicinity” is defined as the impact area.  The location of such nearby sources could be anywhere within the impact area or an annular area extending 50 kilometers beyond the impact area.
Based on the results of the draft preliminary impact determination, full impact NAAQS modeling analyses are expected to be required for 8-hour O3. The form of the predicted ground-level concentrations from the NAAQS modeling, the form of the background concentrations, and the NAAQS for all applicable criteria pollutants are summarized in Table 12-6. The predicted ground-level concentrations from the NAAQS modeling, the background concentrations for the project area, and the sum of the two values will be summarized in Table 12-7. The total impacts are compared to the NAAQS.

Ozone NAAQS Cumulative Analysis

The air quality level is less than the NAAQS, therefore no NAAQS violation is found, and the facility does not cause or contribute to a violation. 

PM2.5 NAAQS
24-hour:

This value is below the SIL of 1.2 ug/m3. Therefore no further analysis is required.
Annual: 

This value is below the SIL of 0.13 ug/m3. Therefore no further analysis is required.
2)	PSD Class II Increment 
A PSD increment is the maximum allowable increase in concentration that is allowed to occur above a baseline concentration for a pollutant.  The baseline concentration is defined for each pollutant and, in general, is the ambient concentration existing at the time that the first complete PSD permit application affecting the area is submitted. Emissions increases that consume a portion of the applicable increment are, in general, all those not accounted for in the baseline concentration and specifically include:
•	Actual emissions increases occurring after the major source baseline date, which are associated with physical changes or changes in the method of operation at a major stationary source; and
•	Actual emissions increase at any stationary source, area source, or mobile source occurring after the minor source baseline date.
Based on the results of the preliminary impact determination, a PSD increment consumption modeling analyses is required for 24-hour PM2.5. Modeling runs numbered 1041 through 1045 represents the full impact PSD Increment modeling conducted for this pollutant. The predicted ground-level concentrations and PSD increment consumption limits are summarized in Table12-8. 

Tables from 12.1.1  

The PM2.5 24-hour Increment Results show that the Maximum Predicted Concentration of 1.192 ug/m3 is less that the PSD Increment of 9 ug/m3. This shows that there is no violation, and no further analysis is needed.

F.	Vegetation and Soils Impact
VOCs are regulated as precursors to tropospheric ozone.  Elevated ground-level ozone concentrations can damage plant life and crop production. VOCs interfere with the ability of plants to produce and store food, making them more susceptible to disease, insects, or other pollutants and harsh weather.  Ozone is formed by the interaction of NOx, VOCs, and sunlight in the atmosphere. The effect of a proposed project’s emissions on local soils and vegetation is often addressed through comparison of modeled impacts to the secondary NAAQS. The secondary NAAQS were established to protect general public welfare and the environment. Impacts below the secondary NAAQS are assumed to indicate a lack of adverse impacts on soils and vegetation.

The emissions from the proposed modification will not significantly affect any soils or vegetation within the area (i.e., the modeling domain). There are no predicted exceedances of the Primary or Secondary NAAQS due to the proposed emissions. Primary NAAQS set limits to protect public health, with an adequate margin of safety. “Public health” is defined to include the health of “sensitive” populations such as asthmatics, children, and the elderly. Secondary NAAQS set limits to protect public welfare from any known or anticipated adverse effects associated with the presence of such a pollutant. “Public welfare” includes protection against decreased visibility, damage to animals, crops, vegetation, and buildings. Therefore, possible adverse impacts from this project are not expected.
G.	Associated Growth Impact
The Growth Impact Analysis is an evaluation of a project’s potential impact on industrial, commercial, or residential impact in the area surrounding the facility. Delta Blues is a replacement facility for Gerald Andrus. Additionally, there will be no changes in the type of development in the area. Therefore, Delta Blues is not expected to have any impacts in the surrounding area.
H.	Class I Impact and Visibility
The Federal Land Managers’ Air Quality Related Values Work Group (FLAG), Phase I Report – Revised (2010), provides recommendations, specific procedures, and interpretation of results for assessing visibility impacts of new or modified sources on Class I Area resources. Section 3.2., Initial Screening Criteria (New), presents a screening tool, Q/D, (where Q is the total SO2, NOx, PM10, and H2SO4 annual emissions divided by D, the distance from the Class I Area) to screen out from Air Quality Related Values (AQRV) review for those sources with relatively small amounts of emissions located a large distance from a Class I Area. If this value is less than or equal to 10, the source will be considered to have negligible impacts with respect to Class I AQRV. The Federal Land Manager (FLM) (and the Federal official with direct responsibility for management of the Federal Class I parks as wilderness areas) will not request any further Class I AQRV impact analysis. As a minimum, the permitting authority should notify the FLM of all sources that exceed the Q/D criteria.

SO2 	30.37-tpy
NOx 	230.34-tpy
PM10 	166.54-tpy
H2SO4 	46.46-tpy

Class I Area	Class I Area Distance (km)	Q/D Value	Agency	
Breton National Wildlife Refuge	450	-	Fish & Wildlife Service (FWS)	
Caney Creek Wilderness Area	297	1.59	Forest Service (FS)	
Mingo Wilderness Area	413	-	Fish & Wildlife Service (FWS)	
Sipsey Wilderness Area	360	-	Forest Service (FS)	
Upper Buffalo Wilderness Area	352	-	Forest Service (FS)	

As seen in the table above, all 5 Class I areas that Mississippi affects are shown, but only the Caney Creek Wilderness Area Q/D value was calculated, since it the only Class I area within 300km of the facility. Delta Blues is located approximately 297 km from the Caney Creek Wilderness Area. The increase of visibility impairing pollutants were below the PSD significant levels, therefore, no Class I impact is necessary.

Following EPA guidance provided in Appendix W to 40 CFR Part 51, a near field assessment was conducted using the AERMOD dispersion model to determine the ambient impacts at, or around, 50 km from the project sources. The 50 km impacts (in any direction) were compared with the PSD increment Class I SILs. The PM2.5 near field analysis included both direct PM2.5 modeling impacts and secondary PM2.5 impact estimates. No further assessment is required if the near field results are less than the Class I SILs. 

The predicted NO2, PM10, and PM2.5, concentrations are less than their respective Class I PSD increment SILs. No additional modeling is required for these pollutants.

A)	Class II Impact and Visibility
EML has extensive experience operating natural gas-fired combustion turbine Electric Generating Units (EGUs) at numerous locations. Because low-sulfur pipeline-quality natural gas is such a clean burning fuel, to the best of EML’s  knowledge there has never been a circumstance where operation of such an EGU has resulted in visibility impairment at any on-site or off-site receptor or area. This statement is true for routine operations as well as maintenance, startup, and shutdown operations of EML’s combustion turbine EGUs. The emissions of visibility impairing pollutants, including sulfates, NOx, and PM/soot, are very low because (1) clean burning low sulfur pipeline quality gas will be fired and (2) state-of-the art emission controls will be employed.

Based on EML’s extensive experience operating natural gas-fired combustion turbine EGUs, EML is confident in asserting that the Delta Blues Advanced Power Station will not cause or contribute to visibility impairment at any off-site receptor or area, including all nearby airports, state forests, parks, scenic vistas, areas of special historic interest, or any other sensitive areas. 
VI.	Recommendation

The staff of the Permit Board has developed the draft permit and preliminary determination based on information submitted to the Permit Board by the applicant. The staff of the Permit Board is soliciting all relative information pertaining to the proposed activity, including a 30-day public comment, EPA review, and FLM review, to ensure that the final staff recommendation on the draft permit complies with all State and Federal regulations. The Public, EPA, and FLM review and comment on the draft permit and supporting documentation is an important element in the staff evaluation and resulting recommendation to the Permit Board. After a thorough consideration of the expressed views of all interested persons, pertinent federal/state statutes and regulations, supplemental information/modeling submitted by Cooperative Energy, a Mississippi Electric Cooperative, R.D. Morrow, Sr., Generating Plant any additional material relevant to the application, and after an appropriate resolution of all the comment, will MDEQ staff recommend issuance of the proposed/final draft PSD permit to Construct in accordance with 11 Miss. Admin. Code Pt. 2 - Air Regulations, 40 CFR Part 52.21 – Prevention of Significant Deterioration of Air Quality, and 40 CFR 51 Appendix W – Guidelines on Air Quality Models. The draft permit conditions have been developed to ensure compliance with all State and Federal regulations but are subject to change based on information received as a result of public, EPA, and FLM participation.