Preliminary Determination
of Approval for
Chemours Company FC LLC The Delisle Plant
Facility No. 1020-00115

Technical Review
by
Ryan Ozment

December 1, 2016
I.	General Information
Chemours Company FC LLC, The Delisle Plant (formerly DuPont), 7685 Kiln DeLisle Road, P.O. Box 430, Pass Christian, Mississippi 39571, (228) 255-2100, manufactures titanium dioxide (TiO2) in a one-step beneficiation chloride-ilmenite process using natural ilmenite ore, chlorine, and petroleum coke as the principal raw materials.  Chemours has two identical but separate TiO2 production lines (Lines 1 and 2).  Titanium-containing ore is chlorinated to form titanium tetrachloride (TiCl4).  The TiCl4 is then purified and oxidized to TiO2, which is surface treated and classified to meet customer specifications.  The final TiO2 products is dried and packaged for shipping.
Chemours’s operations fall under the Standard Industrial Classification (SIC) code 2816 for Inorganic Pigments.  The UTM coordinates of the proposed project are approximately 278.200 km East and 3,362.900 km North (or 89o18’30”W and 30o22’51”N).  
II.	Project Description
On May 28, 2014, Chemours submitted a complete air permit application for a Prevention of Significant Deterioration Permit to address the requirements of of 40 CFR 63, Subpart DDDDD (Boiler MACT), and to increase steam generation at the facility.  At the time, Chemours had not made a determination on the final path forward to satisfy the facility’s steam demand and meet the requirements of the Boiler MACT.  Because of this, Chemours requested a one-year extension to the January 31, 2016, compliance deadline for the Subpart DDDDD as well as a permit with two compliance options.  The first option involved converting two existing coal-fired boilers to natural gas-firing and installing a third, new, natural gas boiler.  The second option comprised of shutting down the two existing coal-fired boilers and installing three, new, natural gas boilers.  The permit was issued January 9, 2015.
On August 15, 2016, Chemours requested to modify the construction permit.  The request was submitted to address three matters:
1.	Since the permit was issued, Chemours has made a selection from the two compliance options.  The permittee selected the second option but decided to only install two new natural gas-fired boilers (rather than the three originally proposed).  Along with this revision to the permit, the facility asked to change the emission point ID’s of the boilers for better clarity, from AF-201 to AF-204 (Boiler No. 4) and AF-203 to AF-205 (Boiler No. 5).
2.	Since the construction permits issuance in January 2015, a number of changes have taken place in the Boiler MACT, 40 CFR 63, Subpart DDDDD.  The facility submitted an additional modification request, received September 12, 2016, to reflect these changes.
3.	Previously, Chemours operated two coal-fired boilers (AF-101A and AF-101B).  In this operating scenario, the facility’s potential-to-emit sulfur dioxide surpassed 2,000 tons per year.  In August 2015, EPA promulgated 40 CFR 51, Subpart BB, Data Requirements Rule for the 1-Hour Sulfur Dioxide (SO2) Primary National Ambient Air Quality Standard (NAAQS).  The rule requires air quality characterization and provides two choices for such (monitoring or modeling).  By July 2016, facilities affected by the rule had to indicate which route they would choose or if they intended to take on federally enforceable permit limit for SO2.  All three paths require implementation or completion by January 13, 2017.  Chemours’s SO2 potential-to-emit (whether choosing compliance option one or two from the construction permit) would drop well below the 2,000 ton per year threshold when utilizing natural gas.  Because of this, the compliance deadline for the requirement to cease operation of the coal-fired boilers was adjusted from January 31, 2017, to January 13, 2017. 

Table 1. PSD Applicability
Pollutant	Original Project Related Increases1	Modification Related Increases2	Significant Emission Rate	Netting Analysis Required?	Contemporaneous Emissions 	Total
Net Emissions	PSD Review Required?	
	(TPY)	(TPY)	(TPY)	(Yes/No)	(TPY)	(TPY)	(Yes/No)	
PM	20.32	13.54	25	No				
PM10	136.28	90.85	151	Yes	-539.43	-448.58	No	
PM2.5	136.28	90.85	10	Yes	-529.00	-429.15	No	
NOX3,4	465.16	310.10	40	Yes	-802.25	-429.15	No	
SO23	2.30	1.54	40	No				
VOC4	21.11	14.07	40	No				
CO	155.05	103.37	100	Yes	45.45	105.82	Yes	
1Option 2 of the original construction permit—replace two existing coal boilers with three, new, natural gas-fired boilers. 
2Modification to reflect the current proposal—replace two existing coal boilers with two, new, natural gas-fired boilers.
3As 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.
4Both NOx and VOC are considered precursors for ozone with a significant emission rate of 40 TPY each.

Because there are no new or increased emissions due to the modification of the permit, no air quality impact analysis was performed for the permit action.  The following data represents the BACT and Source Impact Analyses performed for the permit issued January 9, 2015.

III.	Best Available Control Technology (BACT) Analysis
The applicant is required to perform a BACT analysis for all pollutants that have a significant net emissions increase.  Utilizing the “top-down” approach detailed in EPA’s New Source Review Workshop Manual (Draft 1990), the PSD applicant goes through a five step process to determine BACT:  (1) Identify all control technologies; (2) Eliminate technically infeasible control options; (3) Rank the remaining control technologies by control effectiveness; (4) Evaluate the most effective controls taking into consideration economic, energy, and environmental impacts; and (5) Select BACT.  
BACT is an emission limitation based on the maximum degree of pollutant reduction determined on a case-by-case basis, taking into account energy, environmental, and economic impacts, that is determined to be achievable for a source.  A BACT analysis must be performed for each new or modified emission unit that emits any of the pollutants exceeding the significant emissions rate, which include PM, PM10, PM2.5, CO, and VOC.  Chemours’s May 28, 2014 PSD permit application contained a BACT analysis that went through the five steps listed above.
A.	CO Analysis
The new and existing boilers covered under the two options will be continuous sources of CO emissions. All of these sources will combust natural gas.  Good combustion practices which optimize the air to fuel ratio to achieve a more complete combustion, thus less CO, were evaluated for all combustion sources and deemed feasible for all.  Use of a CO oxidation catalyst was also evaluated for all of the sources and determined to be feasible for all of the boilers, but not economical for any of the boilers.  Therefore, good combustion practices for maintaining burner efficiency and CO emission limits of 0.04 lb/MMBtu (new boilers) and 0.06 lb/MMBtu (conversion of existing boilers) have been selected as BACT for boilers included in both options.  
B.	GHG Analysis
The new and existing boilers covered under the two options will be continuous sources of GHG emissions.  All of these sources will combust natural gas.  The cost of CCS was evaluated for both options, but found to be both infeasible and uneconomical.  
The boilers will combust only natural gas, thus the fuel source is inherently a lower-emitting carbon fuel.  Good combustion practices, which optimize the air to fuel ratio to achieve a more complete combustion while minimizing excess air, were evaluated for all combustion sources and deemed feasible and economical for all boilers.  To ensure good combustion practices for these sources, a continuous oxygen trim system is required as well as routine tune-ups.  A CO2e emission limit of 398,000 tpy will be established for Option 1 and a CO2e emission limit of 454,000 tpy will be established for Option 2.  
Chemours will also use the following energy efficiency measures in the conversion of the existing boilers and/or design of the new boilers: use of economizers (new boilers), air preheaters (converted boilers), oxygen trim controls, blow down heat recovery, steam turbine drives to let down deaerator and feedwater preheater steam and periodic tune-ups.
IV.	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 air quality is defined by the natural and human-generated sources of air pollution. The area surrounding the Harrison County facility is considered rural and in attainment for all regulated pollutants.  The proposed project will result in significant emission increases for carbon monoxide (CO) and greenhouse gases (GHGs) expressed as CO2e.
The pollutant under consideration in the analysis is carbon monoxide (CO).
B.	Modeling Procedure
All estimates of ambient concentrations are to be based upon applicable air quality models, data bases and other requirements specified in Appendix W of 40 CFR Part 51 (Guideline on Air Quality Models).
The AMS/EPA Regulatory Model (AERMOD) version 13350 was used to estimate impacts from all pollutants.  The modeling analysis was conducted using the regulatory default options.  Building wake and downwash effects were accounted for using the Building Profile Input Program (BPIP) version 04112.  
The proposed project is intended to address the requirements of 40 CFR 63, Subpart DDDDD – National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters (Boiler MACT), for two (2) existing coal-fired boilers; Emission Points AF-101A and AF-101B, two 209 MMBtu/hr Coal-fired Boilers. The proposed project will result in an increase of carbon monoxide emissions above the PSD significant emission rate for CO. The preliminary analysis performed was comprised of two (2) modeling scenarios: (1) Option 1, the Boiler Conversion project
•	Convert an existing coal/fuel oil-fired boiler (Emission Point AF-101A, Boiler No.1, a 209 MMBTU/hr Coal-fired boiler) to a 240 MMBTU/hr (nominal) natural gas-fired boiler equipped with low-NOx burners to reduce NOx emissions.
•	Convert an existing coal/fuel oil-fired boiler (Emission Point AF-101B, Boiler No.2, a 209 MMBTU/hr Coal-fired boiler) to a 240 MMBTU/hr (nominal) natural gas-fired boiler equipped with low-NOx burners to reduce NOx emissions.
•	Construct a new 295 MMBtu/hr (nominal) natural gas-fired boiler equipped with low-NOx burners and flue gas recirculation (FGR) to reduce NOx emissions.
•	Shut down and remove from serve Emission Point AF-202, A Natural Gas-fired Rental Boiler.
Emission Points AF-101A and AF-101B share a common stack. The converted boilers will continue to discharge emissions through a single exhaust stack; and, 
(2) Option 2, the Boiler Replacement Project
•	Shut down and remove from service two (2) existing coal/fuel oil-fired boilers. Emission Points AF-101A and AF-101B, two 209 MMBtu/hr Coal-fired Boilers
•	Shut down and remove from service Emission Point AF-202, A Natural Gas-fired Rental Boiler.
•	Construct three (3) new 295 MMBtu/hr (nominal) natural gas-fired boilers, each equipped with low-NOx burners and flue gas recirculation (FGR) to reduce NOx emissions.
Each new boiler will discharge emissions through a dedicated stack. Each scenario was modeled at nominal heat input capacity for each boiler. 
Table 2 and Table 3, Point Source Parameters, reflect the parameters used to perform the dispersion modeling for each scenario.

Table 2. Modeled Point Source Parameters for Option 1 (Boiler Conversion)
Emission Source	Emission Source Description	Emission Rate	Stack Parameters	
		lb/hr	g/s	X (meters)	Y (meters)	Stack Height (m)	Temp (ºK)	Velocity (m/s)	Diameter (m)	
AF-101	Boiler No.1, a 209 MMBTU/hr Coal-fired boiler	28.84	3.6338	278230.6	3363262.6	45.72	437.04	29.97	3.048	
	Boiler No.2, a 209 MMBTU/hr Coal-fired boiler									
AF-201	New 295 MMBtu/hr (nominal) natural gas-fired boilers equipped with low-NOx burners and flue gas recirculation (FGR)	11.80	1.4868	278131.6	3363304.9	15.24	422.04	36.88	2.13	
AF-202	Natural gas-fired Rental Boiler	-15.02	-1.8925	278156.98	3363293.89	15.24	422.04	18.9	1.524	
	Heat Input Capacity: ≥101 MMBtu/hr and ≤231 MMBtu/hr									
	CO: 15.02 lbs/hr and 15.65 TPY									

Table 3. Modeled Point Source Parameters for Option 2 (Boiler Replacement)
Emission Source	Emission Source Description	Emission Rate	Stack Parameters	
		lb/hr	g/s	X (meters)	Y (meters)	Stack Height (m)	Temp (ºK)	Velocity (m/s)	Diameter (m)	
AF-101	Boiler No.1, a 209 MMBTU/hr Coal-fired boiler	-9.020	-1.1365	278230.6	3363262.6	45.72	394.26	13.72	3.048	
	Boiler No.2, a 209 MMBTU/hr Coal-fired boiler									
AF-201	New 295 MMBtu/hr (nominal) natural gas-fired boilers equipped with low-NOx burners and flue gas recirculation (FGR)	11.80	1.4868	278174.1	3363259.6	15.24	422.04	36.88	2.133	
AF-204	New 295 MMBtu/hr (nominal) natural gas-fired boilers equipped with low-NOx burners and flue gas recirculation (FGR)	11.80	1.4868	278193.3	3363350.6	15.24	422.04	36.88	2.133	
AF-205	New 295 MMBtu/hr (nominal) natural gas-fired boilers equipped with low-NOx burners and flue gas recirculation (FGR)	11.80	1.4868	278213.2	3363262.6	15.24	422.04	36.88	2.133	
AF-202	Natural gas-fired Rental Boiler	-15.02	-1.8925	278156.98	3363293.89	15.24	422.04	18.9	1.524	
	Heat Input Capacity: ≥101 MMBtu/hr and ≤231 MMBtu/hr									
	CO: 15.02 lbs/hr and 15.65 TPY									

The hourly meteorological database used in the preliminary and full impact analysis consisted of five years (2009-2013) of Gulfport-Biloxi International Airport, Gulfport, Mississippi, surface data and Slidell, Louisiana, upper air combined.
A Cartesian receptor grid was used for the preliminary modeling runs, including receptors spaced as follows:
•	50-meter spacing along the fence line
•	100-meter spacing extending from the fence line to 4-kilometers
C.	Air Quality Monitoring Requirements
The ambient air quality analysis is required to contain continuous air quality monitoring data gathered for purposes of determining whether emissions of that pollutant would cause or contribute to a violation of the standard or any maximum allowable increase.  The source may be exempt from the preconstruction monitoring requirements if the air quality impacts are less than the monitoring de minimis concentrations. 
Table 4 - Preconstruction de minimus levels.
Pollutant	Averaging Period	Monitoring de minimis Concentration (μg/m3)	Modeled Concentration (μg/m3)	
PM10	24-hour	10	N/A	
PM2.5	24-hour	4	N/A	
SO2	24-hour	13	N/A	
NO2	Annual	14	N/A	
Ozone		VOC or NOx  emission increase < 100 TPY	N/A	
CO	8-hour	575	13.70354	
Lead	3-month avg	0.1	N/A	
Fluorides	24-hour	0.25	N/A	
Total Reduced Sulfur	1-hour	10	N/A	
Hydrogen Sulfide	1-hour	0.2	N/A	
Reduced Sulfur Compounds	1-hour	10	N/A	
Preliminary analysis results show the impact of carbon monoxide to be below the monitoring de minimis concentrations.  The preconstruction monitoring requirement for this pollutant is, therefore, waived. 
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. 
Table 5 and Table 6 summarize the results of the preliminary analysis.  The modeled results presented are the highest estimated concentration for averaging times of 24-hours or less and the highest annual average of the individual years for the annual averaging period.
Table 5 - Significant Impact Modeling Results for Option 1 (Boiler Conversion Project)
Pollutant	Averaging Period	Significant Impact Level (μg/m3)	Modeled Results (μg/m3)	UTM X
(KM)	UTM Y
(KM)	Event (YYMMDDHH)	
CO	8-hour	500	2.32644	277042.47	3363340.92	08091124	
			2.42126	276900.00	3363725.00	09122408	
			1.57873	276900.00	3363425.00	10011608	
			2.28347	277300.00	3364525.00	11090408	
			2.26519	276900.00	3363925.00	12032024	
	1-hour	2,000	2.93184	277014.00	3363257.40	08091120	
			2.92999	278274.00	3362122.40	09111006	
			2.95368	277067.87	3363411.49	10011524	
			2.88349	277100.00	3363925.00	11090323	
			3.08817	278000.00	3364325.00	12083006	
For Option 1, the modeled results for CO were less than the significant impact level; therefore, no further analysis was required for this pollutant.
Table 6 - Significant Impact Modeling Results for Option 2 (Boiler Replacement Project)
Pollutant	Averaging Period	Significant Impact Level (μg/m3)	Modeled Results (μg/m3)	UTM X
(KM)	UTM Y
(KM)	Event (YYMMDDHH)	
CO	8-hour	500	12.89444	278091.95	3364160.00	08060724	
			9.56572	278091.95	3364160.00	09122124	
			13.08701	278091.95	3364160.00	10091024	
			13.70354	278109.90	3364142.60	11021824	
			11.09286	278163.75	3364090.39	12022124	
	1-hour	2,000	28.83327	278055.20	3364165.65	08082019	
			28.34195	278127.85	3364125.19	09052720	
			28.95833	278109.90	3364142.60	10082619	
			28.34115	278127.85	3364125.19	11060302	
			30.25573	278127.85	3364125.19	12081419	
For Option 2, the modeled results for CO were less than the significant impact level; therefore, no further analysis was required for this pollutant.
The significant impact modeling results presented in Table 6 demonstrate the combination of emission rates and source characteristics (stack parameters and stack locations) presented in Option 2, the Boiler Replacement modeling scenario, will result in the maximum carbon monoxide impacts for both the 1-hour and the 8-hour 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 ant the new source or modification.  For SO2, PM10, and NO2, the full impact analysis actually consists of separate analyses for the NAAQS and PSD increments.
The preliminary analysis modeling results presented in Table 5 and Table 6 in Section D above, demonstrates the carbon monoxide concentrations for each modeling scenario will not exceed the Modeling Significance Levels for carbon monoxide.  No significant impact will result from the project; therefore, no further analysis is necessary, a Full Impact Analysis is not required.
F.	Vegetation and Soils Impact
The owner or operator is required to provide an analysis of the impairment to visibility, soils and vegetation that would occur as a result of the source or modification.  The owner or operator need not provide an analysis of the impact on vegetation having no significant commercial or recreational value.
The secondary NAAQS are set to “protect the public welfare from any known or anticipated adverse effects'' associated with ambient concentrations of the pollutant. The term ``welfare'' is defined in the Clean Air Act to include ``effects on soils, water, crops, vegetation, man-made materials, animals, wildlife, weather, visibility, and climate.''  
In accordance with EPA guidance document, “A Screening Procedure for the impacts of Air Pollution Sources on Plants, Soils, and Animals,” the suggested screening concentration for exposure to ambient air concentrations of carbon monoxide is 1,800,000 μg/m3 (1 week averaging period).  The modeled results were below the secondary NAAQS and the suggested screening concentration; therefore, no adverse impacts on soils and vegetation is anticipated.
G.	Associated Growth Impact
The owner or operator is required to provide an analysis of the air quality impact projected for the area as a result of general commercial, residential, industrial and other growth associated with the source or modification.
The proposed project is not expected to have a measurable effect on the residential, commercial, or industrial growth of the area.  No adverse impacts on growth are anticipated.
H.	Class I Impact and Visibility
The owner or operator must demonstrate that actual emissions from the major stationary source or major modification, including fugitive emissions, will not cause or contribute to adverse impact on visibility within any federal Class I area. The owner/operator is required to provide a visibility impact analysis of the visibility impact likely to occur as a result of general commercial, residential, industrial, and other growth associated with the source or major modification.
Visibility impairment is any humanly perceptible change in visibility (light extinction, visual range, contrast, coloration) from that which would have existed under natural conditions. Carbon monoxide emissions do not impact visibility. Chemours Company FC LLC, The Delisle Plant (formerly DuPont) is located approximately 56- km from the Breton Wilderness Area. Based upon the project-associated emission rates and the distance from the Breton Wilderness Ares, the Fish and Wildlife Service anticipates that modeling would not show any significant additional impacts to the AQRV at the areas administered by the FWS. Furthermore, as outlined in the NSR applicability analysis, the shutdown of the coal-fired boilers will result in a substantial net emissions decrease in almost all pollutants. No adverse impacts at the Class I are anticipated; therefore, no Class I AQRV analysis is required/requested.
V.	Recommendation
The impacts of the emission of air contaminants from the proposed modification have been evaluated and the staff believes that, with proper constraints and limitations, this project will operate within all State and Federal air pollution control laws and standards and will be protective of public health and welfare.  Therefore, the staff of the Board has preliminary decided, based on available information, to recommend to the Board that the permit will be issued to reflect the requested construction and modification of emissions equipment.  However, before proceeding with the staff evaluation, public comments are being solicited.  The staff recommendation to the Board, as well as the Board decision, will be made only after a thorough consideration of all public comments.