Crude Flexibility and Modernization Project – Initial Permit Application

Prepared For Texas Commission on Environmental Quality

On behalf of Phillips 66 Company – Borger Refinery

April 2020 Proj ec t No. P2060

TRICORD Consulting, LLC 402A West Palm Valley Blvd., PMB348 888.900.0746

TABLE OF CONTENTS

1 Introduction ...... 1-1 1.1 Facility Information ...... 1-1 1.2 Purpose of Request ...... 1-2 1.3 Federal New Source Review Permitting Applicability ...... 1-3 1.4 Application Fees ...... 1-4 1.5 Application Content ...... 1-5

2 Process Description ...... 2-1 2.1 Overview of Refinery Operations ...... 2-1 2.2 Detailed Process Description – Crude Units (Units 9, 10, 28, and 32) ...... 2-1 2.3 Intermediate Processing ...... 2-2 2.4 Overview of Ancillary Operations ...... 2-6

3 Project Description ...... 3-1 3.1 Crude Flexibility and Modernization Project – Physical and Operational Changes ...... 3-1 3.2 Upstream and Downstream Affects ...... 3-4

4 Emission Calculation Methodology ...... 4-1 4.1 Process Heater Emissions (EPNs: 28-H3, 28-H4, and 88-H1) ...... 4-1 4.2 Continuous Catalytic Reformer Vent (EPN: 88-V1) ...... 4-3 4.3 Equipment Leak Fugitives (EPN: F-CRUDEFLEX) ...... 4-3 4.4 Planned Maintenance, Startup, and Shutdown (EPN: MSS) ...... 4-4 4.5 Process Unit Sump (EPNs: F-SUMPCCR) ...... 4-6

5 Best Available Control Technology – Criteria Pollutants ...... 5-1 5.1 Process Heaters (EPNs: 28-H3, 28-H4, and 88-H1) ...... 5-3 5.2 CCR Regeneration Vent (EPN: 88-V1) ...... 5-6 5.3 Fugitive Piping Components (EPN: F-CrudeFlex) ...... 5-8 5.4 Planned MSS Activities (EPN: MSS) ...... 5-9 5.5 Wastewater Collection (EPN: F-SUMPCCR) ...... 5-10

6 Best Available Control Technology – Greenhouse Gas Pollutants ... 6-1

PERMIT AMENDMENT FOR FLEXIBLE PERMIT 9868A – PHILLIPS 66 BORGER REFINERY i

6.1 Process Heaters (EPNs: 28-H3, 28-H4, and 88-H1) ...... 6-1 6.2 CCR Regeneration Vent (88-V1) ...... 6-2 6.3 Fugitive Piping Components (EPN: F-CrudeFlex) ...... 6-3 6.4 Planned MSS Activities (EPN: MSS) ...... 6-3

7 Regulatory Applicability ...... 7-1 7.1 General Application Requirements – §116.111(a)(2)(A) ...... 7-1

8 Air Quality Analysis ...... 8-1

LIST OF FIGURES

Figure 1-1 Area Map ...... 1-7 Figure 1-2 Plot Plan ...... 1-8 Figure 2-1 Refinery Block Flow Diagram ...... 2-8 Figure 2-2 Simplified Process Flow Diagram - CCR ...... 2-9 Figure 2-3 Simplified Process Flow Diagram – Methanator ...... 2-10 Figure 2-4 Simplified Process Flow Diagram – Naphtha Splitter ...... 2-11

LIST OF TABLES

Table 1-1: PTE Comparison ...... 1-3 Table 4-1: List of New/Modified Sources ...... 4-1 Table 5-1: BACT Summary ...... 5-2 Table 8-1: Summary of Modeling Results (Non-PSD) ...... 8-1

LIST OF APPENDICES

Appendix A: TCEQ Forms and Tables Appendix B: BACT Analyses - Supporting Documentation Appendix C: Criteria Pollutant Emission Calculations Appendix D: PSD Applicability Determination – Criteria Pollutants Appendix E: GHG Pollutant Emission Calculations Appendix F: Air Quality Analysis

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT ii 1 INTRODUCTION

WRB Refining, LP is a 50/50 partnership between the Phillips 66 Company (Phillips 66) and Cenovus Energy. WRB Refining, LP owns the Borger Refinery, which is operated by Phillips 66. Phillips 66 Borger Refinery is requesting an initial New Source Review (NSR) Permit to authorize the construction of new emission sources and the modification of existing emission sources associated with a planned project to modernize the refinery and allow for more variability in refinery crude slates. Phillips 66 Borger Refinery is applying for an initial NSR permit under the requirements of Title 30 of the Texas Administrative Code (30 TAC), Chapter 116, Subchapter B.

Phillips 66 Borger Refinery plans to construct a new Continuous Catalytic Reformer (CCR) Unit and a new Naphtha Splitter Unit, install new and more efficient crude charge heaters to replace the existing crude charge heaters, and make modifications in other selected refinery p rocess units, including shutting down certain older process units. The ph ysical changes will increase overall refinery efficiency and accommodate more crude slate variability. For example, the new CCR Unit will replace existing semi-regenerative reforming units, which operate with older and less efficient technology. Annual site-wide emissions for most pollutants will decrease a result of the changes.

This project is her ein referred to as the “Crude Flexibility and Modernization Project.”

1.1 Facility Information The Phillips 66 Borger Refinery is an integrated petroleum refinery. Crude oil is delivered to the refinery and then processed and refined into various petrochemical products and commercial petroleum products such as propane, gasoline, jet fuel, diesel fuel, and petroleum coke. The TCEQ Customer Number (CN) for Phillips 66 Company is CN604065912. The Regulated Entity Number (RN) for t he Borger Ref inery is RN102495884. The facility TCEQ account number is HW-0018-P.

The Phillips 66 Borger Refinery is located on State Spur 911 i n Borger, Hutchinson County, Texas. Figure 1-1 is an area map showing the refinery l ocation relative to nearby t opographic features. This map is based on Google Earth imagery, and it indicates the property line and a 3,000-foot radius and 1-mile radius from the permitted facility. There are no schools within 3,000 feet of the permitted facility.

The facility plot plan, Figure 1-2, includes the north direction, and indicates the new equipment associated with the project. A more detailed plot plan will also be included in the Air Quality Analysis (AQA), which will be submitted subsequent to this initial application.

The Phillips 66 Borger Refinery currently operates under the following case-by-case construction and operating permits.

Construction Permits

• Flexible Permit 9868A – normal emissions from most refinery sources

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 1-1 • NSR Permit 71385 – Unit 45 (Mercaptan Unit) • NSR Permit 80799 – planned maintenance, startup, and shutdown (MSS) emissions for refinery sources • NSR Permit 85872 – Boilers • NSR Permit 155341 –Johnson Tank Farm (JTF) sources

The refinery also has several active standard exemptions, permits by rule (PBRs), and standard permits (SPs).

Operating Permits

• Standard Operating Permit (SOP) O1440 – most refinery sources • SOP O2166 – Unit 45 (Mercaptan Unit) • SOP O4130 – JTF sources

Phillips 66 Borger Refinery is proposing to authorize the emission increases associated with the Crude Flexibility and Modernization Project under a new Subchapter B NSR permit and a new SOP.

1.2 Purpose of Request The Phillips 66 Borger Refinery is currently able to process up to 165 thousand barrels per day (MBPD) of crude oil. The refinery currently processes primarily heavy crude oils, which are routed to the refinery via pipeline. Phillips 66 Borger Refinery is planning to replace older refinery process equipment with new process equipment, which will allow the refinery to run more efficiently and to process a more variable crude slate.

Phillips 66 Borger Refinery plans to make the following physical changes in support of this project:

1. Install a new crude desalter train that will run in parallel with the existing crude desalters; 2. Replace three (3) existing, older crude unit heaters with two (2) new, lower-emitting crude unit heaters; 3. Construct a new, more efficient 32 MBPD CCR Unit to replace two (2) existing and less efficient semi-regenerative catalytic reforming units; 4. Construct a new Naphtha Splitter unit; 5. Construct a new Methanator in the CCR Unit battery limits to convert carbon monoxide (CO) into methane, using produced hydrogen gas; 6. Modify existing refinery process units to upgrade pumps and safety/relief valves, increase or decrease line sizes, change or replace fugitive piping components (including valves/flanges, control valve, and compressors), change/replace/add heat exchange systems, and make other ancillary changes to process unit configurations.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 1-2 The emission sources associated with the Crude Flexibility and Modernization Project are mostly new; therefore, Phillips 66 Borger Refinery is requesting a new case-by-case Subchapter B NSR permit to authorize the project.

The new emission sources, including the new crude charge heaters and the CCR Unit heaters and regeneration vent, are replacing older and less efficient units. The new sources will be installed with controls meeting current Best Available Control Technology (BACT), which will decrease actual and potential emissions from the units and will require fewer shutdowns than the equipment they are replacing. The table below provides a comparison of the potentials-to-emit (PTEs) for the new sources and the shut-down sources on an annual average basis. The PTEs for the existing sources that will be shut down are based on the current represented flexible permit cap contributions.

Table 1-1: PTE Comparison

Source NOX CO SO2 PM PM10 PM2.5 H2S VOC Classification (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) New Sources1 52.70 124.76 45.01 26.04 26.0 26.04 0.46 99.07 Removed 313.80 198.15 109.46 49.39 49.39 49.39 <0.01 87.96 Sources2 Delta -261.10 -73.39 -64.45 -23.35 -23.35 -23.35 0.46 11.11

As shown above, the majority of the potential annual emission rates significantly decrease as a result of the project. Additionally, there are no PTE increases from existing upstream or downstream sources as a result of this project. Therefore, the site-wide PTE will decrease on an annual average basis for most pollutants. Apparent increases in volatile organic compounds (VOCs) and hydrogen sulfide (H2S) are due to new emissions from fugitive piping components, which are based on estimated component counts and are not enforceable emission limits.

A more detailed description of the Crude Flexibility and Modernization Project is included in Section 3 of this application.

1.3 Federal New Source Review Permitting Applicability Hutchinson County is designated as an attainment or unclassified area for all criteria air pollutants; therefore, Phillips 66 Borger Refinery projects are not subject to nonattainment new source review (NNSR) permitting requirements. However, Phillips 66 Borger Refinery is an existing major source as defined in the Prevention of Significant Deterioration (PSD) permit program for all criteria pollutants; therefore, physical and operational changes at the refinery are potentially subject to PSD permitting requirements.

1 New sources include the following emission point numbers (EPNs), as represented in Table C-1 in Appendix C: 28-H3, 28-H4, 88-H1, 88-V1, F-CrudeFlex, F-SUMPCCR, and MSS 2 Removed sources include the following EPNs, as represented in Table D-2 in Appendix D: 7H1-4, 9H1, 10H1,19H5, 19H6, 28H1, 19H1, 19H2, 7E1, 7E2,7E3, 7E4, 7E5, 7E6, 7E7, F-7, and F-19-2.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 1-3

The Crude Flexibility and Modernization Project will result in an increase in actual emissions for most existing refinery emission sources, although there will be no increase in PTE for any existing source. The Federal New Source Review (FNSR) PSD project emission increases for the Crude Flexibility and Modernization Project are summarized in the General PI-1 form in Appendix A and detailed in Table D-1 in Appendix D for criteria pollutants and Table E-1 in Appendix E for greenhouse gases (GHGs). The Crude Flexibility and Modernization Project results in project emission increases greater than the PSD major modification levels for the following pollutants:

• Oxides of Nitrogen (NOX); • CO; • VOC;

• Sulfur Dioxide (SO2);

• H2S; • Particulate Matter (PM);

• PM with a diameter less than 10 microns (PM10);

• PM with a diameter less than 2.5 microns (PM2.5); and

• Carbon dioxide (CO2) equivalent (CO2e).

The majority of the calculated project increases is due to the difference in the baseline emissions from sources associated with the flexible permit caps and the current authorized flexible permit caps, since the flexible permit cap sources have been operating at emission levels well below the authorized emission rates. Further, the project increase calculations do not incorporate any emission decreases from the sources being shut down.

Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to forego netting and perform a PSD review for all applicable pollutants.

The TCEQ’s PSD Tables 2F and 3F are included in Appendix D for criteria pollutants and Appendix E for GHGs. The TCEQ’s Table 1F is included in Appendix A. A more detailed discussion of the PSD evaluation is included in Section 3.2.

1.4 Application Fees In accordance with 30 TAC 116.163 (b), the initial fee for the PSD permit application is $75,000. This permit application is being submitted through the TCEQ’s expedited permit program using the Form APD‐EXP, which is located in Appendix A. The $20,000 permit surcharge fee is being mailed to the TCEQ’s Revenue Section with the Form APD-APS.

The $75,000 permit fee is being paid to the TCEQ via check. The check was mailed to the TCEQ’s Revenue Section, and a copy of the check is included at the end of Appendix A. The estimated

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 1-4

capital cost of the project is greater than $2 million; therefore, a Professional Engineer Certification is included at the end of this section prior to Figure 1-1.

1.5 Application Content This application is organized into the following sections, as described below. • Section 1 contains background information and describes how this application is organized. • Section 2 includes a process description. • Section 3 includes a detailed project description. • Section 4 provides descriptions of the emission calculation methodologies for sources associated with the project. • Section 5 includes an evaluation of BACT requirements for new/modified sources of criteria pollutants. • Section 6 includes a BACT evaluation for new/modified sources of GHG emissions. • Section 7 provides a discussion of state regulatory applicability. • Section 8 discusses the air quality analysis. • Appendix A contains applicable TCEQ forms and tables, including the General PI-1 form. • Appendix B provides supporting documentation for the BACT analyses. • Appendix C provides detailed emission criteria pollutant calculations for all new/modified sources. • Appendix D contains a detailed PSD evaluation for criteria pollutants. • Appendix E includes a PSD evaluation and detailed emission calculations for new/modified GHG emission sources. • Appendix F includes the TCEQ’s Electronic Modeling Evaluation Workbook (EMEW) for the AQA for non-PSD pollutants.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 1-5 PROFESSIONAL ENGINEER CERTIFICATION

I, Kelly E. Belz, a registered professional engineer in the State of Texas (Registration No. 98955) certify that the attached TCEQ Air Permit Application associated with the Crude Flexibility and Modernization Project at the Phillips 66 Borger Refinery, dated March 31, 2020, was reviewed by me, as based on the information provided and review and approval of the application, by Phillips 66 Borger and/or Phillips 66 Borger representatives.

TRICORD Consulting, LLC DBA TRICORD Consulting, LLC Firm Number 21445

SEAL

Kelly E. Belz, P.E.

Engineer

98955 Registration Number

Texas

State

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 1-6

Figure 1-1 Area Map

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT – PHILLIPS 66 BORGER REFINERY 1-7

Figure 1-2 Plot Plan

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT – PHILLIPS 66 BORGER REFINERY 1-8

2 PROCESS DESCRIPTION

This section includes general and detailed descriptions of the Phillips 66 Borger Refinery and associated process units. A description of the changes associated with the Crude Flexibility and Modernization Project is provided in Section 3 of the application.

2.1 Overview of Refinery Operations The Phillips 66 Borger Refinery processes purchased crude oil and natural gas liquids (NGLs) to produce petrochemical and commercial petroleum products. Crude oil and NGLs are delivered to the refinery via pipeline and are refined into various products such as propane, butane, gasoline, jet fuel, diesel fuel, and other heavy oils via multiple integrated processing units.

2.2 Detailed Process Description – Crude Units (Units 9, 10, 28, and 32) The purpose of the crude units is to separate crude oil into its primary boiling range products, including naphtha, kerosene (jet), light diesel, heavy diesel, and atmospheric tower bottoms (topped crude). The raw crude is heated in heat exchangers and then mixed with water before being fed to the desalters, where the water is allowed to settle out of the crude, effectively removing any salts that are naturally present in the crude oil. If the salts are not removed, then they can cause water hydrolysis (which can result in the formation of corrosive hydrochloric acid [HCl]) and cause fouling and plugging in refinery process equipment. The water layer is treated in the refinery wastewater treatment plant (WWTP).

The desalted crude is then sent through another series of heat exchangers en route to the pre-flash columns. The purpose of the pre-flash column is to remove the light ends and any residual desalter water from the crude feed to reduce energy demand and vapor traffic in the atmospheric crude column. A secondary benefit of removing the light ends from the crude is that the bubble point of the crude becomes much higher, allowing the unit to operate at a lower pressure without risk of developing undesirable two-phase flow. The pre-flash column overheads (or pre-flash naphtha) are combined with the naphtha from the crude distillation columns. The pre-flash columns bottoms are pumped to the crude charge heaters to vaporize the crude oil prior to the crude distillation columns.

The vaporized crude oil enters the crude distillation column at the bottom of the column and as the crude rises up the distillation column, the different fractions are separated based on their boiling points. The topped crude, which has the highest boiling point and is the heaviest fraction, exits at the bottom of the column, and the naphtha/off-gases, which have the lowest boiling point, exit at the top of the column.

The temperature in the distillation column decreases as the crude is routed up the column and the different fractions are separated out. The change in temperature from the distillation column top and distillation column bottom is called the “temperature gradient.” The temperature gradient must be controlled in order to optimize the distillation column operation and ensure that product boiling point ranges are on spec. The Phillips 66 Borger Refinery uses pump-around systems to help manage the temperature gradient by modulating internal reflux temperature and flow. The pump- arounds work by removing hot liquids from the distillation towers, pumping them to a cooler, and

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 2-1

then re-introducing the cooled liquids to the distillation tower at a higher level than where the liquids were removed. Reflux flow can be modulated by increasing or decreasing product draw from the pump-around.

The crude distillation column products (naphtha and lighter, jet, diesel, heavy diesel, and topped crude) are then further processed in downstream process units.

2.3 Intermediate Processing

2.3.1 Crude Unit – Naphtha Processing The naphtha fraction from the Crude Units is sent to fractionating columns to separate the C6 and lighter materials from C7 and heavier materials. The lighter materials are combined with NGLs and further fractionated and processed in fractionating columns and in the Butamer Unit and a benzene removal and isomerization unit known as the Straight Run Isomerization (SRI) Unit. The Butamer Unit isomerizes normal butane to isobutene. The SRI Unit removes benzene by hydrogenating it to cyclohexane and isomerizes C5 and C6 compounds for use in gasoline blending. The C7 and heavier naphtha material is sent to the Naphtha Hydrotreater (NHT) Unit for sulfur removal and product separation. The naphtha is mixed with hydrogen and then routed to the reaction section where sulfur compounds are catalytically converted to H2S. The stream is then routed through a series of separator vessels to remove the sour gas stream. The sour gas stream is sent to other process units for treating.

The sweet naphtha from the NHT Unit is currently sent to blending or to two (2) Semi-Regenerative Reforming Units (Units 7 and 19.2) to raise octane and produce gasoline blending components. After the Crude Flexibility and Modernization Project is completed, the sweet naphtha will be routed to blending or the new CCR Unit for additional processing. The Semi-Regenerative Reforming Units will be shut down.

2.3.1.1 New CCR Unit The new CCR Unit will have a design throughput of 32 MBPD and will functionally replace the existing Semi-Regenerative Reforming Units: the 6 MBPD Unit 7 and the 24.5 MBPD Unit 19.2. The CCR Unit will process the hydrotreated naphtha stream from the NHT Unit to increase the octane rating for use in gasoline blending. The CCR process converts low-octane paraffins into branched alkanes (or isoparaffins) and cyclic naphthenes, which are then partially dehydrogenated to produce high-octane aromatic compounds.

The hydrotreated naphtha is first mixed with hydrogen gas and raised to reaction temperature by cross exchanging with reactor effluent in the combined feed exchanger, and then fed through a fired charge heater. Once the mixed naphtha/hydrogen stream is heated up to the specified temperature, the heated naphtha is fed to the reaction section where it passes through three (3) reactors in series. The reaction is endothermic (meaning that energy [in the form of heat] is absorbed); therefore, the 1st and 2nd reactors are followed by inter-heaters which raise the reactor effluent back up to the desired reaction temperature.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 2-2

The CCR charge and inter-heaters will share a combined convection and flue gas section, containing a waste heat boiler capable of producing 600 pounds per square inch gauge (psig) high pressure steam. The steam will connect to the existing 600 psig steam header and will also provide steam for the new Naphtha Splitter Unit and the CCR product stabilizer.

The reactor effluent is cooled down by cross-exchanging with the unit feed in the combined feed exchanger. The stream is then cooled further in an air cooler before being routed to a product separator to separate the liquid and vapor products. The vapor product is rich in hydrogen gas and is split into two streams: hydrogen-recycle gas and hydrogen-rich net gas. The recycle gas is recycled back to the reactors, and the net gas is sent to the product recovery system, which includes a net gas compressor system.

The hydrogen-rich net gas will be routed through a Methanator section of the process unit, which includes heat exchangers, a Methanation reactor vessel, and a Methanator knockout drum. The purpose of the Methanator is to remove CO from the hydrogen-rich net gas prior before it is exported to other process units. The hydrogen-rich net gas is routed through a series of heat exchangers before entering the Methanation reactor, in which CO is removed by reacting with hydrogen to make methane and water. The reactor effluent is sent to the Methanator knockout drum, which is used to drain the entrained water before the hydrogen-rich net gas is sent on to be used as hydrogen in other process units, including the Gas Oil Hydrodesulfurization (GO HDS) Unit, the NHT Unit, and the Hydrogen Production Unit, as needed.

The liquid product from the product separator is sent to the product stabilizer. The stabilizer further removes light ends from the reformate product, which is further processed in downstream reformate splitter columns 39 and 130. Light ends from the product stabilizer are primarily sent to the net gas compressor system, but Liquid Petroleum Gases (LPGs) from the product stabilizer may be sent to storage and sales, as needed.

The CCR Unit includes a CCR regeneration section. A small slip stream of spent catalyst from the bottom of the reactor section is continuously recirculated back to the catalyst regeneration section. The spent catalyst is regenerated by burning the coke off of the catalyst using air. The regenerated catalyst stream is sent back to the top of the reaction section to the last reactor, where it trickles to the bottom of the reaction section to the first reactor using gravity.

The CCR regenerator vents associated with the initial catalyst depressuring and purge operations will be routed to the Flare Gas Recovery Systems (FGRS). The CCR regenerator vents and control systems associated with coke-burn off, catalyst rejuvenation, reduction or activation will be routed to atmosphere via a scrubbing system or equivalent (ex. the “Chlorsorb” system).

Wastewater will be routed through an oily water sewer system to the existing WWTP. Spent caustic from the CCR scrubber will be sent to the oily solids section of the WWTP.

2.3.1.2 Reformate Splitters (Columns 39/130) The reformate product from the CCR Unit is split and sent to the Reformate Splitter Columns 39/130. The purpose of the reformate splitter columns is to fractionate the reformate stream into light and

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 2-3

heavy reformate in support of managing the benzene concentration in gasoline. Benzene is primarily concentrated in the light reformate cuts. The heavy reformate streams from Columns 39/130 are sent to gasoline blending and sales. The light reformate stream from Column 39 is sent to Column 42 for further fractionating. The light reformate stream from Column 130 is currently sent to the SRI Unit for processing. However, after this project, the light reformate from Column 130 will also be routed to Column 42 in support of maintaining existing feed rates to the Ultra-Low Aromatic Commercial Heptane (ULACH) Unit.

2.3.2 Crude Unit – Diesel and Jet Processing The light diesel and jet kerosene cuts from the Crude Unit distillation process are primarily routed to the Light Cycle Oil (LCO) HDS Unit for sulfur removal and product separation. The LCO HDS Unit operates similarly to the NHT Unit, in that sulfur compounds in the diesel and kerosene are catalytically converted to H2S, which is then removed in a series of separation steps. Products from the Diesel HDS Unit include ultra-low sulfur diesel (ULSD), jet kerosene, off-gases, and naphtha. The ULSD and diesel are sent to tankage and sales. The off-gases and naphtha are sent to downstream units, including the new Naphtha Splitter Unit, for additional processing.

The heavy diesel cuts from the crude distillation columns are split and sent to the Diesel HDS Unit or to the GO HDS Unit for sulfur removal and product separation.

2.3.3 Crude Unit – Topped Crude Processing The No. 1 Vacuum Distillation Unit (VDU) processes the crude distillation column bottoms stream (known as topped crude) and fractionates it using vacuum distillation into diesel, light and heavy gas oils, and vacuum residual. The VDU bottoms are sent to the Coker Unit for processing. Other VDU products are sent to the GO HDS Unit for sulfur treatment and removal and product separation.

The Delayed Coking Unit (DCU) processes the VDU bottoms (or vacuum residual). The feed stream is heated to cracking temperatures and then thermally cracked into shorter chain hydrocarbons in the coke drums, which operate as a batch process. The coke drum vapors are routed to the fractionating column where the different product streams are separated. The coke drum is steamed to remove any residual hydrocarbon vapors and then cooled with water before being opened and drained. The petroleum coke is routed to the coke pads before being sold offsite.

The DCU fractionating column products include off-gases, olefins, coker naphtha, and gas oils. The olefins are routed to the Propane/Butane Treater section prior to being used as feed in the Hydrofluoric Acid (HF) Alkylation Unit (HFAU). The coker naphtha and gas oils are routed to the GO HDS Unit for sulfur treatment and removal and additional product separation.

2.3.4 Gas Oil HDS Unit Light and heavy VDU and DCU gas oils, VDU distillate, crude distillation heavy diesel, DCU naphtha, and light cycle oil (LCO) from the Fluid Catalytic Cracking Units (FCCUs) are combined and routed to the GO HDS Unit. The GO HDS Unit removes sulfur and nitrogen compounds from the feed and cracks some of the gas oils into naphtha and ULSD. Any remaining treated gas oils are

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 2-4

sent to the FCCUs. The ULSD is sent to tankage and sales. The naphtha is sent to the new Naphtha Splitter Unit.

The GO HDS Unit also includes a number of associated process units, including two Steam-Methane Reformer (SMR) units that produce high-purity hydrogen.

2.3.5 New Naphtha Splitter Unit The new Naphtha Splitter Unit will process up to 15 MBPD of unstabilized naphtha streams from the Diesel HDS Unit, the LCO HDS Unit, and the GO HDS Unit. The streams are combined in a feed surge drum and then pumped through a series of feed/product heat exchangers prior to the naphtha splitting column. The new tower is a divided wall column with heavy, middle, and light naphtha cuts and an off-gas fraction. The heavy naphtha bottom cut is cooled and sent to diesel blending. The middle naphtha cut is cooled and sent to gasoline blending during normal operations and to the CCR during NHT Unit outages. The light naphtha cut is sent to an accumulator which separates the off-gases from the light naphtha. Off-gases are sent to the low-pressure gas system. The light naphtha is sent to Column 29 for further fractionation.

2.3.6 Fluid Catalytic Cracking Units The gas oil stream from the GO HDS Unit is routed to the FCCUs for additional processing. The gas oil is pre-heated and combined with a recycled slurry oil stream before being injected into the catalyst riser where it is vaporized and catalytically cracked into shorter-chain hydrocarbons after mixing with powdered catalyst. The fluidized catalyst and hot vapor stream go through the catalyst reactor where the cracked product vapor is separated from the catalyst in a series of cyclones. The spent catalyst then goes through the catalyst regeneration process where the coke deposits on the catalyst are burned off using air. The regenerated catalyst then gets sent back through the riser and repeats the same process. The flue gas from the regenerator is sent through some additional process equipment for more catalyst separation before being routed to the atmosphere via an electrostatic precipitator (ESP) control device. The ESP is designed to control particulate matter (PM) emissions from the FCCU catalyst regeneration process.

The product vapors from the catalytic reactor are sent to the FCCU main distillation column for product separation. FCCU products include off-gases, olefins, FCCU gasoline, LCO, and slurry. The off-gases, olefins, LCO, and slurry are routed to downstream process units for further treatment and refining. The FCCU gasoline is sent to tankage and blending.

The Unit 40 FCCU also includes a Light Ends Fractionation Unit 26 in the battery limits, which helps process the Unit 40 streams into the fractions described above.

2.3.7 Olefin Treatment and C3/C4 Splitter (Column 36) Sour olefins (propylene and butylene) from the DCU and the FCCUs are routed to the Propane/Butane Treatment Unit to remove sulfur compounds. The sweet olefin stream is sent to the C3/C4 splitter to separate the stream into light ends (C3s) and the Alky feed stream (C4s). The light ends are sent to tankage and sales as Refinery Gas Products (RGPs). The Alky feed stream is sent to the HFAU for further treatment.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 2-5

2.3.8 HF Alkylation The HFAU processes butylenes from the C3/C4 splitter and isobutane from the Butamer Unit. The two streams react in the presence of HF acid to produce alkylate, which is used as a gasoline blendstock component. Propane and butane product streams are routed to tankage. Total alkylate, light alkylate, and heavy alkylate are routed to tankage and blending.

2.4 Overview of Ancillary Operations

2.4.1 Planned MSS There is the potential for MSS activities and related emissions to occur at each of the above process units and throughout the refinery. MSS activities can include process unit turnarounds, individual equipment maintenance, and other minor planned maintenance events such as surface blasting activities.

Planned MSS activities can also include ancillary sources and operations, including vacuum truck and frac tank operations and operation of portable control devices. NSR Permit 80799 also authorizes emissions from storage tank MSS activities.

2.4.2 Sulfur Complex (Units 34, 43, 44, and 45) The Phillips 66 Borger Refinery includes a sulfur complex, which is designed to treat or recover sulfur resulting from the processed crude oil. Sour water (which contains H2S) from refinery process units is sent to the Sour Water Stripping Unit to remove H2S and ammonia (NH3) from the water. The sour water is managed in the sour water tank prior to being routed to the sour water stripper. The sour water stripping column uses steam to strip H2S and NH3 from the sour water. The stripped water is sent back to the refinery or treated further in the refinery WWTP.

The acid gas generated in the sour water stripping unit is sent to the Methyldiethanolamine (MDEA) Treatment Unit or the Amine Regeneration Unit (ARU), along with other refinery sour gas and off- gases to remove H2S from the sour gas. The treated gases are routed to the refinery fuel gas system for use as fuel gas in refinery combustion sources. The rich amine is regenerated using thermal regeneration and re-used as lean amine. The H2S gas stripped from the amine is sent to the Sulfur Recovery Units (SRUs) or to the Methyl Mercaptan Unit as feed.

The Phillips 66 Borger Refinery includes two SRUs. Each SRU has a Claus Unit, tail gas treatment unit (TGTU), and an incinerator. The purpose of the SRU is to recover elemental sulfur from the acid gas. The elemental sulfur is stored in a tank and then sent off-site for sales. The Methyl Mercaptan Unit produces methyl mercaptan (MESH) by reacting methanol and H2S. The MESH product is sent to storage tanks via pipeline. The storage tanks are owned and operated by a separate entity (Chevron Phillips Chemical Company) and are authorized in a separate NSR permit.

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2.4.3 Steam Boilers The Phillips 66 Borger Refinery includes multiple refinery fuel gas- or natural gas-fired steam boilers, which operate throughout the refinery. The steam is used in various refinery process units as a heating medium in heat exchange systems and is used in process stripping.

2.4.4 Storage and Loading The Phillips 66 Borger Refinery stores feedstocks, process unit intermediates, and refined products in atmospheric and pressurized storage tanks. The refined products are primarily shipped out via several product pipelines, although some truck loading does occur.

2.4.5 Cooling Towers The Phillips 66 Borger Refinery includes multiple cooling towers to provide a cooling medium to refinery heat exchange systems.

2.4.6 Flare Systems The Phillips 66 Borger Refinery operates four main refinery flares, which are equipped with FGRSs. The Phillips 66 Borger Refinery also operates additional flares that are used in emergency/upset capacities only. The purpose of the flares is to control certain process unit off-gases prior to release into the atmosphere.

Figure 2-1 at the end of this section is a general overview of the refinery operations. Figure 2-2 is a process flow diagram (PFD) of the new CCR Unit. Figure 2-3 is a PFD of the Methanator portion of the CCR Unit. Figure 2-4 is a PFD of the new Naphtha Splitter Unit.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 2-7 Refinery Feeds

Y-Grade Off-Gas Y-2 Slop Col 29 Col 30 Off-Gas Col 31 CC44 ttoo TrTreeaatteerr OOVVHHDD Off-Gas TToo Co Coll 3030

TToo Co Coll 3030 OOHH Liiq L q Col 37 To Col 32 iC5 Col 32 U2.2 SRI Off-Gas Off-Gas C5/C6 Col 40 nC5 19.3 Naphtha SRN C5/C6 to SRI Isom Isomerate 19.3 Jet Recycle to Blending Col 35/38 U19.3 C6- Jet 19.3 ULSD Col 108

Raw Crude OH to Col 42 Crudes Diesel Off-Gas Natural Gasoline Off-Gas Col 130 HHeeaavvyyDDiieesseell Column HH22 NNeett Ga Gass Naphtha 35/38 H2 U36 LEP OVHD Liq LPG Heavy Col 42 OH Heavy Reformate to SRI Naphtha ULSD U19.1 CCR C6C6-- Off-Gas Topped Off-Gas Crude Reformate Col 42 Distillate 42 Naphtha 26.8026.8026.80 Naphtha Sweet Naphtha Splitter UULLAACCHH LVGO 4422 UULLSSDD VDU U42 Col 39 HVGO HVY Nap nC7 to ULSD Off-Gas Gas Oil Col 39 ULACH Coker Off-Gas Heavy & Vac Resid To Gasoline Olefins Blending Reformate Col 33 U29 Olefins Slurry Coker Naphtha Commercial UU2299 Ga Gassoolliinnee C7s Coker LCGO U29 LCO Reference Fuels HCGO SSlluurrrryy RGP C3 TToo Co Cokkeerr Coke iC4 Off-Gas nnCC44 U40 PB PB Total Units highlighted in red are Olefins Treater Treater AAllkkyyllaattee & & LLiigghhtt Figure 2-1: Refinery Block Col 36 Col 36 AAllkkyyllaattee new/modified. U40/26 U40 Gasoline Flow Diagram >K Alky Feed Heavy Alkylate *Major process units only Page 2-8 Figure 2-2 Simplified Process Flow Diagram - CCR

EPN: MSS EPN: F-CrudeFlex

EPN: CCR-H Net Gas

EPN: CCRV

Net Gas Compressors

CW Regenerator

LPG (NNF)

HPS Cond.

Feed Recycle H2

CW Platformate

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 2-9 Figure 2-3 Simplified Process Flow Diagram – Methanator EPN: MSS EPN: F-CrudeFlex

H2-Rich Net Gas to Other Process Units

Steam

To Closed Drain H2-Rich Net Gas

Condensate

H2-Rich Net Gas

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 2-10 Figure 2-4 Simplified Process Flow Diagram – Naphtha Splitter

EPN: MSS EPN: F-CrudeFlex

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3 PROJECT DESCRIPTION

This section provides a description of the changes associated with the Crude Flexibility and Modernization Project. The purpose of this project is to modernize the Phillips 66 Borger Refinery so it can operate more efficiently and process a more variable crude slate. Certain older process equipment and units will be shut down and replaced with new, more efficient and lower-emitting equipment and process unit technology, in support of this project. A detailed project description is provided as follows.

3.1 Crude Flexibility and Modernization Project – Physical and Operational Changes

3.1.1 New Desalter Drum Phillips 66 Borger Refinery plans to install a new horizontal crude oil desalting drum that will operate in parallel to the two existing spherical crude oil desalting drums which operate in series. The purpose of the new desalter is to handle increases in crude throughput associated with the Crude Flexibility and Modernization Project. Wastewater from the new crude oil desalting drum will be hard-piped to the existing Benzene Stripper for treatment. The only new or modified emission sources associated with the crude desalter changes are new fugitive piping components.

3.1.2 New Crude Charge Heaters and Crude Unit Changes Phillips 66 Borger Refinery currently operates three (3) crude charge heaters (EPNs: 9H1, 10H1, and 28H1), which are rated at 102 million British thermal units per hour (MMBtu/hr), 96 MMBtu/hr, and 158.5 MMBtu/hr, respectively. Phillips 66 Borger Refinery plans to replace the existing crude charge heaters with two new more modern and efficient heaters, which are designed for 192.5 MMBtu/hr each. The new crude charge heaters will enable the crude units to operate at higher throughput and will be designed to reduce or eliminate de-coke cycles that occur with the existing crude charge heaters. Additionally, the heaters will be associated with lower NOX emissions on a lb/MMBtu basis, reducing actual NOX emissions, compared to the current crude charge heaters.

New piping, including new pumps and crude preheat modifications, will be also installed in support of the new crude heaters and crude rate increase. Phillips 66 Borger Refinery plans to make the following physical changes:

• Install new internals in the four preflash columns to prevent naphtha foaming and to handle the increased charge rate; • Install new crude circulation pumps between the desalters and the preflash columns; • Install new flashed crude booster pumps in front of the crude charge heaters, which will enable the existing flashed crude pumps to be used without any modifications; • Re-vamp the crude preheat system by replacing heat exchange bundles in 16 heat exchangers and installing 13 new heat exchangers;

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• Upgrade the existing Unit 10A preflash tower bottoms pump to prevent double pumping at the new charge rate; • Move the desalted crude and diesel heat exchanger to upstream of the desalted crude and topped crude heat exchanger in Unit 28 to reduce crude inlet temperature and increase diesel pump-around duty; • Install a new heavy diesel pump-around system, including heavy diesel and flashed crude heat exchangers, which recovers heat into the crude feed and maximizes the unit energy efficiency and minimizes the required size of the new crude charge heaters; • Install new pumps and lines and install a new crude distillation tower nozzle and feed pipe to accommodate the new heavy diesel pump-around system; • Increase the line size to the heavy diesel pumps; • Install a new heavy diesel and flashed crude heat exchanger and a new control valve to cool the incremental increase in heavy diesel product and route it to its destination; and • Modify the inlet nozzles of the crude distillation tower to support even distribution of flow into the column flash zone.

Other changes not described above can include piping reroutes and installation of other new valves and fugitive piping components in support of the Crude Flexibility and Modernization Project.

3.1.3 New CCR Unit Phillips 66 Borger Refinery plans to modernize the refinery by replacing the existing semi- regenerative reforming units with a more efficient and lower-emitting 32 MBPD CCR. The semi- regenerative reforming units are designed for 6 MBPD (Unit 7) and 24.5 MBPD (Unit 19.2) of throughput rates. Semi-Regenerative reforming units are designed with older technology and produce gasoline blendstocks with lower octane numbers than their new CCR counterparts. Additionally, semi-regenerative reforming units must be regularly shut down in order to regenerate the catalyst.

CCR units are equipped with the most up-to-date technology and are designed with regenerators that allow the catalyst to be continuously regenerated, meaning the unit is only required to be shut down for turnarounds, which occur every 3-5 years. CCR units also produce high quality hydrogen gas which can be used throughout the refinery and may reduce the load on the existing Hydrogen Plants. CCR units are also more efficient than semi-regenerative reforming units, meaning CCR units can produce more barrels of reformate with the same amount of the feed as compared to their semi-regenerative reforming unit counterparts.

Phillips 66 Borger Refinery will shut down five (5) older heaters and six (6) older gas-fired engines, associated with the semi-regenerative reforming units. There will be three (3) new heaters that are installed in the new CCR Unit. The heaters will all vent through one stack and NOX emissions will be controlled by a Selective Catalytic Reduction (SCR) system. There will be one charge heater and two inter-heaters that have a combined fired duty of 412.90 MMBtu/hr. The SCR will utilize

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anhydrous ammonia, which will be stored in a new tank. There will be no emissions from the anhydrous ammonia tank during normal operations.

The CCR regenerator vents associated with the initial catalyst depressuring and purge operations will be routed to the FGRS. The CCR regenerator vents and control systems associated with coke- burn off, catalyst rejuvenation, reduction or activation will be routed to atmosphere. HCl and chlorine (Cl2) emissions will be controlled by a scrubbing system or equivalent (ex. the “Chlorsorb” system) prior to venting to atmosphere.

Wastewater will be routed through an oily water sewer system to the existing WWTP. Spent caustic from the CCR scrubber will be sent to the oily solids section of the WWTP.

3.1.3.1 Methanator Phillips 66 Borger Refinery is constructing a new Methanator section, which will be located within the battery limits of the CCR Unit. The purpose of the Methanator is to remove CO from the produced hydrogen gas from the CCR Unit. The Methanator section will include heat exchangers, a catalytic reactor, and a knockout drum.

3.1.4 New Naphtha Splitter Phillips 66 Borger Refinery plans to construct a new naphtha splitter to fractionate approximately 15 MBPD of naphtha from the GO HDS Unit, LCO HDS Unit, and Diesel HDS Unit. The heavy naphtha cut will be routed to storage and sales as a ULSD blendstock. The overhead liquid fraction (primarily C6-) will be sent to Column 29 in the refinery light ends section for further fractionating. The middle cut naphtha stream will be routed to storage and sales as a gasoline blendstock. The naphtha splitter will include a new surge drum, pumps, heat exchange systems and coolers, and a divided wall column for naphtha splitting. Steam will be provided by the existing 600 psig steam header system.

3.1.5 Planned Maintenance, Startup, and Shutdown Operations The new units and equipment will undergo planned MSS activities, including equipment opening and degassing. The materials in the equipment will be degassed to other process units or equipment, drained to closed systems, or routed to the flare gas recovery systems, as needed. Insignificant maintenance activities may include individual equipment isolation, catalyst changeout, meter proving, etc. These smaller activities are generally found in “Attachment A” and “Attachment B” of MSS permits and conditions. The MSS emissions authorized in this permit are for new equipment and emission sources. Planed MSS-related emissions from existing sources/activities are authorized in existing NSR permits. Phillips 66 Borger Refinery is not requesting any changes to existing permitted MSS emissions as a result of this project.

3.1.6 Column 130 and Column 33 Reroute Phillips 66 Borger Refinery plans to reroute the Column 130 overheads from the SRI Unit to the inlet of Column 42 as feed, in order to maintain existing production rates of commercial heptane, ULACH, and reference fuels. New piping will also be installed around Column 33 to enable the C7

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product stream to be routed to product tanks 3001/3002. This stream is normally routed to the refinery 12# header system.

3.1.7 Ancillary Changes Phillips 66 Borger Refinery may make other changes to units in the refinery in support of the Crude Flexibility and Modernization Project, including but not limited to piping routing and adding equipment leak fugitive components. Phillips 66 Borger Refinery is planning to make piping changes in the GOHDS Unit to allow the unit to process additional throughput. Phillips 66 Borger Refinery is also installing new pumps and associated piping in the Tank Farm area to enable the refinery to pump sweet naphtha from Tank 2575 and Tank 5599 to the CCR Unit when the NHT Unit is down.

In addition to piping changes, existing storage tanks may accommodate different materials based on refinery operations and crude slate and/or have increases in tank throughputs. However, there will be no physical changes to the storage tanks to accommodate any material changes. An increase in throughput and/or a tank change of service (i.e. feedstock) are not modifications under 40 CFR §52.21, 40 CFR §60.14, or 30 TAC §116.721(c) as long as the existing tanks could have physically and legally accommodated the higher throughputs and new materials. Since there are no physical changes to the tanks, and the tanks could have physically and legally accommodated the material, the tanks are not considered modified with this project.

Emission sources authorized under the existing flexible permit caps will remain subject to the flexible permit caps, which are not being increased as a result of this project. Any actual increases in emissions associated with the increased unit and tank throughputs or with changes in tank service due to crude slate variability will remain within the current flexible permit cap limits. This logic applies to any refinery emission sources authorized under the flexible permit caps that may have increased utilizations as a result of the project.

3.2 Upstream and Downstream Affects The Phillips 66 Borger Refinery is an integrated petroleum refinery. If any changes associated with the Crude Flexibility and Modernization Project result in actual emission increases from upstream or downstream unit operations, then evaluation of PSD applicability must include those actual emission increases.

According to PSD regulations, project emission increases (PEI) must include potential emission increases from new sources and sources that will be modified as part of a project. PSD guidance indicates that sources upstream and downstream of the project changes must also be evaluated for effects on actual emission rates, and these actual emissions increases must also be included in the determination of total PEI. The PEI are calculated as prescribed in Title 40 of the Code of Federal Regulations (40 CFR) §52.21 and 30 TAC §116.12(32).

3.2.1 Baseline Actual Emissions The baseline period for each PSD-regulated pollutant is determined by finding the highest consecutive 24-month emissions from the ten-year period preceding either start of construction or

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the date a complete permit application is submitted to the TCEQ. This application is being submitted to the TCEQ in March 2020; therefore, the 24-month baseline actual emissions (BAE) can be chosen between March 2010 and February 2020. As per 40 CFR 52.21(b)(48)(ii)(d) and 30 TAC §116.12(3) a different consecutive 24-month period can chosen for each regulated NSR pollutant. The selected baseline periods for each PSD-regulated pollutant are provided below.

• NOX – September 1, 2010 – August 31, 2012

• SO2 – March 1, 2010 – February 29, 2012 • CO – May 1, 2010 – April 30, 2012

• VOC and H2S – August 1, 2010 – July 31, 2012

• PM/PM10/PM2.5 – October 1, 2010 – September 30, 2012 • GHG – see Section 3.2.4

Baseline emissions for new sources with less than two (2) years of data are equal to the PTE, in accordance with 40 CFR 52.21(b)(48)(iii) and 30 TAC §116.12(3)(C).

3.2.2 Projected Actual Emissions and Potential to Emit For purposes of the PSD evaluation, projected actual emissions (PAE) for each new/modified/affected emission source are considered to be equal to the PTE. The majority of the existing emission sources associated with the Phillips 66 Borger Refinery are authorized under the flexible permit caps in Flexible Permit 9868A. The PSD evaluation includes a baseline to flexible permit cap PTE evaluation for all sources and emissions currently authorized under the flexible permit caps. The BAE from each source in the flexible permit caps are summed. The PEI for flexible permit cap sources are calculated as the difference between the proposed flexible permit cap PTE and the summed BAE. The flexible permit caps in Table D-1 in Appendix D are based on the removal of the cap contributions from sources being shut down as part of this project. Table D-2 in Appendix D provides the current authorized flexible permit caps, the current cap contributions from sources being shut down, and the new calculated flexible permit caps.

The PSD applicability evaluation also includes PEI for affected sources that are not authorized in the flexible permit caps. Table D-1 in Appendix D includes the list of new/modified/affected sources, current permit authorization, and whether the sources/emissions are included in the flexible permit cap.

Phillips 66 Borger Refinery is not requesting any increases in PTE from sources authorized in Flexible Permit 9868A (including the flexible permit caps) or NSR Permits 85872, 71385, 80799, or 155341. Phillips 66 Borger Refinery will alter Flexible Permit 9868A to lower the flexible permit caps due to removal of the contributions from the sources being shut down. This alteration request will be submitted as a separate permit action.

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3.2.3 GHG Emission Project Increases The Phillips 66 Borger Refinery does not have any current permitted GHG emission rates. The calculated GHG PTE from the new sources associated with the Crude Flexibility and Modernization Project are greater than the major modification threshold for major sources of GHG emissions alone and the project will also trigger PSD for all criteria pollutants; therefore, the project triggers PSD review for GHGs based on emissions from new sources alone. Phillips 66 Borger Refinery is complying with all GHG-related PSD permitting requirements (i.e. a BACT review), and there are no NAAQS for GHG pollutants. For purposes of simplicity, and given that existing affected sources have no GHG limits, Phillips 66 Borger Refinery is only quantifying the GHG PTE from the new emission sources.

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4 EMISSION CALCULATION METHODOLOGY

This section describes the emission calculation methodologies used to calculate the proposed hourly and annual pollutant emission rates from the new/modified sources associated with the Crude Flexibility and Modernization Project. The table below lists the new/modified sources associated with the project.

Table 4-1: List of New/Modified Sources

Process Unit Source Type EPN Source Description Pollutants Emitted

Crude Unit Process Heater 28-H3 Crude Charge VOC, NOX, CO, Heater PM/PM10/PM2.5, SO2, NH3, GHGs

Crude Unit Process Heater 28-H3 Crude Charge VOC, NOX, CO, Heater PM/PM10/PM2.5, SO2, NH3, GHGs

CCR Process Heater 88-H1 CCR Charge Heater VOC, NOX, CO, PM/PM10/PM2.5, SO2, NH3, GHGs

CCR Process Heater 88-H1 CCR 1st Stage VOC, NOX, CO, Interheater PM/PM10/PM2.5, SO2, NH3, GHGs

CCR Process Heater 88-H1 CCR 2nd Stage VOC, NOX, CO, Interheater PM/PM10/PM2.5, SO2, NH3, GHGs

CCR CCR Regeneration 88-V1 CCR Regeneration VOC, NOX, CO, SO2, HCl, Vent Vent Cl2, GHGs

Various Fugitive Piping F-CrudeFlex Fugitive Piping VOC, NH3, H2S, GHGs Components Components

CCR / MSS MSS CCR and Naphtha VOC, NOX, CO, SO2, Naphtha Splitting Unit MSS PM/PM10/PM2.5, GHGs Splitter Emissions CCR Covered Sump F- Covered Oil-Water VOC SUMPCCR Sump

4.1 Process Heater Emissions (EPNs: 28-H3, 28-H4, and 88-H1) The project includes five (5) new process heaters. The two (2) new crude charge heaters have capacities of 192.5 MMBtu/hr and are designated as EPNs: 28-H3 and 28H-4. The CCR Charge and

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Interheaters have a total capacity of 412.9 MMBtu/hr and are vented through one combined stack (EPN: 88-H1).

4.1.1 Criteria Pollutants Process heater criteria pollutant emission rates are provided in Table C-2 in Appendix C.

4.1.1.1 NOX Emissions

The crude charge and CCR heaters will be equipped with individual SCR systems for NOX emission control. Hourly and annual emissions are calculated using the design firing rate capacities and an emission factor of 0.015 lb/MMBtu on an hourly and annual average basis.

The heaters may have elevated NOX emissions during planned MSS operations, before the SCR reaches operating temperature. During this period, the hourly emissions are calculated using 75% of the design firing rate and vendor-guaranteed NOX emission factors. Annual NOX emissions from MSS are included in the normal emissions.

4.1.1.2 CO Emissions Process heater CO emissions are based on a maximum hourly concentration of 100 ppmv and an average annual concentration of 50 ppmv, both corrected to 3% excess oxygen, consistent with TCEQ presumptive BACT.

The crude charge heaters and the CCR heaters may have elevated CO emissions during planned MSS operations, due to incomplete combustion caused by lower temperatures during these operating scenarios. During this period, the hourly emissions are calculated using 75% of the design firing rate and a CO emission factor of 500 ppmv, consistent with the limitations in the TCEQ’s Air Quality Standard Permit for Boilers. Annual CO emissions from MSS are included in the normal emissions.

4.1.1.3 SO2 Emissions

Process heater SO2 emissions are based on an hourly H2S limit of 0.1 grains per dry standard cubic foot (gr/dscf) of fuel and an annual H2S limit of 0.0375 grains/dscf of fuel, which are equivalent to the short-term and annual H2S limits of 162 ppmv and 60 ppmv specified in 40 CFR Part 60, Subpart Ja.

4.1.1.4 PM and VOC Emissions PM and VOC emissions are based on emission factors from Table 1.4-2 of the United States Environmental Protection Agency’s (U.S. EPAs) AP-42 Chapter 1.4 (July 1998). Total PM is assumed to be equal to PM10 and PM2.5.

4.1.1.5 NH3 Emissions

NH3 emissions from the heaters are calculated based on an assumed 10 ppmv ammonia slip, consistent with TCEQ presumptive BACT for heaters equipped with SCR systems.

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4.1.2 Greenhouse Gas Pollutants Process heater GHG emissions are provided in Table E-2 of Appendix E.

The CO2, methane, and nitrous oxide (N2O) emissions are based on the fuel gas factors from Tables C-1 and C-2 from 40 CFR Part 98 Subpart C. The equivalency factors used to convert the CO2, methane, and N2O emissions to CO2 equivalents (CO2e) are based on Table A-1 in 40 CFR Part 98 Subpart A.

4.2 Continuous Catalytic Reformer Vent (EPN: 88-V1) Emissions from the CCR regeneration section to the atmosphere are based on an assumed regenerator flue gas flow rate of 1,644 lb/hr. The regenerator mass flow rate is converted to volumetric flow by assuming an average molecular weight of 29.97 lb/lb-mol, calculated from the estimated flue gas composition.

Emissions from the initial depressurization and purge cycle and coke burn cycle are routed to the flare gas recovery system for processing and re-use in the refinery fuel gas system. No emissions are calculated for this step in the catalyst regeneration process. The final catalyst purge removes oxygen and any remaining pollutants from the system and reduces the catalyst prior to returning the catalyst to the reaction section. Criteria pollutants, including VOC, NOX, CO, and SO2, are generated during the coke burn-off step of the regenerating process. HCl and Cl2 are produced during the catalyst coke burn-off when the water formed during combustion leaches chloride atoms from the CCR Unit catalyst.

4.2.1 Criteria Pollutants The CCR regenerator vent pollutant emission rates are detailed in Table C-3 in Appendix C. Emissions are based on the regenerator flue gas flow rate and the estimated flue gas concentrations.

4.2.2 Cl2 and HCl Pollutants The CCR regenerator vent pollutant emission rates are detailed in Table C-3 in Appendix C. Emissions are based on the regenerator flue gas flow rate and the estimated flue gas HCl and Cl2 concentrations.

4.2.3 Greenhouse Gas Pollutants The CCR regenerator GHG emission rates are detailed in Table E-3 of Appendix E. Emissions are based on the regenerator flue gas flow rate and the estimated flue gas CO2 concentration. No methane or N2O emissions are expected to be emitted from the CCR regenerator vent section.

4.3 Equipment Leak Fugitives (EPN: F-CRUDEFLEX)

4.3.1 Criteria Pollutants and Ammonia Detailed fugitive piping component emission rates are included in Table C-4 and Table C-5 in Appendix C. Fugitive emissions from equipment leaks are estimated by multiplying the number of components of each type (e.g., light liquid valve, gas/vapor valve) by the appropriate leak factor for

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each component type. Emissions are estimated using methods outlined in the TCEQ’s Air Permit Technical Guidance for Chemical Sources, Fugitive Guidance (June 2018). The Phillips 66 Borger Refinery employs the TCEQ’s 28VHP Leak Detection and Repair (LDAR) program for fugitive VOC emission control. Phillips 66 Borger Refinery will comply with the TCEQ’s 28AVO program for the new fugitive piping components in NH3 service (associated with the SCR).

Speciated emissions are based on refinery process knowledge and engineering estimates.

4.3.2 Greenhouse Gas Pollutants Detailed fugitive piping component GHG emission rates are included in Table E-5 in Appendix E and are calculated using the methods described for the criteria pollutants above. Components in natural gas service are assumed to be 95% methane by weight. The new gas/vapor components in VOC service are estimated to be 10% methane by weight.

Phillips 66 Borger Refinery will comply with the TCEQ’s 28VHP LDAR program and 28PI program for components in VOC service and natural gas service, respectively.

4.4 Planned Maintenance, Startup, and Shutdown (EPN: MSS)

4.4.1 CCR and Naphtha Splitting Units: Clearing/Degassing – Criteria Pollutants Emissions from equipment degassing are calculated by simulating, as close as possible, the actual steps associated with clearing equipment prior to turnaround.

In the first step, residual liquid is drained to the extent possible to adjacent equipment and the refinery closed drain system. There are no emissions associated with this step. After draining, it is assumed that a 0.0004-inch thick clingage layer will remain on the inside surfaces of equipment, which is consistent with a 2009 TCEQ guidance document on MSS emissions. The inside surface area is calculated based on equipment sizes quoted in the preliminary engineering design packages. Once residual liquid is removed to the extent possible, the initial pressure in the unit is vented to the FGRS or flare. The amount of initial VOC in the unit is calculated using the ideal gas law, plus the residual clingage liquid. Emissions from the initial depressure are calculated assuming an initial unit pressure of 100 psig, and a final pressure of 14.696 psia. The total amount of VOC that is vented during this initial purge is the difference between the total initial moles of VOC in the unit, minus the number of moles of vapor in the depressured equipment (at P = 14.696 psia). This scenario is denoted by purge cycle 0 in Table C-7b, and is assumed to be 100% VOC.

Once the initial depressure is complete, the remaining vapor is actively purged to the flare in a series of pressure purges, where the unit is pressured up to 20 psig with nitrogen, and then depressured to flare back down to 0 psig. The calculations are based on consistently sized and perfectly mixed purges for the sake of simplicity. The setup for the pressure purge calculations is provided in Table C-7a, and the individual pressure purges are modeled in Table C-7b.

During each purge, an estimated number of moles of pure nitrogen are added to the unit, and the same number of moles of a vapor that has progressively less VOC is vented to flare. The first purge

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is assumed to be 100% hydrocarbon, so the hydrocarbon concentration at the peak of the purge cycle, after nitrogen has been added is calculated by dividing the moles at the bottom of the pressure cycle by the moles at the peak of the cycle. This approach estimates the VOC concentration of the number moles vented to the flare during the first purge. A mass balance around the first purge is conducted in order to determine the VOC concentration in the second purge. This procedure is repeated until the hydrocarbon concentration at the start of the next purge cycle is less than BACT 10,000 ppmv, or 0.01 mole %. The hours per purge cycle are based on engineering estimates.

For each pressure purge, the flare gas heating value is calculated assuming a gross heating value of 22,000 Btu/lb. For any purges that result in a heating value of less than 270 Btu/scf, the moles of natural gas required to raise the heating value to 270 Btu/scf is calculated. The total hydrocarbon flared plus the supplemental natural gas flared are used to calculate a flare combustion heat release for each purge cycle. The NOX and CO emission rates are calculated using the emission factors for steam assisted flares from TCEQ’s Guidance Document for Flares and Vapor Oxidizers, dated October 2000. The vent gas heating value during each purge is used to identify when the low or high heating value emission factors are appropriate. The criteria pollutant totals per event are calculated by summing the emission rates from each of the individual pressure purges. Finally, once the unit reaches 10,000 ppmv, the manways can be opened and the unit can be ventilated to atmosphere. The residual VOC emissions released at this step are calculated in Table C-7a and Table C-8a, and are assumed to be released over a 10-hour period.

Criteria pollutant emission rates for the CCR and Naphtha Splitter MSS operations are provided in Tables C-6, C-7a, C-7b, C-8a, and C-8b in Appendix C.

4.4.2 CCR and Naphtha Splitting Units: Clearing/Degassing – Greenhouse Gas Pollutants GHG emissions from planned MSS-related flaring are calculated using the estimated annual average firing rates and equations from 40 CFR Part 98 Subpart Y (Equations Y-2, Y-4, and Y-5). The MSS- related GHG emissions are provided in Table E-4 in Appendix E.

4.4.3 Insignificant and Routine Equipment Maintenance Emissions estimates for the “insignificant” maintenance activities which will be listed in Attachment A and Attachment B are calculated using emission factors developed as part of the initial MSS permit application for NSR Permit 80799. Hourly and annual frequencies are adjusted since this new permit will only cover MSS emissions from the new equipment associated with the project.

Miscellaneous equipment maintenance emissions are provided in Table C-9 in Appendix C. No GHG emissions are expected from the insignificant and routine equipment maintenance.

Catalyst changeouts for the CCR Unit reactors and net gas chloride treaters are calculated in Table C-10 in Appendix C and are summed in Table C-9 in Appendix C. PM/PM10/PM2.5 emissions from loading fresh catalyst into the reactors and treaters are calculated using the estimated catalyst volume and density and equations from the U.S. EPA’s AP-42 Chapter 13.2.4 for “Aggregate

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Handling and Storage Piles.” Annual catalyst changeout emissions are based on one catalyst changeout/year.

4.5 Process Unit Sump (EPNs: F-SUMPCCR) The CCR sump emissions are based the average flow factor from for reforming processes from Table 7-8 in the April 2015 version of the “Emission Estimation Protocol for Petroleum Refineries.” The controlled VOC emission factor for oil-water separators from Table 5.1-3 from the U.S. EPA’s AP-42 Chapter 5.1 is used in the emission calculations. The calculations use the controlled emission factor due to the sump either being covered or equipped with carbon control, which complies with the applicable control technology in Table 5.1-3.

No GHG emissions are expected from the process unit sump.

Sump emissions are provided in Table C-11 in Appendix C.

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5 BEST AVAILABLE CONTROL TECHNOLOGY – CRITERIA POLLUTANTS

Pursuant to 30 TAC §116.116(a)(2)(C), a permit applicant is required to apply BACT to control emissions from new and modified sources, with consideration given to the technical practicability and economic reasonableness of reducing or eliminating emissions from the new/modified source. The TCEQ uses a three-tiered approach to evaluate the BACT proposal in NSR permit applications, which is a SIP-approved alternative to the U.S. EPA’s “top-down” BACT evaluation process. The TCEQ accepts both the “top-down” and the “Three Tier” approaches to BACT. The U.S. EPA has approved the TCEQ three tiered BACT approach as an alternative to the EPA "top-down" BACT review procedure for PSD permits issued by TCEQ when the following are considered: 1) Recently issued/approved permits within the state of Texas; 2) Recently issued/approved permits in other states; and 3) Control technologies contained within the U.S. EPA's RACT/BACT/LAER Clearinghouse (RBLC).

Phillips 66 Borger Refinery reviewed the TCEQ’s BACT determinations for the following recently issued PSD permits in Texas:

• NSR Permit No. 49138 / PSDTX1506 for the ExxonMobil Beaumont Refinery in Jefferson County, Texas (TCEQ Project Nos. 259270, 259273, and 259291, Issued January 9, 2018) – also included in RBLC • NSR Permit 6825A / PSDTX49M1 for the Valero Port Arthur Refinery in Jefferson County, Texas (TCEQ Project No. 266018, Issued September 14, 2018) – also included in RBLC • NSR Permit No. 47256 / PSDTX402M4 for the Marathon Galveston Bay Refinery in Galveston County, Texas (TCEQ Project No. 264194. Issued November 30, 2018)3 – NOT included in RBLC

Control technologies for recently issued permits in states outside of Texas are also included in the RBLC tables in Appendix B.

The TCEQ’s three-tiered process works as follows. In the first tier, the BACT proposal is compared to the emission reduction performance levels accepted as BACT in recent NSR permit reviews for the same process and/or industry (as identified by the Standard Industrial Classification [SIC] code or the North American Industrial Classification System [NAICS] code). The TCEQ has established Tier I BACT requirements for multiple industry types, including for refineries. Tier I BACT requirements are provided for each new/modified source in the General PI-1 form in Appendix A.

3 The Marathon Galveston Bay Refinery is located in an ozone non-attainment area; therefore, this site is subject to more stringent control requirements, including Lowest Achievable Emission Rate (LAER) and selected control technologies may not be applicable to the Phillips 66 Borger Refinery.

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The second tier takes into account controls that have been accepted as BACT in recent permits for similar facilities in a different process or industry. The third tier of the TCEQ BACT approach consists of a detailed technical and economic analysis of all control options available for the process under review.

The Crude Flexibility and Modernization Project triggers PSD review for criteria and GHG pollutants. The BACT evaluation for GHG pollutants is provided in Section 6.

The following table provides the list of sources for which a BACT evaluation is conducted.

Table 5-1: BACT Summary

Source Type EPN Source Pollutant Federal BACT State BACT Description Required? Required?

Process Heater 28-H3 Crude Charge VOC Yes Yes Heater NOX Yes Yes CO Yes Yes

SO2 Yes Yes PM Yes Yes

NH3 No Yes Process Heater 28-H3 Crude Charge VOC Yes Yes Heater NOX Yes Yes CO Yes Yes

SO2 Yes Yes PM Yes Yes

NH3 No Yes Process Heater 88-H1 CCR Charge and VOC Yes Yes Inter-stage NOX Yes Yes Heaters CO Yes Yes

SO2 Yes Yes PM Yes Yes

NH3 No Yes

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Source Type EPN Source Pollutant Federal BACT State BACT Description Required? Required?

CCR 88-V1 CCR Regeneration Cl2 No Yes Regeneration Vent HCl No Yes Vent NOX Yes Yes CO Yes Yes

SO2 Yes Yes VOC Yes Yes Fugitive Various New Fugitive VOC Yes Yes Piping Piping H2S Yes Yes Components Components NH3 No Yes MSS MSS CCR and Naphtha VOC Yes Yes Splitting Unit NOX Yes Yes MSS Emissions CO Yes Yes PM Yes Yes

SO2 Yes Yes Covered F- New CCR Sump VOC Yes Yes Sumps SUMPCCR

The following sections address BACT for each source and pollutant.

5.1 Process Heaters (EPNs: 28-H3, 28-H4, and 88-H1) There will be five (5) new heaters installed as part of this project. RBLC search results associated with process heaters and other similar sources are provided in Table B-1 in Appendix B. The Crude Charge Heaters have firing rates of 192.5 MMBtu/hr each and will vent through individual stacks. The CCR Unit Heaters have a combined firing rate of 412.90 MMBtu/hr and will vent through one stack.

5.1.1 NOX

NOX emissions from heaters primarily occur from the reaction of nitrogen and oxygen in the combustion air and from the early reactions of nitrogen molecules in the combustion air and hydrocarbon radicals from the fuel. NOX formation can be minimized by using a proper air-to-fuel ratio and by optimizing combustion zone temperature and residence time.

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Phillips 66 Borger Refinery conducted a search of the RBLC for BACT determinations for heaters and boilers and reviewed those with firing rates greater than 100 MMBtu/hr and less than 500 MMBtu/hr.

A search of the RBLC showed the following control methods for NOX for heaters of these sizes:

• ULNB; • LNB; • Firing low-BTU fuel gas; and • SCR.

Additionally, SCR was also the selected NOX control technology for new heaters from the recently issued NSR Permit No. 47256 for the Marathon Galveston Bay Refinery. The heaters equipped with SCR had the lowest emission factors on a lb/MMBtu basis.

TCEQ’s Tier I BACT for NOX is burners with the best NOX performance given the burner configuration and gaseous fuel used. Justification must be provided if the emission factor is greater than 0.01 lb/MMBtu.

The 0.01 lb/MMBtu emission factor is based on a heater firing natural gas. The new Crude Charge Heaters and CCR heaters will primarily fire refinery fuel gas, which has a slightly different makeup and is more variable than natural gas. TCEQ has accepted 0.015 lb/MMBtu as Tier I BACT for heaters that fire refinery fuel gas.

SCR, an annual average NOX limit of 0.015 lb/MMBtu, and CEMS are considered BACT for new heaters of this size.

5.1.2 CO and VOC CO and VOC emissions from process heaters occur due to incomplete combustion. Utilizing proper operation and combustion techniques (e.g., appropriate air-to-fuel ratios and combustion chamber residence times) for the process heaters results in more complete combustion and a decrease in the formation of CO and VOC. A search of the RBLC showed the following control methods for CO and VOC:

• Good combustion practices; • Firing gaseous fuels; and • Compliance with the tune-up provisions of 40 CFR Part 63 Subpart DDDDD.

No add-on control technologies for CO and VOC were identified in the RBLC search or in a review of the TCEQ’s Preliminary Determination Summary (PDS) for the recently issued NSR Permit No. 47256 for the Marathon Galveston Bay Refinery. TCEQ’s Tier I BACT for CO is limiting the flue gas CO concentration to 50 ppmvd, corrected to 3% O2, on an average annual basis. TCEQ’s Tier I BACT

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for VOC is firing pipeline quality natural gas and following good combustion practices. The heaters will be fired with either pipeline quality natural gas or refinery fuel gas, which is similar to pipeline quality natural gas in terms of VOC emissions.

Phillips 66 Borger Refinery proposes that BACT for CO and VOC is good combustion practices, a flue gas CO limitation of 50 ppmvd at 3% O2 on an annual average basis, and compliance with the applicable requirements of 40 CFR Part 63 Subpart DDDDD.

The new heaters will be also equipped with CO CEMS for purposes of monitoring and compliance.

5.1.3 SO2

SO2 emissions from heaters are a direct result of the fuel gas sulfur content. The new heaters will be fired using sweet natural gas or refinery fuel gas and will be subject to the emission limitation and monitoring requirements of 40 CFR Part 60 Subpart Ja. A search of the RBLC showed the following control methods for SO2:

• Good combustion practices; • Firing low-sulfur gaseous fuels; and • Compliance with NSPS Ja emission limitations.

No add-on control technologies for SO2 were identified in the RBLC search or in the TCEQ’s PDS for the recently issued NSR Permit No. 47256 for the Marathon Galveston Bay Refinery. The SO2 emissions from the new heaters are a function of the H2S content in the refinery fuel gas. TCEQ’s Tier I BACT for “plant fuel gas” is “H2S: 0.1 gr/dscf or 160 ppmv max short term, 80 ppmv max annually”.

The new heaters will primarily be fired with refinery fuel gas. 40 CFR Part 60 Subpart Ja limits the fuel gas H2S content to 162 ppmv on a rolling 3-hour basis and 60 ppmv on an annual average basis. The annual average H2S limitation under 40 CFR Part 60 Subpart Ja is more stringent than TCEQ’s Tier I BACT for plant fuel gas. Therefore, Phillips 66 Borger Refinery proposes that BACT for SO2 is use of sweet natural gas or refinery fuel gas and compliance with the emission limitations and monitoring requirements of 40 CFR Part 60 Subpart Ja.

5.1.4 PM/PM10/PM2.5

PM/PM10/PM2.5 emissions from heaters occur from inert solids in the fuel gas and combustion air and from unburned fuel hydrocarbons that form solids in the heater stack. Utilizing proper operation and combustion techniques (e.g., appropriate air-to-fuel ratios and combustion chamber residence times) for the process heaters results in more complete combustion, which results in a decrease in the formation of PM/PM10/PM2.5. A search of the RBLC showed the following control methods for PM/PM10/PM2.5:

• Good combustion practices; and • Firing gaseous fuels.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 5-5 No add-on control technologies for PM/PM10/PM2.5 were identified in theC s RBL earch or in the TCEQ’s PDS for the recently issued NSR Permit No. 47256 for the Marathon Galveston Bay Refinery. TCEQ’s Tier I BACT for PM/PM10/PM2.5 is limiting opacity to 5%.

Phillips 66 Borger Refinery proposes that TBAC for PM/PM 10/PM2.5 is good combustion practices and firing either refinery fuel gas or pipeline quality sweet natural gas. Phillips 66 Borger Refinery will also comply with the applicable opacity limitations in 30 TAC §111.111.

5.1.5 NH3

NH3 emissions from process heaters occur as a result of “ammonia slip” from SCR systems, which is unreacted NH3 exiting in the flue gas. NH3 is not a regulated pollutant under the PSD permitting program. However, a search of the RBLC showed the following control method for NH3 emissions: flue gas NH3 concentration limitation of 10 ppmvd at 3% O2.

No add-on control technologies for NH3 were identified in the RBLC search. TCEQ’s Tier I BACT for NH3 is limiting the flue gas NH3 concentration limitation to 10 ppmvd at 3% O2. The Tier I BACT is based on “boilers greatera th n 40 MMBtu/hr firing liquid or gaseous fuels,” and there is no Tier I BACT for NH3 listed for “process heaters”.

Phillips 66 Borger Refinery proposes that limiting the SCR ammonia slip to 10 ppmvd at 3% O2 on an annual a verage basis meets BACT.

5.2 CCR Regeneration Vent (EPN: 88-V1)

The CCR regenerating process results in emissions of VOCs, CO, SO2, and NOX, which are regulated under the federal PSD permitting program, as well as Cl2 and HCl, which are only regulated by state BACT requirements.

A search of the RBLC rfo process t ype: “Petroleum Refining Conversion Process (cracking, reforming, etc.)” with SIC dCo e: 2911 showed one draft determination fro a CCR regeneratio n vent (RBLC :ID TX-0874) and one final determination for a CCR regeneration vent (RBLC ID: LA-0326). The RBLC search was expanded outside of SIC Code 2911 to search for “Process Contains: Catalyst”. The relevant results of the RBLC search are included in Table B-5 in Appendix B.

5.2.1 VOC, CO, SO2, Oand N X The catalyst regenerating process of a CCR continuously pulls a small slip stream of catalyst from the CCR reaction section for regenerating. In the catalyst regenerator, coke is removed from the catalyst by oxidation. Combustion emissions (VOC, CO, SO2, and NOX) are generated by the catalyst coke-burn off process.

The following control technologies are listed in the RBLC search results:

• Proper operating technique to limit number of events; and

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• Good combustion practices to reduce VOC, including maintain proper air-to-fuel ratio, necessary residence time, temperature and turbulent. White Burn Mode. The CCR regenerating process is continuous; therefore, it is not technically feasible to operate the CCR Unit to “limit the number of events.” However, it is technically feasible to implement good combustion practices to minimize emissions. Therefore, this control technique will be further considered in the BACT evaluation.

The TCEQ has not established Tier I BACT requirements for CCR regeneration vents. However, there are control requirements for CCR regeneration vents in 40 CFR Part 63 Subpart UUU. The total organic compound (TOC) emissions from the initial catalyst purging and coke-burn off steps will be controlled by one of the following methods, in accordance with Table 15 of 40 CFR Part 63 Subpart UUU:

• Vented to a flare that meets the requirements of 40 CFR §63.670 or will be reduced by 98% by weight; or • Reduced by 98% or limited to an outlet concentration of 20 ppmv (dry basis, as hexane) from an approved control device.

Phillips 66 Borger Refinery proposes the following control methods to minimize combustion emissions from the CCR regeneration vent:

• Route emissions from the initial catalyst purging and coke-burn off steps to a flare or control device, as required by 40 CFR Part 63 Subpart UUU; • Comply with the monitoring, testing, recordkeeping, and reporting requirements of 40 CFR Part 63 Subpart UUU; and • Develop and implement operating and maintenance plans incorporating manufacturer's recommendations to minimize coke formation and ensure good combustion.

Phillips 66 Borger Refinery constitutes that compliance with the above items meets Tier II BACT for combustion emissions from CCR catalyst regenerating activities.

5.2.2 HCl and Cl2

HCl and Cl2 emissions are produced during the catalyst coke burn-off when the water formed during combustion leaches chloride atoms from the CCR Unit catalyst.

The following control technology for HCl emissions is listed in the RBLC search result: Vent Scrubber with continuous emission monitoring system (CEMS).

The control technology listed above is for a “propane dehydrogenation unit”, associated with SIC Code 2869. The TCEQ has not established Tier I BACT requirements for CCR regeneration vents.

There are control and monitoring requirements for CCR regeneration vents in 40 CFR Part 63 Subpart UUU. The inorganic hazardous air pollutant (HAP) emissions (in which HCl is regulated

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as a surrogate) are required to be controlled as follows: Reduce the uncontrolled HCl emissions by 97% by weight or to an outlet concentration of 10 ppmv (dry basis, 3% O2).

The CCR regenerating vent flue gas will be routed to an add-on scrubber control device to reduce emissions of HCl, as required by 40 CFR Part 63 Subpart UUU.

Phillips 66 Borger Refinery proposes the following control methods to minimize HCl and Cl2 emissions from the CCR regeneration vent:

• Route emissions to an add-on scrubbing system to reduce HCl emissions to the level required by 40 CFR Part 63 Subpart UUU; • Comply with the monitoring, testing, recordkeeping, and reporting requirements of 40 CFR Part 63 Subpart UUU; and • Develop and implement operating and maintenance plans incorporating manufacturer's recommendations to minimize coke formation and ensure good combustion.

Phillips 66 Borger Refinery constitutes that compliance with the above items meets BACT for combustion emissions from CCR catalyst regenerating activities

5.3 Fugitive Piping Components (EPN: F-CrudeFlex) Leaking process equipment, including piping, valves, pumps, compressors, etc., can result in emissions of VOCs, H2S, and NH3. Fugitive emissions of NH3 occur due to use of anhydrous ammonia for the SCR systems. Fugitive emissions of VOC and H2S occur due to typical refinery process streams, which are primarily comprised of VOC with a small amount of H2S impurity.

Fugitive emissions are controlled by installing equipment that is designed to minimize leaks and by employing an LDAR program, which is considered a work-practice standard. Equipment leaks are reduced by LDAR programs as a result of regular inspections of piping components. Inspections can include Method 21 monitoring using a TVA (or equivalent), infrared cameras, and audio, visual, and olfactory (AVO) leak indications. If a leak is detected, then the leak must be repaired as prescribed in the applicable LDAR program and/or federal regulatory requirements.

The RBLC entries for fugitive emissions control are provided in Table B-2 in Appendix B.

5.3.1 VOC and H2S

A search of the RBLC showed the following control method for VOC and H2S emissions from fugitive piping components: compliance with various LDAR programs.

TCEQ’s Tier I BACT for VOC emissions from fugitive piping and equipment leaks is compliance with the 28VHP LDAR program (for sites that have uncontrolled VOC emissions > 25 tpy). There is one final determination on the RBLC search that shows a more stringent LDAR program than 28VHP, which is 28MID and is associated with RBLC ID TX-0760.

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Per the TCEQ’s Air Permit Technical Guidance for Chemical Sources “Fugitive Guidance” (APDG 6422, June 2018), 28MID was developed to address off-property impact problems associated with fugitive emissions from specific compounds. 28MID is the most stringent voluntary program and required directed maintenance. Additionally, a review of the TCEQ technical summary for this project (TCEQ Project No. 219294) indicates that the use of the 28MID program exceeded BACT.

The majority of the RBLC results showed 28VHP to be BACT for control of VOC, which also meets TCEQ’s Tier I BACT requirements. Phillips 66 Borger Refinery proposes that BACT for VOC emissions from fugitive piping components is complying with the TCEQ’s 28VHP LDAR program and any applicable federal requirements, including 40 CFR Part 60 Subpart GGG/GGGa and 40 CFR Part 63 Subpart CC.

TCEQ’s Tier I BACT for fugitive piping components in inorganic service (including H2S) is an AVO program, which requires AVO inspections not less than once per shift. The H2S emissions from the new fugitive piping components are based on estimated stream speciation, and the material is mostly comprised of VOC. H2S is only present as an impurity. The process units where the new fugitive piping components are going to be installed do not have any AVO requirements associated with H2S emissions from fugitive piping components; therefore, Phillips 66 Borger Refinery proposes that BACT for H2S emissions from fugitive piping components is complying with the TCEQ’s 28VHP LDAR program and any applicable federal requirements, including 40 CFR Part 60 Subpart GGG/GGGa and 40 CFR Part 63 Subpart CC.

5.3.2 NH3

A search of the RBLC did not show any control methods for NH3 emissions from fugitive piping components. Additionally, there are no federal regulations that govern NH3 emissions from fugitive piping components at petroleum refineries. The TCEQ’s Tier I BACT for components in inorganic service (including NH3) is utilization of the TCEQ’s 28AVO program, which requires AVO inspections not less than once per shift. Phillips 66 Borger Refinery proposes that BACT for NH3 emissions from fugitive piping components is complying with the TCEQ’s 28AVO program and performing AVO inspections once per shift.

5.4 Planned MSS Activities (EPN: MSS)

Planned MSS activities include emissions of VOC, NOX, CO, SO2, and PM/PM10/PM2.5 from equipment opening and degassing, catalyst changeout, and heater startups and shutdowns. A search of the RBLC showed the following control methods for planned MSS activities and emissions:

• Route process equipment degassing emissions to a flare meeting the requirements of 40 CFR 60.18; • Minimize frequencies and durations; and • Control equipment degassing until VOC concentration in equipment is less than 10,000 ppmv (or equivalent).

The RBLC entries for planned MSS activities are provided in Table B-3 in Appendix B.

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5.4.1 Equipment Maintenance and Process Unit Startup/Shutdown The methods of control identified in the RBLC are equivalent to TCEQ’s established Best Management Practices (BMPs) for planned MSS activities. Equipment containing lighter or gaseous materials with vapor pressures greater than 0.5 psia at 95°F will be depressured and degassed to control, consistent with the requirements in TCEQ’s “Draft MSS Model Permit” (April 2011). Larger equipment, such as vessels and heat exchangers, will be monitored prior to opening the equipment to atmosphere to ensure the VOC concentration is not greater than 10,000 ppmv (or equivalent). Any residual liquids will be drained to a closed system or will be transferred to a closed system within two hours. Potential control devices include the refinery FGRS and flare and other portable control devices such as thermal oxidizers, carbon adsorption systems, etc.

The main refinery flares at the Phillips 66 Borger Refinery are equipped with FGRS, which reduce the amount of flaring since the gases can be compressed and then sent to treating units for future use as refinery fuel gas. However, FGRS are typically designed to capture and compress waste gases generated during normal operation. Due to the nature of MSS events (high short-term flows, streams with high nitrogen content, etc.), the FGRS may be intentionally bypassed or over- pressured, resulting in waste gas flaring. Phillips 66 Borger Refinery will utilize work practice standards to minimize the amount of flaring from planned MSS activities. The main flares at the Phillips 66 Borger Refinery also comply with the requirements of 40 CFR §63.670 to maximize complete combustion.

Phillips 66 Borger Refinery proposes that complying with TCEQ’s BMPs and 40 CFR Part 63 Subpart CC for flares and maintenance vents and minimizing events and event durations constitutes BACT for equipment maintenance and process unit startups and shutdowns.

5.4.2 Process Heater Startup/Shutdown Phillips 66 Borger Refinery will minimize heater startups and shutdowns to the extent practical. The NOX emissions during startup and shutdowns will be based on vendor guaranteed emissions factors of 0.044 lb/MMBtu for the Crude Charge Heaters and 0.03 lb/MMBtu for the CCR heaters.

Process heater CO emissions occur from incomplete combustion due to the low combustion chamber temperature as the heaters are being started up or shut down. Phillips 66 Borger Refinery will comply with a flue gas CO concentration limit of 500 ppmv on an hourly average basis during startups and shutdowns. The CO limitation is based on the TCEQ’s “Air Quality Standard Permit for Boilers.”

Phillips 66 Borger Refinery proposes that meeting the aforementioned emissions limitations and minimizing event frequency and event duration constitutes BACT for process heater startups and shutdowns.

5.5 Wastewater Collection (EPN: F-SUMPCCR) VOC emissions can occur from new process drains, sumps, and other pieces of the wastewater collection system which will be installed in the new refinery process units. Phillips 66 Borger Refinery is not planning to make any modifications to the existing WWTP, which includes oil-water

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separators, Dissolved Air Floatation (DAF) tanks, biological treatment units, etc. However, new wastewater collection system components will be installed in the CCR and Naphtha Splitter Units. The new wastewater collection system components will be designed with the following key parameters, which establish BACT.

• All process wastewater sewers will be enclosed (e.g., no trenches or other open conveyance systems). • Each process drain will be equipped with a water seal, cap, or plug as appropriate, depending on the intended nature and frequency of use for each drain. • Manholes, junction boxes, and sumps will be equipped with sealed covers and any associated vent pipes will be designed consistent with either 40 CFR Part 60 Subpart QQQ or 40 CFR Part 61 Subpart FF standards.

A search of the RBLC for sumps and other applicable wastewater treatment plant facilities showed the following control technologies:

• Good housekeeping practices; • Closed top design; • Use of water seals or p-traps; • Venting to a carbon adsorption system (CAS); and • Venting to flare.

The TCEQ does not have established Tier I BACT for individual components of a wastewater collection system, like process drains and sumps. Phillips 66 Borger Refinery proposes that BACT for the new wastewater collection components is compliance with federal wastewater regulations, as specified in 40 CFR Part 60 Subpart QQQ and 40 CFR Part 61 Subpart FF.

The RBLC entries for wastewater treatment and collection are provided in Table B-4 in Appendix B.

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6 BEST AVAILABLE CONTROL TECHNOLOGY – GREENHOUSE GAS POLLUTANTS

The 1977 Clean Air Act (CAA) Amendments established requirements for the approval of pre- construction permit applications under the PSD program. 30 TAC §116.164(a) states that projects with increases in GHG emissions do not require a PSD applicability evaluation for GHGs unless the project requires PSD review for a pollutant other than GHGs. The Crude Flexibility and Modernization Project triggers a PSD review for all criteria pollutants; therefore, a GHG PSD applicability evaluation is required. The project emission increases exceed the major modification threshold for GHG emissions (or 75,000 tpy of CO2e); therefore, a GHG PSD review is required. A BACT analysis is required for each applicable new or modified emission source.

The proposed BACT for all emission sources was established after completing a Tier I review, as was determined by review and knowledge of U.S. EPA- issued GHG permits addressing BACT, TCEQ- issued GHG permits addressing BACT, and review of the RBLC. Based on the research detailed above, carbon capture and sequestration technology was not required or implemented for any projects with similar sized combustion sources; therefore, sequestration was not considered with the proposed tiered BACT analyses.

6.1 Process Heaters (EPNs: 28-H3, 28-H4, and 88-H1) Virtually all GHG emissions from fuel combustion result from the complete conversion of the carbon in the fuel to CO2; however, methane emissions are possible if incomplete combustion occurs. Fuels used in industrial processes and power generation typically include coal, fuel oil, natural gas, and process fuel gas. A search of the RBLC and a review of BACT determinations in GHG permits issued by both TCEQ and the U.S. EPA in Texas showed the following control methods for GHG emissions.

• Use of low carbon fuel, including natural gas and refinery fuel gas • Minimum thermal efficiency between 80-87% (PSD-TX-1342-GHG, PSD-TX-861-GHG and GHGPSDTX167) • Good combustion, operating and maintenance practices, which may entail:

o Use of appropriate materials of construction o Proper insulation on the heater and piping o Instrumentation to monitor flue gas oxygen content, combustion air flow, fuel consumption, and flue gas temperature

o Maintenance and calibration of instrumentation according to the manufacturer’s recommendations • Conduct tune-ups as required by 40 CFR Part 63 Subpart DDDDD

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Phillips 66 Borger Refinery proposes to burn refinery fuel gas and/or natural gas in the new process heaters. Refinery fuel gas contains less methane and more hydrogen and ethane than natural gas. Table C-1 in 40 CFR Part 98 Subpart C, provides a default emission factor of 59.00 kg CO2/MMBtu for fuel gas, which is only slightly above that of natural gas, which has a default emission factor of 53.06 kg CO2/MMBtu. The refining process units generate off-gases which are compressed and sweetened in treating units to be used as refinery fuel gas. If the refinery fuel gas is not used as fuel for heaters and other combustion sources, it would be burned in the flare system and released to atmosphere, which is not considered practical for purposes of emission reduction and control.

Phillips 66 Borger Refinery reviewed all the fuels listed in Table C-1 in 40 CFR Part 98 Subpart C, and the only fuels with lower default CO2 factors than fuel gas and natural gas are coke oven gas, landfill gas, and biomass gases, with default CO2 factors of 46.85 kg/MMBtu, 52.07 kg/MMBtu, and 52.07 kg/MMBtu, respectively. These fuels are not available at the refinery to be burned as fuel gas; therefore, burning these gases is considered to be technically infeasible.

In addition to burning refinery fuel gas and natural gas in the heater, Phillips 66 Borger Refinery will purchase heaters with a minimum thermal efficiency design of least 80%, develop and implement procedures to ensure good combustion practices are followed and the heater is operated and maintained properly, and conduct tune-ups as required by 40 CFR Part 63 Subpart DDDDD. The proposed heater design and work practices satisfy Tier I BACT.

The RBLC entries for process heater controls are provided in Table B-1 in Appendix B.

6.2 CCR Regeneration Vent (88-V1) A search in the RBLC database for Continuous Catalytic Reformers and a review of BACT determinations in GHG permits issued by both TCEQ and EPA in Texas was conducted and no CCR Regeneration Vents were found. The search was expanded to “Reformers”, which included steam methane reformers, hydrogen reformers and unspecified reformers and revealed the following BACT determinations.

• Energy efficient measures. • Use of low carbon fuels. • Good engineering practices. • The C3/C4 Hydrogenation Reactor shall be operated such that coke formation is minimized. • Feed a C3/C4 distillate and a purified hydrogen stream to minimize contaminants and catalyst fouling. • Load with hydrogenation catalyst per catalyst supplier recommendations. • Maintain reactor temperatures, pressures, and hydrogen concentrations within recommended levels.

CO2 emissions from the CCR Regeneration vent are a direct result of burning coke that has deposited on the catalyst as a normal part of the CCR operation; therefore, proper design and

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 6-2

operation of the CCR is important in minimizing the formation of coke on the catalyst. Phillips 66 Borger Refinery proposes to develop and implement operating and maintenance plans incorporating the manufacturer’s recommendations for operating conditions including, but not limited to, temperatures, pressures, and concentrations to minimize coke formation, as well as instrument and equipment checks and calibrations. Phillips 66 Borger Refinery uses reduction hydrogen from the reaction section to limit additional hydrocarbons in the chamber, which would combust into additional CO2 emissions; therefore, Phillips 66 Borger Refinery is using low carbon fuel. Phillips 66 Borger Refinery will also use the catalyst specified by the manufacturer. These engineering design and work practice requirements satisfy Tier II BACT.

6.3 Fugitive Piping Components (EPN: F-CrudeFlex) A search in the RBLC database fugitive emissions from petroleum liquids, fuel gas, and natural gas and a review of BACT determinations in GHG permits issued by both TCEQ and U.S. EPA in Texas showed the following requirements.

• LDAR program required for components in VOC service has consistently been applied to meet BACT for reduction of CH4 emissions. • Weekly AVO inspections for detecting leaking in natural gas piping components. • Use of high-quality components and materials of construction that are compatible with the service in which they are employed.

Phillips 66 Borger Refinery will employ the TCEQ 28VHP LDAR program to monitor the new project fugitive emission sources in VOC service, a weekly AVO for components in natural gas service, and use high quality materials of construction that are compatible with the service in which they are employed. Compliance with these LDAR programs satisfies Tier I BACT. The RBLC entries for fugitive emissions control are provided in Table B-2 in Appendix B.

6.4 Planned MSS Activities (EPN: MSS)

Planned MSS activities include emissions of methane, N2O and CO2 from flaring. Methane emissions from the flare occur due to incomplete combustion. Methane has a higher global warming potential (GWP) factor than CO2; therefore, it is preferable to employ engineering design and work practices to ensure complete combustion, even if CO2 emissions increase as a result. A search of the RBLC showed the following control methods for planned MSS activities and emissions:

• Route process equipment degassing emissions to a flare meeting the requirements of 40 CFR §60.18; and • Minimize frequencies and durations.

The RBLC entries for planned MSS activities are provided in Table B-3 in Appendix B.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 6-3

6.4.1 Equipment Maintenance and Process Unit Startup/Shutdown The methods of control identified in the RBLC are equivalent to TCEQ’s established Best Management Practices (BMPs) for planned MSS activities. Additionally, the main refinery flares at the Phillips 66 Borger Refinery are also equipped with FGRS, which reduce the amount of flaring since the gases can be compressed and then sent to treating units for future use as refinery fuel gas. However, FGRS are typically designed to capture and compress waste gases generated during normal operation. Due to the nature of MSS events (high short-term flows, streams with high nitrogen content, etc.), the FGRS may be intentionally bypassed or over-pressured, resulting in waste gas flaring. Phillips 66 Borger Refinery will utilize work practice standards to minimize the amount of flaring from planned MSS activities.

Phillips 66 Borger Refinery will comply with the requirements of 40 CFR §63.670 for the refinery flare systems to ensure complete combustion. Phillips 66 Borger Refinery will also comply with the requirements in Special Condition 12 of TCEQ’s “Draft MSS Model Permit” (April 2011) for any temporary control devices used in support of planned MSS activities.

Phillips 66 Borger Refinery proposes that complying with TCEQ’s BMPs and 40 CFR Part 63 Subpart CC for flares and minimizing events and event durations constitutes BACT for planned MSS-related flaring.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 6-4

7 REGULATORY APPLICABILITY

Pursuant to 30 TAC §116.111 and §116.311, Phillips 66 Borger Refinery will continue to meet all rules and regulations of the TCEQ, the requirements of this permit, and the intent of the Texas Clean Air Act (TCAA) for the emission sources and activities addressed in this permit application, as follows: • §116.111(a)(1) – A completed General Form PI-1 has been authorized by a representative of Phillips 66 and is included in Appendix A. The signature page, with an original signature from the Phillips 66 responsible official is being mailed to the TCEQ. • §116.111(a)(2)(A) through (L) – These items are addressed individually below. • §116.111(b) – Phillips 66 will comply with applicable 30 TAC 39 and 30 TAC 55 public notice and public participation requirements for this initial permit application.

7.1 General Application Requirements – §116.111(a)(2)(A) The emissions associated with the units described in this initial permit application will comply with all applicable air quality rules and regulations and with the intent of the TCAA, including protection of the health and the physical property of the people, as required by 30 TAC §116.111(a)(2)(A)(i). Following is a summary of rules and regulations as they apply to the proposed project: • 30 TAC Chapter 101 - General Rules: Phillips 66 will continue to operate on-site facilities in accordance with the General Rules relating to circumvention, nuisance, traffic hazard, sampling, sampling ports, emissions inventory requirements, and sampling procedures and terminology. Phillips 66 will also continue to comply with U.S.EPA Standards, the National Primary and Secondary Air Quality Standards, inspection fees, emissions fees, and all other applicable General Rules. • 30 TAC Chapter 111 - Visible Emissions and Particulate Matter: The operation of refinery facilities may result in visible emissions, but not in excess of the opacity limits specified in §111.111. The new and modified emission sources will comply with any applicable provisions of 30 TAC Chapter 111. • 30 TAC Chapter 112 - Sulfur Compounds: For Hutchinson County, the net ground level concentration of sulfur dioxide (SO2) is limited to 0.4 part per million by volume (ppmv) averaged over any 30-minute period. Phillips 66 Borger Refinery will provide air dispersion modeling to demonstrate compliance with the 30 TAC Chapter 112 net ground level concentration standards. • 30 TAC Chapter 113 - Toxic Materials: Phillips 66 Borger Refinery will comply with all applicable requirements of 40 CFR Part 63. Applicable subparts include 40 CFR Part 63 Subparts A, CC, UUU, and DDDDD. • 30 TAC Chapter 114 - Motor Vehicles: There are no motor vehicles specifically associated with the sources included in this application. To the extent that motor vehicles are owned by Phillips 66, the company will continue to comply with applicable requirements in Rule §114.20. • 30 TAC Chapter 115 - Volatile Organic Compounds: The requirements of Chapter 115 are not applicable to sources in Hutchinson County; therefore, this rule does not apply.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 7-1

• 30 TAC Chapter 116 - Permits for New Construction or Modification: This initial NSR permit application is submitted to comply with Chapter 116 permitting requirements. • 30 TAC Chapter 117 - Nitrogen Compounds: The requirements of Chapter 117 are not applicable to sources in Hutchinson County; therefore, this rule does not apply. • 30 TAC Chapter 118 - Air Pollution Episodes: Hutchinson County is not a designated county under Chapter 118; therefore, this rule does not apply. • 30 TAC Chapter 122 - Federal Operating Permits (FOPs): Phillips 66 Borger Refinery complies with this regulation as required. Phillips 66 Borger Refinery will submit an initial application for a new SOP to authorization operation of sources associated with the Crude Flexibility and Modernization Project.

Emissions Measurement - §116.111(a)(2)(B)

Emissions will be sampled upon request of the TCEQ.

Best Available Control Technology - §116.111(a)(2)(C)

Sections 5 and Section 6 of this application present BACT discussions.

New Source Performance Standards (NSPS) - §116.111(a)(2)(D)

Phillips 66 Borger Refinery will comply with all applicable NSPS standards, including 40 CFR Part 60 Subparts A, GGG/GGGa, Ja, and QQQ.

National Emission Standards for Hazardous Air Pollutants (NESHAP) - §116.111(a)(2)(E)

Phillips 66 will comply with all applicable NESHAPS standards, including 40 CFR Part 61 Subparts A and FF.

Maximum Achievable Control Technology (MACT) - §116.111(a)(2)(F)

Phillips 66 will comply with all applicable MACT standards, including 40 CFR Part 63 Subparts A, CC, UUU, and DDDDD.

Performance Demonstration - §116.111(a)(2)(G)

The sources and activities to be permitted as part of the initial permit are expected to perform as represented in this application.

Non-attainment New Source Review §116.111(a)(2)(H)

The site is not located in a nonattainment county; therefore, the site is not subject to an NSR nonattainment review.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 7-2

Prevention of Significant Deterioration - §116.111(a)(2)(I)

Phillips 66 Borger Refinery is considered a major source under the PSD program. The PSD permitting evaluation is provided in Section 1 of this application.

Air Dispersion Modeling - §116.111(a)(2)(J)

See Appendix F for the TCEQ’s EMEW for the project. The EMEW is being submitted to cover emissions from non-PSD-regulated pollutants (e.g., health effects and state property line reviews). The detailed modeling protocol and modeling report for the PSD pollutants will be submitted under separate covers.

FCAA §112(b) Hazardous Air Pollutants - §116.111(a)(2)(K)

The proposed permit will not include any new construction or reconstruction of any existing equipment subject to the Federal Clean Air Act (FCAA) §112(g).

Mass Cap and Trade Allowances - §116.111(a)(2)(L)

Phillips 66 Borger Refinery is not subject to the Mass Emissions Cap and Trade Program under 30 TAC Chapter 101, Subchapter H, Division 3.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 7-3

8 AIR QUALITY ANALYSIS

The Crude Flexibility and Modernization Project results in emissions from new sources and emission increases from modified existing sources. Therefore, an air quality analysis is required. For projects that trigger PSD review, the initial permit application must include the PSD Modeling Protocol for PSD-regulated pollutants. The purpose of the modeling protocol is to detail the proposed approach to demonstrate compliance with all applicable air quality analysis requirements. The PSD modeling protocol is provided under a separate cover.

The project also results in emission increases of pollutants not regulated under the PSD program. Therefore, the TCEQ’s EMEW is provided in Appendix F, with the results of the non-PSD pollutant air quality analysis. A summary of the modeling results for non-PSD pollutants is provided below.

Table 8-1: Summary of Modeling Results (Non-PSD)

Pollutant Federal PSD Minor NAAQS State Health Review1 Review Property Effects Line2 Review2 See Federal Nitrogen Oxides (NO2) TBD -- -- PSD See Federal CO TBD -- -- PSD See Federal Coarse Particulates (PM10) TBD -- -- PSD See Federal Fine Particulates (PM2.5) TBD -- -- PSD See Federal Passes SO2 TBD -- PSD Project-Level See Federal Ozone (O3) TBD -- -- PSD Passes H2S ------Project-Level Passes MERA Crude Oil ------Step 3 Light Petroleum Passes MERA ------Distillates (LPD) Step 4 Heavy Petroleum Passes MERA ------Distillates (HPD) Step 3 Passes MERA HCl ------Step 3

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 8-1

State Health Federal PSD Minor NAAQS Pollutant Property Effects Review1 Review Line2 Review2 Passes MERA NH3 ------Step 3 Passes MERA Cl2 ------Step 7

1. The NAAQS pollutants are still in the preliminary modeling stages and require additional evaluation/refinement. Given the current emission rate increases for the project, it is highly likely several of the NAAQS pollutants and averaging periods will require site-wide modeling.

2. As shown in the table above, all State Property Line (SPL) pollutants and averaging periods are de minimis and the Health Effects Review (HER) pollutants and averaging periods satisfy the requirements of Modeling and Effects Review Applicability (MERA) Step 3, 4 or 7. Therefore, no further demonstration is required for these pollutants.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT 8-2

APPENDIX A: TCEQ FORMS AND TABLES This appendix includes the administrative forms and technical tables: • TCEQ’s General PI-1 Form workbook (version 4); • TCEQ’s Form APD-EXP; • TCEQ’s Form APD-APS; • Table 2 – Material Balance; • Table 6’s –Boilers and Heaters; and • A copy of the application fee and expedited permit fee checks.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD General Company: Phillips 66 Company

I. Applicant Information I acknowledge that I am submitting an authorized TCEQ application workbook and any necessary attachments. Except for inputting the requested data and adjusting row height and I agree column width, I have not changed the TCEQ application workbook in any way, including but not limited to changing formulas, formatting, content, or protections. A. Company Information Company or Legal Name: Phillips 66 Company

Permits are issued to either the facility owner or operator, commonly referred to as the applicant or permit holder. List the legal name of the company, corporation, partnership, or person who is applying for the permit. We will verify the legal name with the Texas Secretary of State at (512) 463-5555 or at: https://www.sos.state.tx.us Texas Secretary of State Charter/Registration 0801507995 Number (if given): B. Company Official Contact Information: must not be a consultant Prefix (Mr., Ms., Dr., etc.): Mr. First Name: Darrel Last Name: Hail Title: Refinery Manager Mailing Address: P.O. Box 271 Address Line 2: State Spur 119 North City: Borger State: Texas ZIP Code: 79008 Telephone Number: (806) 275-2242 Fax Number: (806) 275-2224 Email Address: [email protected] C. Technical Contact Information: This person must have the authority to make binding agreements and representations on behalf of the applicant and may be a consultant. Additional technical contact(s) can be provided in a cover letter. Prefix (Mr., Ms., Dr., etc.): Mr. First Name: Russell Last Name: Hill Title: Senior Environmental Consultant Company or Legal Name: Phillips 66 Company Mailing Address: P.O. Box 271 Address Line 2: City: Borger State: Texas ZIP Code: 79008 Telephone Number: 806-275-1348 Fax Number: 806-275-2224 Email Address: [email protected]

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD General Company: Phillips 66 Company

D. Assigned Numbers The CN and RN below are assigned when a Core Data Form is initially submitted to the Central Registry. The RN is also assigned if the agency has conducted an investigation or if the agency has issued an enforcement action. If these numbers have not yet been assigned, leave these questions blank and include a Core Data Form with your application submittal. See Section VI.B. below for additional information. Enter the CN. The CN is a unique number given to each business, governmental body, association, individual, or other entity that owns, operates, is responsible for, or CN604065912 is affiliated with a regulated entity. Enter the RN. The RN is a unique agency assigned number given to each person, organization, place, or thing that is of environmental interest to us and where regulated activities will occur. The RN replaces existing air account numbers. The RN102495884 RN for portable units is assigned to the unit itself, and that same RN should be used when applying for authorization at a different location.

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

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Version 4.0 Page 2 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD General Company: Phillips 66 Company

III. Permit Information A. Permit and Action Type (multiple may be selected, leave no blanks) Additional information regarding the different NSR authorizations can be found at: https://www.tceq.texas.gov/permitting/air/guidance/authorize.html

Select from the drop-down the type of action being requested for each permit type. If that permit type does not apply, you MUST select "Not applicable".

Provide all assigned permit numbers relevant for the project. Leave blank if the permit number has not yet been assigned.

Permit Type Action Type Requested Permit Number (if assigned) (do not leave blank) Minor NSR (can be a Title V major source): Not applicable, Initial, Amendment, Renewal, Renewal Certification, Renewal/Amendment, Initial TBD Relocation/Alteration, Change of Location, Alteration, Extension to Start of Construction Special Permit: Not applicable, Amendment, Renewal, Renewal Certification, Not applicable Renewal/Amendment, Alteration, Extension to Start of Construction

De Minimis: Not applicable, Initial Not applicable

Flexible: Not applicable, Initial, Amendment, Renewal, Renewal Certification, Not applicable Renewal/Amendment, Alteration, Extension to Start of Construction

PSD: Not applicable, Initial, Major Modification Initial TBD

Nonattainment: Not applicable, Initial, Major Not applicable Modification HAP Major Source [FCAA § 112(g)]: Not Not applicable applicable, Initial, Major Modification PAL: Not applicable, Initial, Amendment, Renewal, Not applicable Renewal/Amendment, Alteration GHG PSD: Not applicable, Initial, Major Initial TBD Modification, Voluntary Update GHG projects: List the non-GHG applications TBD (pending or being submitted) that are associated with the project. Note: All preconstruction authorizations (including authorization for emissions of greenhouse gases, if applicable) must be obtained prior to start of construction. B. MSS Activities How are/will MSS activities for sources associated This permit with this project be authorized?

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C. Consolidating NSR Permits Will this permit be consolidated into another NSR permit with this action? No

Will NSR permits be consolidated into this permit with this action? No

D. Incorporation of Standard Permits, Standard Exemptions, and/or Permits By Rule (PBR) To ensure protectiveness, previously issued authorizations (standard permits, standard exemptions, or PBRs) including those for MSS, are incorporated into a permit either by consolidation or by reference. At the time of renewal and/or amendment, consolidation (in some cases) may be voluntary and referencing is mandatory. More guidance regarding incorporation can be found in 30 TAC § 116.116(d)(2), 30 TAC § 116.615(3) and in this memo:

https://www.tceq.texas.gov/assets/public/permitting/air/memos/pbr_spc06.pdf Are there any standard permits, standard exemptions, or PBRs to No be incorporated by reference?

Are there any PBR, standard exemptions, or standard permits associated to be incorporated by consolidation? Note: Emission calculations, a BACT analysis, and an impacts analysis must be No attached to this application at the time of submittal for any authorization to be incorporated by consolidation.

Version 4.0 Page 4 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD General Company: Phillips 66 Company

E. Associated Federal Operating Permits Is this facility located at a site required to obtain a site operating permit (SOP) or general operating Yes permit (GOP)? Is a SOP or GOP review pending for this source, area, or site? Yes

If required to obtain a SOP or GOP, list all associated permit number(s). If no associated 1440, 2166, 4130, TBD permit number has been assigned yet, enter "TBD":

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IV. Facility Location and General Information A. Location County: Enter the county where the facility is Hutchinson physically located. TCEQ Region Region 1 County attainment status as of Sept. 23, 2019 attainment or unclassified for all pollutants Street Address: State Spur 119 N City: If the address is not located in a city, then enter the city or town closest to the facility, even if it Borger is not in the same county as the facility. ZIP Code: Include the ZIP Code of the physical facility site, not the ZIP Code of the applicant's 79008 mailing address. Site Location Description: If there is no street address, provide written driving directions to the site. Identify the location by distance and direction from well-known landmarks such as major highway intersections. Use USGS maps, county maps prepared by the Texas Department of Transportation, or an online software application such as Google Earth to find the latitude and longitude. Latitude (in degrees, minutes, and nearest second (DDD:MM:SS)) for the street address or the destination point of the driving directions. Latitude is the angular distance of a location north of the 035:41:58 equator and will always be between 25 and 37 degrees north (N) in Texas. Longitude (in degrees, minutes, and nearest second (DDD:MM:SS)) for the street address or the destination point of the driving directions. Longitude is the angular distance of a location west of the 101:21:35 prime meridian and will always be between 93 and 107 degrees west (W) in Texas. Is this a project for a lead smelter, concrete crushing facility, and/or a hazardous waste management No facility?

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B. General Information Site Name: Borger Refinery Area Name: Must indicate the general type of operation, process, equipment or facility. Include numerical designations, if appropriate. Examples are Sulfuric Acid Plant and No. 5 Steam Boiler. Crude Flexibility and Modernization Project Vague names such as Chemical Plant are not acceptable. Are there any schools located within 3,000 feet of No the site boundary? C. Portable Facility Permanent or portable facility? Permanent

D. Industry Type Principal Company Product/Business: Petroleum Refinery A list of SIC codes can be found at: https://www.naics.com/sic-codes-industry-drilldown/ Principal SIC code: 2911 NAICS codes and conversions between NAICS and SIC Codes are available at: https://www.census.gov/eos/www/naics/ Principal NAICS code: 324110 E. State Senator and Representative for this site This information can be found at (note, the website is not compatible to Internet Explorer): https://wrm.capitol.texas.gov/ State Senator: Kel Seliger District: 31 State Representative: Walter "Four" Price District: 87

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Version 4.0 Page 6 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD General Company: Phillips 66 Company

V. Project Information A. Description Provide a brief description of the project that is requested. (Limited Authorize construction of sources associated with a planned project to modernize to 500 characters). the Phillips 66 Borger Refinery and to allow for more variability in refinery crude slates.

B. Project Timing Authorization must be obtained for many projects before beginning construction. Construction is broadly interpreted as anything other than site clearance or site preparation. Enter the date as "Month Date, Year" (e.g. July 4, 1776).

Projected Start of Construction: June 1, 2021 Projected Start of Operation: June 1, 2023 C. Enforcement Projects Is this application in response to, or related to, an agency investigation, notice of violation, or No enforcement action?

D. Operating Schedule Will sources in this project be authorized to operate 8760 hours per year? Yes

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Version 4.0 Page 7 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD General Company: Phillips 66 Company

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

B. Is the Core Data Form (Form 10400) attached? No https://www.tceq.texas.gov/assets/public/permitting/centralregistry/10400.docx C. Is a current area map attached? Yes Is the area map a current map with a true north arrow, an accurate scale, the entire plant property, the location of the property relative to prominent geographical features including, but not limited to, highways, roads, streams, and significant landmarks such as buildings, residences, schools, parks, Yes hospitals, day care centers, and churches? Does the map show a 3,000-foot radius from the property boundary? Yes D. Is a plot plan attached? Yes Does your plot plan clearly show a north arrow, an accurate scale, all property lines, all emission points, buildings, tanks, process vessels, other process equipment, and two bench mark locations? Yes

Does your plot plan identify all emission points on the affected property, including all emission points authorized by other air authorizations, construction permits, PBRs, special permits, and standard Yes permits? Did you include a table of emission points indicating the authorization type and authorization identifier, such as a permit number, registration number, or rule citation under which each emission point is Yes currently authorized? E. Is a process flow diagram attached? Yes Is the process flow diagram sufficiently descriptive so the permit reviewer can determine the raw materials to be used in the process; all major processing steps and major equipment items; individual emission points associated with each process step; the location and identification of all emission Yes abatement devices; and the location and identification of all waste streams (including wastewater streams that may have associated air emissions)? F. Is a process description attached? Yes Does the process description emphasize where the emissions are generated, why the emissions must be generated, what air pollution controls are used (including process design features that minimize Yes emissions), and where the emissions enter the atmosphere? Does the process description also explain how the facility or facilities will be operating when the Yes maximum possible emissions are produced?

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G. Are detailed calculations attached? Calculations must be provided for each source with new or changing emission rates. For example, a new source, changing emission factors, decreasing emissions, consolidated sources, etc. You do not need to submit calculations for sources which are not changing emission rates with this project. Please note: the preferred Yes format is an electronic workbook (such as Excel) with all formulas viewable for review. It can be emailed with the submittal of this application workbook. Are emission rates and associated calculations for planned MSS facilities and related activities Yes attached? H. Is a material balance (Table 2, Form 10155) attached? Yes Table 2 (Form 10155), entitled Material Balance: A material balance representation may be required for all applications to confirm technical emissions information. Typically this is required for refining and chemical manufacturing processes involving reactions, separations, and blending. It may also be requested by the permit reviewer for other applications. Table 2 should represent the total material balance; that is, all streams into the system and all streams out. Additional sheets may be attached if necessary. Complex material balances may be presented on spreadsheets or indicated using process flow diagrams. All materials in the process should be addressed whether or not they directly result in the emission of an air contaminant. All production rates must be based on maximum operating conditions. I. Is a list of MSS activities attached? Yes Are the MSS activities listed and discussed separately, each complete with the authorization mechanism or emission rates, frequency, duration, and supporting information if authorized by this Yes permit? J. Is a discussion of state regulatory requirements attached, addressing 30 TAC Chapters 101, Yes 111, 112, 113, 115, and 117? For all applicable chapters, does the discussion include how the facility will comply with the Yes requirements of the chapter? For all not applicable chapters, does the discussion include why the chapter is not applicable? Yes K. Are all other required tables, calculations, and descriptions attached? Yes

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Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Technical Company: Phillips 66 Company

VIII. Federal Regulatory Questions Indicate if any of the following requirements apply to the proposed facility. Note that some federal regulations apply to minor sources. Enter all applicable Subparts. A. Title 40 CFR Part 60 Do NSPS subpart(s) apply to a Yes facility in this application? List applicable subparts you will demonstrate compliance with (e.g. A, Ja, GGG/GGGa, QQQ Subpart M) B. Title 40 CFR Part 61 Do NESHAP subpart(s) apply to a Yes facility in this application? List applicable subparts you will demonstrate compliance with (e.g. Subpart BB) A, FF

C. Title 40 CFR Part 63 Do MACT subpart(s) apply to a Yes facility in this application? List applicable subparts you will demonstrate compliance with (e.g. A, CC, UUU, DDDDD Subpart VVVV)

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

C. Air Pollutant Watch List Certain areas of the state have concentrations of specific pollutants that are of concern. The TCEQ has designated these portions of the state as watch list areas. Location of a facility in a watch list area could result in additional restrictions on emissions of the affected air pollutant(s) or additional permit requirements. The location of the areas and pollutants of interest can be found at: https://www.tceq.texas.gov/toxicology/apwl/apwl.html

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Is the proposed facility located in a watch list area? No

D. Mass Emissions Cap and Trade Is this facility located at a site within the Houston/Galveston nonattainment area (Brazoria, Chambers, No Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties)?

This cell intentionally left blank X. Additional Requirements A. Bulk Fuel Terminals Is this project for a bulk fuel terminal? No

B. Plant Fuel Gas Facilities Does this site utilize plant fuel gas? Yes

Version 4.0 Page 2 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Unit Types - Emission Rates Company: Phillips 66 Company

Permit primary industry (must be selected for workbook to function) Chemical / Energy this cell is intentionally left blank This cell intentionally left blank Include these Emission Consolidate emissi Point Current Current Consolidated d Current Proposed Short-Term Unit Type Notes (only if Action Requested ons in Facility ID Number Short-Term Long-Term Current Short- Long-Term Short-Term Proposed Long- Difference Long-Term Unit Type (Used for reviewing BACT and "other" unit type in (only 1 action per FIN) annual Number (FIN) (EPN) Source Name Pollutant (lb/hr) (tpy) Term (lb/hr) (tpy) (lb/hr) Term (tpy) (lb/hr) Difference (tpy) Monitoring Requirements) Column O) Crude Charge New/Modified Yes 28-H3 28-H3 NOX 2.89 12.65 2.89 12.65 Heater Heater No. 1 CO 13.48 29.51 13.48 29.51 SO2 6.16 10.12 6.16 10.12 PM 1.43 6.28 1.43 6.28 PM10 1.43 6.28 1.43 6.28 PM2.5 1.43 6.28 1.43 6.28 VOC 1.04 4.55 1.04 4.55 NH3 0.83 3.65 0.83 3.65 NOX - MSS 6.35 6.35 0 CO - MSS 50.53 50.53 0 CO2 109,639.85 0 109639.85 CH4 5.57 0 5.57 N2O 1.11 0 1.11 CO2 Equivalent 110,111.49 0 110111.49 Crude Charge New/Modified Yes 28-H4 28-H4 NOX 2.89 12.65 2.89 12.65 Heater Heater No. 2 CO 13.48 29.51 13.48 29.51 SO2 6.16 10.12 6.16 10.12 PM 1.43 6.28 1.43 6.28 PM10 1.43 6.28 1.43 6.28 PM2.5 1.43 6.28 1.43 6.28 VOC 1.04 4.55 1.04 4.55 NH3 0.83 3.65 0.83 3.65 NOX - MSS 6.35 6.35 0 CO - MSS 50.53 50.53 0 CO2 109,639.85 0 109639.85 CH4 5.57 0 5.57 N2O 1.11 0 1.11 CO2 Equivalent 110,111.49 0 110111.49

CCR Charge and New/Modified Yes 88-H1.1, 1.2, 1.3 88-H1 NOX 6.19 27.13 6.19 27.13 Heater Interheaters CO 28.90 63.30 28.9 63.3 SO2 13.21 21.70 13.21 21.7 PM 3.08 13.48 3.08 13.48 PM10 3.08 13.48 3.08 13.48 PM2.5 3.08 13.48 3.08 13.48 VOC 2.23 9.75 2.23 9.75 NH3 1.79 7.83 1.79 7.83 NOX - MSS 9.29 9.29 0 CO - MSS 108.39 108.39 0 CO2 235,170.37 0 235170.37 CH4 11.96 0 11.96 N2O 2.39 0 2.39 CO2 Equivalent 236,182.00 0 236182 New/Modified Yes 88-V1 88-V1 CCR Vent Cl2 0.97 4.26 0.97 4.26 Other CCR Regeneration Vent NOX 0.03 0.11 0.03 0.11 CO 0.31 1.35 0.31 1.35 SO2 0.70 3.08 0.7 3.08 VOC 0.11 0.46 0.11 0.46 HCl 0.02 0.08 0.02 0.08 CO2 2,695.76 0 2695.76 CO2 Equivalent 2,695.76 0 2695.76 CCR/Crude Flex New/Modified Yes F-CrudeFlex F-CrudeFlex VOC 16.15 70.72 16.15 70.72 Fugitives: Piping and Equipment Leak Fugitives H2S 0.10 0.46 0.1 0.46 NH3 0.09 0.40 0.09 0.4 CH4 49.24 0 49.24 CO2 Equivalent 1,230.97 0 1230.97

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Unit Types - Emission Rates Company: Phillips 66 Company

Include these Emission Consolidate emissi Point Current Current Consolidated d Current Proposed Short-Term Unit Type Notes (only if Action Requested ons in Facility ID Number Short-Term Long-Term Current Short- Long-Term Short-Term Proposed Long- Difference Long-Term Unit Type (Used for reviewing BACT and "other" unit type in (only 1 action per FIN) annual Number (FIN) (EPN) Source Name Pollutant (lb/hr) (tpy) Term (lb/hr) (tpy) (lb/hr) Term (tpy) (lb/hr) Difference (tpy) Monitoring Requirements) Column O) Planned MSS New/Modified Yes MSS MSS NOX 56.79 0.17 56.79 0.17 Other Planned MSS Emissions CO 410.21 1.10 410.21 1.1 SO2 0.69 0.01 0.69 0.01 VOC 1064.56 7.30 1064.56 7.3 PM 0.16 0.01 0.16 0.01 PM10 0.08 0.01 0.08 0.01 PM2.5 0.01 0.01 0.01 0.01 CO2 103.34 0 103.34 CH4 0.31 0 0.31 N2O 0.01 0 0.01 CO2 Equivalent 111.45 0 111.45 F- New/Modified Yes F-SUMPCCR CCR Sump VOC 0.4 1.75 0.4 1.75 Wastewater Facilities SUMPCCR 0 0 0 0 0 0

Version 4.0 Page 2 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Stack Parameters Company: Phillips 66 Company

Emission Point Discharge Parameters UTM Coordinates Height Stack Exit Fugitives - Included in East North Building Above Diameter Temperature Fugitives - Fugitives - Axis EPN EMEW? Zone (Meters) (Meters) Height (ft) Ground (ft) (ft) Velocity (FPS) (°F) Length (ft) Width (ft) Degrees

28-H3 Yes

28-H4 Yes

88-H1 Yes

88-V1 Yes F-CrudeFlex Yes MSS Yes F-SUMPCCR Yes

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Public Notice Company: Phillips 66 Company

I. Public Notice Applicability A. Application Type Is this an application for an initial permit? Yes

Is this an application for a new or major modification of a PSD (including GHG), Nonattainment, or HAP permit? Yes

B. Project Increases and Public Notice Thresholds (for Initial and Amendment Projects)

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Public Notice Company: Phillips 66 Company

Proposed Long- Pollutant Term (tpy)

VOC 99.08 PM 26.05

PM10 26.05

PM2.5 26.05

NOx 52.71 CO 124.77

SO2 45.03 Pb 0.00 NH3 15.53 NOX - MSS 0 CO - MSS 0 CO2 457249.17 CH4 72.65 N2O 4.62 CO2 Equivalent 460443.16 Cl2 4.26 HCl 0.08 H2S 0.46

* Notice is required for PM, PM10, and PM2.5 if one of these pollutants is above the threshold. ** Notice of a GHG action is determined by action type. Initial and major modification always require notice. Voluntary updates require a consolidated notice if there is a change to BACT. Project emission increases of CO2e (CO2 equivalent) are not relevant for determining public notice of GHG permit actions.

C. Is public notice required for this project as represented in this workbook? Yes If no, proceed to Section III Small Business Classification. Note: public notice applicability for this project may change throughout the technical review. D. Are any HAPs to be authorized/re-authorized with this project? The category "HAPs" must No be specifically listed in the public notice if the project authorizes (reauthorizes for renewals) any HAP pollutants.

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Version 4.0 Page 2 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Public Notice Company: Phillips 66 Company

II. Public Notice Information Complete this section if public notice is required (determined in the above section) or if you are not sure if public notice is required.

A. Contact Information Enter the contact information for the person responsible for publishing. This is a designated representative who is responsible for ensuring public notice is properly published in the appropriate newspaper and signs are posted at the facility site. This person will be contacted directly when the TCEQ is ready to authorize public notice for the application. Prefix (Mr., Ms., Dr., etc.): Mr. First Name: Russell Last Name: Hill Title: Senior Environmental Consultant Company Name: Phillips 66 Company Mailing Address: P.O. Box 271 Address Line 2: City: Borger State: Texas ZIP Code: 79008 Telephone Number: 806-275-1348 Fax Number: 806-275-2224 Email Address: [email protected] Enter the contact information for the Technical Contact. This is the designated representative who will be listed in the public notice as a contact for additional information. Prefix (Mr., Ms., Dr., etc.): Mr. First Name: Russell Last Name: Hill Title: Senior Environmental Consultant Company Name: Phillips 66 Company Mailing Address: P.O. Box 271 Address Line 2: City: Borger State: Texas ZIP Code: 79008 Telephone Number: 806-275-1348 Fax Number: 806-275-2224 Email Address: [email protected] B. Public place Place a copy of the full application (including all of this workbook and all attachments) at a public place in the county where the facilities are or will be located. You must state where in the county the application will be available for public review and comment. The location must be a public place and described in the notice. A public place is a location which is owned and operated by public funds (such as libraries, county courthouses, city halls) and cannot be a commercial enterprise. You are required to pre-arrange this availability with the public place indicated below. The application must remain available from the first day of publication through the designated comment period.

If this is an application for a PSD, nonattainment, or FCAA §112(g) permit, the public place must have internet access available for the public as required in 30 TAC § 39.411(f)(3).

If the application is submitted to the agency with information marked as Confidential, you are required to indicate which specific portions of the application are not being made available to the public. These portions of the application must be accompanied with the following statement: Any request for portions of this application that are marked as confidential must be submitted in writing, pursuant to the Public Information Act, to the TCEQ Public Information Coordinator, MC 197, P.O. Box 13087, Austin, Texas 78711-3087.

Version 4.0 Page 3 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Public Notice Company: Phillips 66 Company

Name of Public Place: Hutchinson County Library Physical Address: 625 Weatherly Street (Application will also be published online - http://tricordconsulting.com/wp- Address Line 2: content/uploads/2020/04/2020_04_09-Crude-Flexibility-and-Modernization-Application- and-Protocol.pdf.) City: Borger ZIP Code: 79007 County: Hutchinson Has the public place granted authorization to place the application for public Yes viewing and copying? Does the public place have Internet access available for the public? Yes C. Alternate Language Publication In some cases, public notice in an alternate language is required. If an elementary or middle school nearest to the facility is in a school district required by the Texas Education Code to have a bilingual program, a bilingual notice will be required. If there is no bilingual program required in the school nearest the facility, but children who would normally attend those schools are eligible to attend bilingual programs elsewhere in the school district, the bilingual notice will also be required. If it is determined that alternate language notice is required, you are responsible for ensuring that the publication in the alternate language is complete and accurate in that language. Is a bilingual program required by the Texas Education Code in the School Yes District? Are the children who attend either the elementary school or the middle school closest to your facility eligible to be enrolled in a bilingual program provided by Yes the district? If yes to either question above, list which language(s) are required by the Spanish bilingual program?

Version 4.0 Page 4 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Public Notice Company: Phillips 66 Company

D. PSD and Nonattainment Permits Only If this is an application for emissions of GHGs, select either "Separate Public Notice" or "Consolidated Public Notice". Note: Separate public notices requires a separate application. Consolidated Public Notice

We must notify the applicable county judge and presiding officer when a PSD or Nonattainment permit or modification application is received. This information can be obtained at: https://www.txdirectory.com Provide the information for the County Judge for the location where the facility is or will be located. The Honorable: Judge Cindy Irwin Mailing Address: 515 S. Main Street Suite 214 Address Line 2: P.O. Box 790 City: Stinnett State: Texas ZIP Code: 79083 Provide the information for the Presiding Officer(s) of the municipality for this facility site. This is frequently the Mayor. First Name: Marvin Last Name: Dickson Title: Mayor Mailing Address: 600 N Main Street Address Line 2: PO Box 5250 City: Borger State: TX ZIP Code: 79008-5250 Are the proposed facilities located within 100 km or less of an affected state or No Class I Area?

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

Small business classification: No

Version 4.0 Page 5 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Federal Applicability Company: Phillips 66 Company

I. County Classification

Does the project require retrospective review? No

County (completed for you from your response on the General sheet) Hutchinson

This project will be located in an area that is in attainment for ozone as of Sept. 23, 2019. Select from the drop-down list to the right if you would like the project to be reviewed under a different classification.

This project will be located in an area that is in attainment or unclassified for all Determination: pollutants. Nonattainment review is not required.

This cell intentionally left blank II. PSD and GHG PSD Applicability Summary Is netting required for the PSD analysis for this project? Yes If yes, the project increases listed below should be after netting has been performed. Attach the netting information to the application. Project Increase (after Pollutant Threshold PSD Review Required? netting) CO 3,162.42 100 Yes

NOx 1,484.41 40 Yes PM 1,255.04 25 Yes

PM10 1,283.45 15 Yes

PM2.5 1,343.28 10 Yes

SO2 2,774.55 40 Yes Ozone (as VOC) 1,059.66 40 Yes Ozone (as NOx) 1,484.41 40 Yes Pb 0 0.6 No

H2S 41.55 10 Yes TRS 0 10 No

Reduced sulfur compounds (including H2S) 0 10 No

H2SO4 0 7 No Fluoride (excluding HF) 0 3 No CO2e 460,443.16 75000 Yes

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Fees Company: Phillips 66 Company

I. General Information - Non-Renewal Is this project for new facilities controlled and operated directly by the federal government? No (30 TAC § 116.141(b)(1) and 30 TAC § 116.163(a))

A fee of $75,000 shall be required if no estimate of capital project cost is included with the permit application. (30 TAC § 116.141(d)) Select "yes" here to use this option. Then skip Yes sections II and III.

Select Application Type Major Application

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Fees Company: Phillips 66 Company

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

This cell intentionally left blank Your estimated capital cost: Maximum fee appies. Permit Application Fee: $75,000.00

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Version 4.0 Page 2 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Fees Company: Phillips 66 Company

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

Total $75,000.00

This cell intentionally left blank VII. Payment Information A. Payment One (required) Was the fee paid online? No Enter the fee amount: $ 75,000.00 Enter the check, money order, ePay Voucher, or other transaction number: Enter the Company name as it appears on the check: WRB Refining LP

C. Total Paid $75,000.00

This cell intentionally left blank VIII. Professional Engineer Seal Requirement Is the estimated capital cost of the project above $2 million? Yes Is this project subject to an exemption contained in the Texas Engineering Practice Act No (TEPA)? (30 TAC § 116.110(f)) Is the application required to be submitted under the seal of a Texas licensed P.E.? Yes Note: an electronic PE seal is acceptable.

Version 4.0 Page 3 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Impacts Company: Phillips 66 Company

Does this pollutant How will you demonstrate that this Pollutant require PSD project meets all applicable Notes Additional Notes (optional) review? requirements?

Protocol (required for all PSD projects, Ozone Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Project does trigger PSD review for VOC. A state health effects review for VOCs was completed VOC No Modeling: screen or refined Attach a completed "Electronic Modeling Evaluation Workbook" (EMEW). in the EMEW. There is no PSD- related VOC modeling since it does not have a NAAQS.

Protocol (required for all PSD projects, NOX Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Protocol (required for all PSD projects, CO Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Protocol (required for all PSD projects, SO2 Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Protocol (required for all PSD projects, PM Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Protocol (required for all PSD projects, PM10 Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Protocol (required for all PSD projects, PM2.5 Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Protocol (required for all PSD projects, NH3 Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

An air quality analysis for GHGs (i.e., air dispersion modeling, ambient air NOX - MSS Yes None (GHG-PSD Only) monitoring, additional impacts, or Class I area impacts) is not required.

An air quality analysis for GHGs (i.e., air dispersion modeling, ambient air CO - MSS Yes None (GHG-PSD Only) monitoring, additional impacts, or Class I area impacts) is not required.

An air quality analysis for GHGs (i.e., air dispersion modeling, ambient air CO2 Yes None (GHG-PSD Only) monitoring, additional impacts, or Class I area impacts) is not required.

An air quality analysis for GHGs (i.e., air dispersion modeling, ambient air CH4 Yes None (GHG-PSD Only) monitoring, additional impacts, or Class I area impacts) is not required.

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Impacts Company: Phillips 66 Company

Does this pollutant How will you demonstrate that this Pollutant require PSD project meets all applicable Notes Additional Notes (optional) review? requirements?

N2O No Modeling: screen or refined Attach a completed "Electronic Modeling Evaluation Workbook" (EMEW).

Protocol (required for all PSD projects, CO2 Equivalent Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Cl2 No Modeling: screen or refined Attach a completed "Electronic Modeling Evaluation Workbook" (EMEW).

HCl No Modeling: screen or refined Attach a completed "Electronic Modeling Evaluation Workbook" (EMEW).

Protocol (required for all PSD projects, H2S Yes Attach a protocol meeting all requirements listed on the TCEQ website. excluding GHG PSD)

Version 4.0 Page 2 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD BACT Company: Phillips 66 Company

Plant Type Current Tier I BACT Confirm Additional Notes

Plant fuel gas facility Maximum short term H2S emissions: 0.1 gr/dscf or 160 ppmv. Maximum annual H2S This cell intentionally blank. Action Requested FINs Unit Type Pollutant Current Tier I BACT Confirm Additional Notes Burners with the best NOx performance given the burner configuration and gaseous fuel used. Specify the proposed emission rate (performance is an annual average) and provide justification if NOx>0.01 lb/MMBtu. New/Modified 28-H3 Heater NOX Yes See Section 5. Cost data must be submitted for SCR if firing rate is > 300 MMBtu/hr and burner is >0.01 lb/MMBtu.

CEMS required for 100 MMBtu/hr or greater. New/Modified 28-H3 Heater CO 50 ppmv corrected to 3% O2 Yes See Section 5. Maximum 0.6% sulfur content any liquid fuel or 5 grains for pipeline quality sweet New/Modified 28-H3 Heater SO2 No Facility utilizes plant fuel gas for new process heaters. natural gas. Provide details. The emission reduction techniques for PM10 and PM2.5 will follow the technique for New/Modified 28-H3 Heater PM Yes See Section 5. PM. Maximum opacity 5% Firing pipeline quality natural gas and good combustion practices. Specify if firing a New/Modified 28-H3 Heater VOC Yes See Section 5. different fuel. New/Modified 28-H3 Heater NH3 See Additional Notes: See Section 5. New/Modified 28-H3 Heater NOX - MSS See additional notes: See Section 5. New/Modified 28-H3 Heater CO - MSS See additional notes: See Section 5. New/Modified 28-H3 Heater CO2 See additional notes: See Section 6. New/Modified 28-H3 Heater CH4 See additional notes: See Section 6. New/Modified 28-H3 Heater N2O See additional notes: See Section 6.

New/Modified 28-H3 Heater CO2 Equivalent See additional notes: See Section 6.

New/Modified 28-H3 Heater

New/Modified 28-H3 Heater MSS Same as normal operation BACT requirements. Yes See Section 5. Burners with the best NOx performance given the burner configuration and gaseous fuel used. Specify the proposed emission rate (performance is an annual average) and provide justification if NOx>0.01 lb/MMBtu. New/Modified 28-H4 Heater NOX Yes See Section 5. Cost data must be submitted for SCR if firing rate is > 300 MMBtu/hr and burner is >0.01 lb/MMBtu.

CEMS required for 100 MMBtu/hr or greater. New/Modified 28-H4 Heater CO 50 ppmv corrected to 3% O2 Yes See Section 5. Maximum 0.6% sulfur content any liquid fuel or 5 grains for pipeline quality sweet New/Modified 28-H4 Heater SO2 No Facility utilizes plant fuel gas for new process heaters. natural gas. Provide details. The emission reduction techniques for PM10 and PM2.5 will follow the technique for New/Modified 28-H4 Heater PM Yes See Section 5. PM. Maximum opacity 5% Firing pipeline quality natural gas and good combustion practices. Specify if firing a New/Modified 28-H4 Heater VOC Yes See Section 5. different fuel. New/Modified 28-H4 Heater NH3 See Additional Notes: See Section 5. New/Modified 28-H4 Heater NOX - MSS See additional notes: See Section 5. New/Modified 28-H4 Heater CO - MSS See additional notes: See Section 5. New/Modified 28-H4 Heater CO2 See additional notes: See Section 6. New/Modified 28-H4 Heater CH4 See additional notes: See Section 6. New/Modified 28-H4 Heater N2O See additional notes: See Section 6.

New/Modified 28-H4 Heater CO2 Equivalent See additional notes: See Section 6.

New/Modified 28-H4 Heater

New/Modified 28-H4 Heater MSS Same as normal operation BACT requirements. Yes See Section 5.

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD BACT Company: Phillips 66 Company

Action Requested FINs Unit Type Pollutant Current Tier I BACT Confirm Additional Notes Burners with the best NOx performance given the burner configuration and gaseous fuel used. Specify the proposed emission rate (performance is an annual average) and provide justification if NOx>0.01 lb/MMBtu. New/Modified 88-H1.1, 1.2, 1.3 Heater NOX Yes See Section 5. Cost data must be submitted for SCR if firing rate is > 300 MMBtu/hr and burner is >0.01 lb/MMBtu.

CEMS required for 100 MMBtu/hr or greater. New/Modified 88-H1.1, 1.2, 1.3 Heater CO 50 ppmv corrected to 3% O2 Yes See Section 5. Maximum 0.6% sulfur content any liquid fuel or 5 grains for pipeline quality sweet New/Modified 88-H1.1, 1.2, 1.3 Heater SO2 No Facility utilizes plant fuel gas for new process heaters. natural gas. Provide details. The emission reduction techniques for PM10 and PM2.5 will follow the technique for New/Modified 88-H1.1, 1.2, 1.3 Heater PM Yes See Section 5. PM. Maximum opacity 5% Firing pipeline quality natural gas and good combustion practices. Specify if firing a New/Modified 88-H1.1, 1.2, 1.3 Heater VOC Yes See Section 5. different fuel. New/Modified 88-H1.1, 1.2, 1.3 Heater NH3 See Additional Notes: See Section 5. New/Modified 88-H1.1, 1.2, 1.3 Heater NOX - MSS See additional notes: See Section 5. New/Modified 88-H1.1, 1.2, 1.3 Heater CO - MSS See additional notes: See Section 5. New/Modified 88-H1.1, 1.2, 1.3 Heater CO2 See additional notes: See Section 6. New/Modified 88-H1.1, 1.2, 1.3 Heater CH4 See additional notes: See Section 6. New/Modified 88-H1.1, 1.2, 1.3 Heater N2O See additional notes: See Section 6.

New/Modified 88-H1.1, 1.2, 1.3 Heater CO2 Equivalent See additional notes: See Section 6.

New/Modified 88-H1.1, 1.2, 1.3 Heater

New/Modified 88-H1.1, 1.2, 1.3 Heater MSS Same as normal operation BACT requirements. Yes See Section 5. New/Modified 88-V1 CCR Regeneration Vent Cl2 See additional notes: See Section 5. New/Modified 88-V1 CCR Regeneration Vent NOX See additional notes: See Section 5. New/Modified 88-V1 CCR Regeneration Vent CO See additional notes: See Section 5. New/Modified 88-V1 CCR Regeneration Vent SO2 See additional notes: See Section 5. New/Modified 88-V1 CCR Regeneration Vent VOC See additional notes: See Section 5. New/Modified 88-V1 CCR Regeneration Vent HCl See additional notes: See Section 5. New/Modified 88-V1 CCR Regeneration Vent CO2 See additional notes: See Section 6.

New/Modified 88-V1 CCR Regeneration Vent CO2 Equivalent See additional notes: See Section 6.

New/Modified 88-V1 CCR Regeneration Vent

New/Modified 88-V1 CCR Regeneration Vent

New/Modified 88-V1 CCR Regeneration Vent

New/Modified 88-V1 CCR Regeneration Vent

New/Modified 88-V1 CCR Regeneration Vent

New/Modified 88-V1 CCR Regeneration Vent MSS See additional notes: See Section 5 and Section 6.

Version 4.0 Page 2 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD BACT Company: Phillips 66 Company

Action Requested FINs Unit Type Pollutant Current Tier I BACT Confirm Additional Notes Specify which is applicable: 1. Uncontrolled VOC emissions < 10 tpy: none

2. 10 tpy < uncontrolled VOC emissions < 25 tpy: 28M leak detection and repair program. 75% credit for 28M.

3. Uncontrolled VOC emissions > 25 tpy: 28VHP leak detection and repair program. New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak VOC Yes See Section 5. 97% credit for valves, 85% for pumps and compressors.

4. VOC vp < 0.002 psia: no inspection required, no fugitive emissions expected.

For emissions of approved odorous compounds (chlorine, ammonia, hydrogen sulfide, hydrogen cyanide and mercaptans only): AVO inspection twice per shift. Appropriate credit for AVO program.

H2S emissions from fugitives are from crude oil and refinery petrolum fraction speciation and are minimal. Phillips 66 New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak H2S AVO inspection twice per shift. Appropriate credit for AVO program. No Borger Refinery proposes that compliance with 28VHP is considered BACT for this source and pollutant. See Section 5.

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak NH3 AVO inspection twice per shift. Appropriate credit for AVO program. No See Section 5. Site proposes AVO inspections 1xshift. New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak CH4 See additional notes: See Section 6.

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak CO2 Equivalent See additional notes: See Section 6.

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak

New/Modified F-CrudeFlex Fugitives: Piping and Equipment Leak MSS Same as normal operation BACT requirements. Yes See Section 5 and Section 6. New/Modified MSS Planned MSS NOX See additional notes: See Section 5. New/Modified MSS Planned MSS CO See additional notes: See Section 5. New/Modified MSS Planned MSS SO2 See additional notes: See Section 5. New/Modified MSS Planned MSS VOC See additional notes: See Section 5. The emission reduction techniques for PM10 and PM2.5 will follow the technique for New/Modified MSS Planned MSS PM See Section 5. PM. See additional notes: New/Modified MSS Planned MSS CO2 See additional notes: See Section 5. New/Modified MSS Planned MSS CH4 See additional notes: See Section 5. New/Modified MSS Planned MSS N2O See additional notes: See Section 5.

New/Modified MSS Planned MSS CO2 Equivalent See additional notes: See Section 6.

New/Modified MSS Planned MSS

New/Modified MSS Planned MSS

New/Modified MSS Planned MSS

New/Modified MSS Planned MSS

New/Modified MSS Planned MSS MSS See additional notes: See Section 5 and Section 6.

Version 4.0 Page 3 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD BACT Company: Phillips 66 Company

Action Requested FINs Unit Type Pollutant Current Tier I BACT Confirm Additional Notes Applicable for organics and inorganics.

Uncontrolled site-wide wastewater emissions < 5 tpy VOC: Piped and covered conveyance to storage or biological treatment. New/Modified F-SUMPCCR Wastewater Facilities VOC Yes See Section 5. Uncontrolled site-wide wastewater emissions > 5 tpy VOC: stripped gases from pretreatment routed to a control device, collection system hard piped/covered conveyance to biological treatment unit vented to a control device, wastewater treatment system must be at least 90 percent efficient.

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities

New/Modified F-SUMPCCR Wastewater Facilities MSS Same as normal operation BACT requirements. Yes See Section 5.

Version 4.0 Page 4 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Monitoring Company: Phillips 66 Company

Proposed Measurement Technique (only complete for FIN Unit Type Pollutant Minimum Monitoring Requirements Confirm Additional Notes for Monitoring Additional Notes for Measuring: pollutants with a project increase above the PSD threshold)

CEMS <100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. Data used with stack testing results. 28-H3 Heater NOX Yes CEMS ≥100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. CEMS. Data collected four times per hour and averaged hourly.

CEMS <100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. Data used with stack testing results. 28-H3 Heater CO Yes CEMS ≥100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. CEMS. Data collected four times per hour and averaged hourly.

Continuously monitor the fuel firing rates. Periodic monitoring of fuel Other: composition and heating value, if and when varied. SO2 and O2 Continuous monitoring for fuel gas flow Continuous monitoring for fuel gas flow rate and fuel 28-H3 Heater SO2 CEMS if a major source. Yes rate and fuel gas H2S concentration gas H2S concentration under NSPS Ja. Refinery requires continuous monitoring of H2S in fuel, except where under NSPS Ja. low sulfur content by design is established. Other: The emission monitoring techniques for PM10 and PM2.5 will follow the technique for PM. Quarterly visible emission checks, followed by an Continuous monitoring for fuel gas flow opacity observation if visible emissions are observed. Continuous monitoring for fuel gas flow rate. Quarterly 28-H3 Heater PM Yes rate. Quarterly visible emissions visible emissions observations. observations. Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied.

Continuously monitor the fuel firing rates. Periodic monitoring of fuel Continuous monitoring for fuel gas flow Other: 28-H3 Heater VOC Yes Continuous monitoring for fuel gas flow rate. composition and heating value, if and when varied. rate. SCR requires continuous monitoring for slip reduced to an hourly Continuous monitoring (or equivalent) for 28-H3 Heater NH3 Yes average. ammonia slip. 28-H3 Heater NOX - MSS See additional notes: Same as normal NOX emissions. CEMS Same as normal NOX emissions. 28-H3 Heater CO - MSS See additional notes: Same as normal CO emissions. CEMS Same as normal CO emissions. 28-H3 Heater CO2 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent 28-H3 Heater CH4 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent 28-H3 Heater N2O See additional notes: See CO2 Equivalent Other: See CO2 Equivalent Other: Good combustion practices: Operate heater at an optimum air-fuel ratio and limit the heater operating temperature to the extent practicable. Conduct tune- 28-H3 Heater CO2 Equivalent See additional notes: Design thermal efficiency of at least 80%. ups under 40 CFR Part 63 Subpart DDDDD. Continuous monitoring of flue gas temperature. Flue gas temperature limit to be based on 12-month rolling average.

28-H3 Heater

Version 4.0 Page 1 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Monitoring Company: Phillips 66 Company

Proposed Measurement Technique (only complete for FIN Unit Type Pollutant Minimum Monitoring Requirements Confirm Additional Notes for Monitoring Additional Notes for Measuring: pollutants with a project increase above the PSD threshold)

CEMS <100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. Data used with stack testing results. 28-H4 Heater NOX Yes CEMS ≥100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. CEMS. Data collected four times per hour and averaged hourly.

CEMS <100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. Data used with stack testing results. 28-H4 Heater CO Yes CEMS ≥100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. CEMS. Data collected four times per hour and averaged hourly.

Continuously monitor the fuel firing rates. Periodic monitoring of fuel Other: composition and heating value, if and when varied. SO2 and O2 Continuous monitoring for fuel gas flow Continuous monitoring for fuel gas flow rate and fuel 28-H4 Heater SO2 CEMS if a major source. Yes rate and fuel gas H2S concentration gas H2S concentration under NSPS Ja. Refinery requires continuous monitoring of H2S in fuel, except where under NSPS Ja. low sulfur content by design is established. Other: The emission monitoring techniques for PM10 and PM2.5 will follow the technique for PM. Quarterly visible emission checks, followed by an Continuous monitoring for fuel gas flow opacity observation if visible emissions are observed. Continuous monitoring for fuel gas flow rate. Quarterly 28-H4 Heater PM Yes rate. Quarterly visible emissions visible emissions observations. observations. Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied.

Continuously monitor the fuel firing rates. Periodic monitoring of fuel Continuous monitoring for fuel gas flow Other: 28-H4 Heater VOC Yes Continuous monitoring for fuel gas flow rate. composition and heating value, if and when varied. rate. SCR requires continuous monitoring for slip reduced to an hourly Continuous monitoring (or equivalent) for 28-H4 Heater NH3 Yes average. ammonia slip. 28-H4 Heater NOX - MSS See additional notes: Same as normal NOX emissions. CEMS Same as normal NOX emissions. 28-H4 Heater CO - MSS See additional notes: Same as normal CO emissions. CEMS Same as normal CO emissions. 28-H4 Heater CO2 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent 28-H4 Heater CH4 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent 28-H4 Heater N2O See additional notes: See CO2 Equivalent Other: See CO2 Equivalent Other: Good combustion practices: Operate heater at an optimum air-fuel ratio and limit the heater operating temperature to the extent practicable. Conduct tune- 28-H4 Heater CO2 Equivalent See additional notes: Design thermal efficiency of at least 80%. ups under 40 CFR Part 63 Subpart DDDDD. Continuous monitoring of flue gas temperature. Flue gas temperature limit to be based on 12-month rolling average.

28-H4 Heater

Version 4.0 Page 2 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Monitoring Company: Phillips 66 Company

Proposed Measurement Technique (only complete for FIN Unit Type Pollutant Minimum Monitoring Requirements Confirm Additional Notes for Monitoring Additional Notes for Measuring: pollutants with a project increase above the PSD threshold)

CEMS <100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. Data used with stack testing results. 88-H1.1, 1.2, 1.3 Heater NOX Yes CEMS ≥100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. CEMS. Data collected four times per hour and averaged hourly.

CEMS <100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. Data used with stack testing results. 88-H1.1, 1.2, 1.3 Heater CO Yes CEMS ≥100 MMBtu/hr: Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied. CEMS. Data collected four times per hour and averaged hourly.

Continuously monitor the fuel firing rates. Periodic monitoring of fuel Other: composition and heating value, if and when varied. SO2 and O2 Continuous monitoring for fuel gas flow Continuous monitoring for fuel gas flow rate and fuel 88-H1.1, 1.2, 1.3 Heater SO2 CEMS if a major source. Yes rate and fuel gas H2S concentration gas H2S concentration under NSPS Ja. Refinery requires continuous monitoring of H2S in fuel, except where under NSPS Ja. low sulfur content by design is established. Other: The emission monitoring techniques for PM10 and PM2.5 will follow the technique for PM. Quarterly visible emission checks, followed by an Continuous monitoring for fuel gas flow opacity observation if visible emissions are observed. Continuous monitoring for fuel gas flow rate. Quarterly 88-H1.1, 1.2, 1.3 Heater PM Yes rate. Quarterly visible emissions visible emissions observations. observations. Continuously monitor the fuel firing rates. Periodic monitoring of fuel composition and heating value, if and when varied.

Continuously monitor the fuel firing rates. Periodic monitoring of fuel Continuous monitoring for fuel gas flow Other: 88-H1.1, 1.2, 1.3 Heater VOC Yes Continuous monitoring for fuel gas flow rate. composition and heating value, if and when varied. rate. SCR requires continuous monitoring for slip reduced to an hourly Continuous monitoring (or equivalent) for 88-H1.1, 1.2, 1.3 Heater NH3 Yes average. ammonia slip. 88-H1.1, 1.2, 1.3 Heater NOX - MSS See additional notes: Same as normal NOX emissions. CEMS Same as normal NOX emissions. 88-H1.1, 1.2, 1.3 Heater CO - MSS See additional notes: Same as normal CO emissions. CEMS Same as normal CO emissions. 88-H1.1, 1.2, 1.3 Heater CO2 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent 88-H1.1, 1.2, 1.3 Heater CH4 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent 88-H1.1, 1.2, 1.3 Heater N2O See additional notes: See CO2 Equivalent Other: See CO2 Equivalent Other: Good combustion practices: Operate heater at an optimum air-fuel ratio and limit the heater operating temperature to the extent practicable. Conduct tune- 88-H1.1, 1.2, 1.3 Heater CO2 Equivalent See additional notes: Design thermal efficiency of at least 80%. ups under 40 CFR Part 63 Subpart DDDDD. Continuous monitoring of flue gas temperature. Flue gas temperature limit to be based on 12-month rolling average.

88-H1.1, 1.2, 1.3 Heater

Version 4.0 Page 3 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Monitoring Company: Phillips 66 Company

Proposed Measurement Technique (only complete for FIN Unit Type Pollutant Minimum Monitoring Requirements Confirm Additional Notes for Monitoring Additional Notes for Measuring: pollutants with a project increase above the PSD threshold)

Compliance with MACT UUU monitoring 88-V1 CCR Regeneration Vent Cl2 See additional notes: requirements Continuous operation according to Other: Continuous operation according to manufacturer's manufacturer's recommendations will 88-V1 CCR Regeneration Vent NOX See additional notes: recommendations will reduce coke build up and reduce coke build up and combustion combustion emissions. emissions. Continuous operation according to Other: Continuous operation according to manufacturer's manufacturer's recommendations will 88-V1 CCR Regeneration Vent CO See additional notes: recommendations will reduce coke build up and reduce coke build up and combustion combustion emissions. emissions. Continuous operation according to Other: Continuous operation according to manufacturer's manufacturer's recommendations will 88-V1 CCR Regeneration Vent SO2 See additional notes: recommendations will reduce coke build up and reduce coke build up and combustion combustion emissions. emissions. Continuous operation according to Other: Continuous operation according to manufacturer's manufacturer's recommendations will 88-V1 CCR Regeneration Vent VOC See additional notes: recommendations will reduce coke build up and reduce coke build up and combustion combustion emissions. emissions. Compliance with MACT UUU monitoring 88-V1 CCR Regeneration Vent HCl See additional notes: requirements 88-V1 CCR Regeneration Vent CO2 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent Continuous operation according to Other: Continuous operation according to manufacturer's manufacturer's recommendations will 88-V1 CCR Regeneration Vent CO2 Equivalent See additional notes: recommendations will reduce coke build up and reduce coke build up and combustion combustion emissions. emissions.

88-V1 CCR Regeneration Vent

88-V1 CCR Regeneration Vent

88-V1 CCR Regeneration Vent

88-V1 CCR Regeneration Vent

88-V1 CCR Regeneration Vent

Version 4.0 Page 4 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Monitoring Company: Phillips 66 Company

Proposed Measurement Technique (only complete for FIN Unit Type Pollutant Minimum Monitoring Requirements Confirm Additional Notes for Monitoring Additional Notes for Measuring: pollutants with a project increase above the PSD threshold)

Other: 28VHP and 28PI LDAR programs. Use EPA Method 21 to monitor for leaks from seals on pumps, compressors, agitator and valve seals on piping components in light liquid and gas VOC service quarterly. Gas or hydraulic check new and a replaced connectors prior to returning to service, or monitor with Method 21 within 15 days of returning to service. Leak detection and Fugitives: Piping and F-CrudeFlex VOC repair (LDAR) Program 28M has a leak definition where repair action is Yes Equipment Leak required at 10,000 ppmv. LDAR Program 28 VHP has a leak definition where repair action is required at 500 ppmv for valves and connectors and 2000 ppmv for pumps, compressors and agitators. Check connectors weekly using audio, visual or olfactory (AVO) senses to observe leaks. Record results and corrective action taken.

Other: 28VHP and 28PI LDAR programs. H2S is only present in stream as an Look for leaks twice per shift using audio, visual or olfactory (AVO) impurity. Compliance with the 28VHP F-CrudeFlex Fugitives: Piping and Equipment Leak H2S No senses to observe leaks. Record results and corrective action taken. LDAR program for these components meets monitoring requirements.

Look for leaks twice per shift using audio, visual or olfactory (AVO) Propose AVO inspections 1xshift. See Propose AVO inspections 1xshift. See F-CrudeFlex Fugitives: Piping and Equipment Leak NH3 No senses to observe leaks. Record results and corrective action taken. Section 5. Section 5.

F-CrudeFlex Fugitives: Piping and Equipment Leak CH4 See additional notes: Yes See CO2 Equivalent Other: See CO2 Equivalent F-CrudeFlex Fugitives: Piping and Equipment Leak CO2 Equivalent See additional notes: Yes 28VHP and 28PI LDAR programs. Other: 28VHP and 28PI LDAR programs.

F-CrudeFlex Fugitives: Piping and Equipment Leak

F-CrudeFlex Fugitives: Piping and Equipment Leak

F-CrudeFlex Fugitives: Piping and Equipment Leak

F-CrudeFlex Fugitives: Piping and Equipment Leak

F-CrudeFlex Fugitives: Piping and Equipment Leak

F-CrudeFlex Fugitives: Piping and Equipment Leak

F-CrudeFlex Fugitives: Piping and Equipment Leak

F-CrudeFlex Fugitives: Piping and Equipment Leak

Version 4.0 Page 5 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Monitoring Company: Phillips 66 Company

Proposed Measurement Technique (only complete for FIN Unit Type Pollutant Minimum Monitoring Requirements Confirm Additional Notes for Monitoring Additional Notes for Measuring: pollutants with a project increase above the PSD threshold)

Other: Compliance with 40 CFR Part 63.670 for Compliance with 40 CFR Part 63.670 for flare MSS flare MSS and compliance with and compliance with boilerplate MSS special MSS Planned MSS NOX See additional notes: boilerplate MSS special conditions for conditions for MSS emissions to atmosphere and from MSS emissions to atmosphere and from temporary control devices. temporary control devices.

Other: Compliance with 40 CFR Part 63.670 for Compliance with 40 CFR Part 63.670 for flare MSS flare MSS and compliance with and compliance with boilerplate MSS special MSS Planned MSS CO See additional notes: boilerplate MSS special conditions for conditions for MSS emissions to atmosphere and from MSS emissions to atmosphere and from temporary control devices. temporary control devices. Other: Compliance with 40 CFR Part 63.670 for Compliance with 40 CFR Part 63.670 for flare MSS flare MSS and compliance with and compliance with boilerplate MSS special MSS Planned MSS SO2 See additional notes: boilerplate MSS special conditions for conditions for MSS emissions to atmosphere and from MSS emissions to atmosphere and from temporary control devices. temporary control devices. Other: Compliance with 40 CFR Part 63.670 for Compliance with 40 CFR Part 63.670 for flare MSS flare MSS and compliance with and compliance with boilerplate MSS special MSS Planned MSS VOC See additional notes: boilerplate MSS special conditions for conditions for MSS emissions to atmosphere and from MSS emissions to atmosphere and from temporary control devices. temporary control devices. Other: Compliance with 40 CFR Part 63.670 for Compliance with 40 CFR Part 63.670 for flare MSS flare MSS and compliance with The emission monitoring techniques for PM10 and PM2.5 will follow the and compliance with boilerplate MSS special MSS Planned MSS PM boilerplate MSS special conditions for technique for PM. See additional notes: conditions for MSS emissions to atmosphere and from MSS emissions to atmosphere and from temporary control devices. temporary control devices.

MSS Planned MSS CO2 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent MSS Planned MSS CH4 See additional notes: See CO2 Equivalent Other: See CO2 Equivalent MSS Planned MSS N2O See additional notes: See CO2 Equivalent Other: See CO2 Equivalent Other: Compliance with 40 CFR Part 63.670 for Compliance with 40 CFR Part 63.670 for flare MSS flare MSS and compliance with and compliance with boilerplate MSS special MSS Planned MSS CO2 Equivalent See additional notes: boilerplate MSS special conditions for conditions for MSS emissions to atmosphere and from MSS emissions to atmosphere and from temporary control devices. temporary control devices.

MSS Planned MSS

MSS Planned MSS

MSS Planned MSS

MSS Planned MSS

Version 4.0 Page 6 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Monitoring Company: Phillips 66 Company

Proposed Measurement Technique (only complete for FIN Unit Type Pollutant Minimum Monitoring Requirements Confirm Additional Notes for Monitoring Additional Notes for Measuring: pollutants with a project increase above the PSD threshold)

Daily Flow into treatment plant. Other: Quarterly AVO check of water seal where site wastewater emissions >5tpy Unit is a gravity flow sump. Comply with Unit is a gravity flow sump. Comply with NSPS QQQ F-SUMPCCR Wastewater Facilities VOC For Activated Sludge Biological Treatment, daily mixed liquor Yes NSPS QQQ and/or NESHAP FF for and/or NESHAP FF for wastewater collection suspended solids (MLSS) wastewater collection component. component. Monthly wastewater concentration of all air contaminants entering treatment plant.

Version 4.0 Page 7 Texas Commission on Environmental Quality Date: March 2020 Form PI-1 General Application Permit #: TBD Materials Company: Phillips 66 Company

Item How submitted Date submitted A. Administrative Information Form PI-1 General Application Email 04/03/2020 Hard copy of the General sheet with original (ink) signature Mail 04/03/2020 Professional Engineer Seal Email 04/03/2020 B. General Information Copy of current permit (both Special Conditions and MAERT) Core Data Form Area map Email 04/03/2020 Plot plan Email 04/03/2020 Process description Email 04/03/2020 Process flow diagram Email 04/03/2020 List of MSS activities Email 04/03/2020 State regulatory requirements discussion Email 04/03/2020 C. Federal Applicability Summary and project emission increase determination - Tables 1F and 2F Email 04/03/2020 Netting analysis (if required) - Tables 3F and 4F as needed Email 04/03/2020 D. Technical Information BACT discussion, if additional details are attached Email 04/03/2020 Monitoring information, if additional details are attached Email 04/03/2020 Material Balance (if applicable) Email 04/03/2020 Calculations Email 04/03/2020 E. Impacts Analysis Qualitative impacts analysis MERA analysis Electronic Modeling Evaluation Workbook: SCREEN3 Not applicable Electronic Modeling Evaluation Workbook: NonSCREEN3 Email 04/03/2020 PSD modeling protocol Email 04/03/2020 F. Additional Attachments

Version 4.0 Page 1

Texas Commission on Environmental Quality Form APD-APS Air Permitting Surcharge Payment

I. Contact Information Company or Other Legal Customer Name: Phillips 66 Company Customer Reference Number (CN): CN604065912 Regulated Entity Number (RN): RN102495884 Company Official or Technical Contact Information: ( Mr. Mrs. Ms. Other: ) Name: Russell Hill Title: Senior Environmental Consultant Mailing Address: P.O. Box 271 City: Borger State: TX UT ZIP Code: 79008 Telephone Number: 806-275-1348 E-mail Address: [email protected] II. Project Information Facility Name: Phillips 66 Borger Refinery

Permit Number: TBD - Initial Project Number: TBD III. Surcharge Payment Project Type: Federal NSR Fee Amount: $ 20,000 Check, Money Order, Transaction Number, and/or ePay Voucher Number: (below)

Paid Online: YES NO

Company Name on Check: WRB Refining LP

TCEQ-20707 (APDG 6260v4, Revised 01/17) Form APD-APS Air Permitting Surcharge Payment This form for use by facilities subject to air quality permits requirements and may be revised periodically. Page __1___ of ___1__ Texas Com m ission on Environm ental Quality Table 2 Material Balance

This material balance table is used to quantify possible emissions of air contaminants and special emphasis should be placed on potential air contaminants, for example: If feed contains sulfur, show distribution to all products. Please relate each material (or group of materials) listed to its respective location in the process flow diagram by assigning em ission point numbers (taken from the flow diagram) to each material.

List every material involved in Em ission Point Process Rate 1 2 Measurement Estim ation Calculation each of the following groups No. from Flow Check appropriate column at right to Diagram indicate process rate method. Raw Materials - Input Crude Oil: 175,000 BPD X NGL: 3.3M BPSD

Fu els - Input 7 3 MM SCFD X

Products and By-Products - Output Gasolines: 96.2 MPD X Distillates: 71.7 MBPD Butanes and Lighter: 4.7 BPD Su lfu r: 214 LTPD average and 420 LTPD peak Coke: 1.6 Short Tons/Day Solid Was t es - Output

Liquid Wastes - Output

Airborne Waste (Solid) - Output See General PI-1 form X

Airborne Wastes (Gaseous) - Output See General PI-1 form X

1 Specify the process rate of the facility using conventional engineering units (e.g., bbl/d, lb/yr, SCFM), and indicate the units next to each number. Standard Conditions: are 68°F 14.7 psia (30 Texas Administrative Code, Section 101.1(99). 2 Only rates for major products are provided. Rates are representative only and should not be considered as limits. TCEQ-10155 (APDG 6194v3, Revised 06 /16) Table 2 This form is for use by facilities subject to air quality permit requirements and may be revised periodically. Page 1 of 1 Texas Commission on Environmental Quality Table 6 Boilers and Heaters

Equipment Information Type of Device: Heater Manufacturer: TBD Model Number: TBD Emission Point Number (EPN) (from Flow Diagram): 28-H3 Fuel Characteristics (choose applicable fuel characteristics, or revise from typical values shown) Fuel Type Hours Use Per Fuel Sulfur Content Higher Heating Value Year and Units and Units Natural Gas 8760 2 gr / 100 dscf 1020 Btu/scf

No. 2 Fuel Oil

Propane

Plant Fuel Gas 8760 162 ppmv (3-hour) 841 Btu/scf 60 ppmv (Annual) Landfill Gas

Other:

Fuel Firing Rate Design Maximum: 192.50 Units (MMBtu/hr is preferred): MMBtu/hr Stack Parameters (not required if represented on page 2 of Table 1(a)) Stack Diameter (ft): 9 Stack Height (ft): 96 Stack gas velocity at maximum fuel flow rate (ft/second): 15 Stack Gas Temperature (°F): 330 Exhaust (scfm*): 57,255 Exhaust Air Flow and Excess Air Exhaust Air Flow (scfm*): Percentage of Excess Air: Control Device (if present) Add on Control Device (type, description): SCR

TCEQ-10163 (APDG 6196v2, Revised 06/16) Table 6 This form is for use by facilities subject to air quality permit requirements and may be revised periodically. Page 1 of 2 Texas Commission on Environmental Quality Table 6 Boilers and Heaters

Characteristics of Output: Outlet Concentrations to be used as Emission Factors (confirm applicable fuel characteristics, revise from typical values shown, or enter applicable value) Material Chemical Composition of Exit Gas Released (% by volume)

NOx 13 ppmv corrected to 3% O2**

CO 100 ppmv corrected to 3% O2** (hourly avg.)

1 VOC 5 ppmv corrected to 3% O2

Formaldehyde (should be subset of VOC)

SO2 Assume 100% conversion of fuel sulfur to SO2**

PM/PM10/PM2.5 0.89 lb/MM Dscf

Others (such as Ammonia): Ammonia 10 ppmvd at 3% O2**

Attach an explanation on how temperature, air flow rate, excess air or other operating variables are controlled. * Standard Conditions: 68°F, 14.7 psia ** Values shown are typical for natural gas fired boilers; confirm with your vendor.

1 Assumed VOC MW of 44.09 lb/lb-mole for propane TCEQ-10163 (APDG 6196v2, Revised 06/16) Table 6 This form is for use by facilities subject to air quality permit requirements and may be revised periodically. Page 2 of 2 Texas Commission on Environmental Quality Table 6 Boilers and Heaters

Equipment Information Type of Device: Heater Manufacturer: TBD Model Number: TBD Emission Point Number (EPN) (from Flow Diagram): 28-H4 Fuel Characteristics (choose applicable fuel characteristics, or revise from typical values shown) Fuel Type Hours Use Per Fuel Sulfur Content Higher Heating Value Year and Units and Units Natural Gas 8760 2 gr / 100 dscf 1020 Btu/scf

No. 2 Fuel Oil

Propane

Plant Fuel Gas 8760 162 ppmv (3-hour) 841 Btu/scf 60 ppmv (Annual) Landfill Gas

Other:

Fuel Firing Rate Design Maximum: 192.50 Units (MMBtu/hr is preferred): MMBtu/hr Stack Parameters (not required if represented on page 2 of Table 1(a)) Stack Diameter (ft): 9 Stack Height (ft): 96 Stack gas velocity at maximum fuel flow rate (ft/second): 15 Stack Gas Temperature (°F): 330 Exhaust (scfm*): 57,255 Exhaust Air Flow and Excess Air Exhaust Air Flow (scfm*): Percentage of Excess Air: Control Device (if present) Add on Control Device (type, description): SCR

TCEQ-10163 (APDG 6196v2, Revised 06/16) Table 6 This form is for use by facilities subject to air quality permit requirements and may be revised periodically. Page 1 of 2 Texas Commission on Environmental Quality Table 6 Boilers and Heaters

Characteristics of Output: Outlet Concentrations to be used as Emission Factors (confirm applicable fuel characteristics, revise from typical values shown, or enter applicable value) Material Chemical Composition of Exit Gas Released (% by volume)

NOx 13 ppmv corrected to 3% O2**

CO 100 ppmv corrected to 3% O2** (hourly avg.)

1 VOC 5 ppmv corrected to 3% O2

Formaldehyde (should be subset of VOC)

SO2 Assume 100% conversion of fuel sulfur to SO2**

PM/PM10/PM2.5 0.89 lb/MM Dscf

Others (such as Ammonia): Ammonia 10 ppmvd at 3% O2**

Attach an explanation on how temperature, air flow rate, excess air or other operating variables are controlled. * Standard Conditions: 68°F, 14.7 psia ** Values shown are typical for natural gas fired boilers; confirm with your vendor.

1 Assumed VOC MW of 44.09 lb/lb-mole for propane TCEQ-10163 (APDG 6196v2, Revised 06/16) Table 6 This form is for use by facilities subject to air quality permit requirements and may be revised periodically. Page 2 of 2 Texas Commission on Environmental Quality Table 6 Boilers and Heaters

Equipment Information Type of Device: Heater Manufacturer: TBD Model Number: TBD Emission Point Number (EPN) (from Flow Diagram): 88-H1 Fuel Characteristics (choose applicable fuel characteristics, or revise from typical values shown) Fuel Type Hours Use Per Fuel Sulfur Content Higher Heating Value Year and Units and Units Natural Gas 8760 2 gr / 100 dscf 1020 Btu/scf

No. 2 Fuel Oil

Propane

Plant Fuel Gas 8760 162 ppmv (3-hour) 841 Btu/scf 60 ppmv (Annual) Landfill Gas

Other:

Fuel Firing Rate Design Maximum: 412.90 Units (MMBtu/hr is preferred): MMBtu/hr Stack Parameters (not required if represented on page 2 of Table 1(a)) Stack Diameter (ft): 7 Stack Height (ft): 189 Stack gas velocity at maximum fuel flow rate (ft/second): 29 Stack Gas Temperature (°F): 470 Exhaust (scfm*): 66,963 Exhaust Air Flow and Excess Air Exhaust Air Flow (scfm*): Percentage of Excess Air: Control Device (if present) Add on Control Device (type, description): SCR

TCEQ-10163 (APDG 6196v2, Revised 06/16) Table 6 This form is for use by facilities subject to air quality permit requirements and may be revised periodically. Page 1 of 2 Texas Commission on Environmental Quality Table 6 Boilers and Heaters

Characteristics of Output: Outlet Concentrations to be used as Emission Factors (confirm applicable fuel characteristics, revise from typical values shown, or enter applicable value) Material Chemical Composition of Exit Gas Released (% by volume)

NOx 13 ppmv corrected to 3% O2**

CO 100 ppmv corrected to 3% O2** (hourly average)

1 VOC 5 ppmv corrected to 3% O2

Formaldehyde (should be subset of VOC)

SO2 Assume 100% conversion of fuel sulfur to SO2**

PM/PM10/PM2.5 0.89 lb / MM Dscf

Others (such as Ammonia): Ammonia 10 ppmvd at 3% O2**

Attach an explanation on how temperature, air flow rate, excess air or other operating variables are controlled. * Standard Conditions: 68°F, 14.7 psia ** Values shown are typical for natural gas fired boilers; confirm with your vendor.

1 Assumed VOC MW of 44.09 lb/lb-mole for propane TCEQ-10163 (APDG 6196v2, Revised 06/16) Table 6 This form is for use by facilities subject to air quality permit requirements and may be revised periodically. Page 2 of 2

APPENDIX B: BACT ANALYSES - SUPPORTING DOCUMENTATION This appendix includes supporting documentation for the BACT analyses provided in Section 5 and Section 6, as follows. • Table B-1: RBLC Search Results for Process Heaters and Boilers; • Table B-2: RBLC Search Results for Equipment Fugitives; • Table B-3: RBLC Search Results for Planned MSS Operations; • Table B-4: RBLC Search Results for Process Unit Sumps; and • Table B-5: RBLC Search Results for CCR Regeneration Vents.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT Firing Rates Between 100 MMBtu/hr and 250 MMBtu/hr OK-0170 Holly Refinery And Tulsa Refinery East 2012-1062-C(M- 11/12/2015 Process Heater 100 MMBTUH Carbon Monoxide Ultra Low-Nox Burner 0.04 LB/MMBTU 3-Hour Marketing - Tulsa Llc 6)PSD OK-0170 Holly Refinery And Tulsa Refinery East 2012-1062-C(M- 11/12/2015 Process Heater 100 MMBTUH Nitrogen Oxides (Nox) Ultra Low-Nox Burner 0.03 LB/MMBTU 3-Hour Marketing - Tulsa Llc 6)PSD OK-0170 Holly Refinery And Tulsa Refinery East 2012-1062-C(M- 11/12/2015 Process Heater 100 MMBTUH Particulate Matter, Total Fueled By Refinery Fuel Gas 0.0075 LB/MMBTU 3-Hour Marketing - Tulsa Llc 6)PSD OH-0362 None Listed Lima Refining Company P0114527 12/23/2013 Vacuum Unit Ii Heater 102.3 MMBTU/H Carbon Monoxide Good Combustion Practices 0.04 LB/MMBTU Per 365 Day (B001) Rolling Average OH-0362 None Listed Lima Refining Company P0114527 12/23/2013 Vacuum Unit Ii Heater 102.3 MMBTU/H GHG Use Of Low-Carbon Gaseous Fuels 54151 T/Y Per Rolling 12 (B001) (Refinery Fuel Gas Or Natural Gas); Month Period Heat Recovery Through Use Of A Convection Section And Boiler Feed Water Preheating; And Excess Oxygen Monitoring And Annual Burner Tuning And Heater Inspection.

OH-0362 None Listed Lima Refining Company P0114527 12/23/2013 Vacuum Unit Ii Heater 102.3 MMBTU/H Sulfur Dioxide (SO2) None Listed 11.09 T/Y Per Rolling 12 (B001) Month Period TX-0812 GRAVITY MIDSTREAM CRUDE OIL 9342A, 9343A, 10/31/2016 Industrial Boilers and 104 MMBTU/H GHG An automated air-fuel controller shall be 54800 T/YR CORPUS CHRISTI LLC PROCESSING FACILITY PSDTX963M1, Furnaces (Natural gas used to ensure a minimum net thermal GHGP fired) efficiency of 80%. IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Ammonia Catalyst Startup 106.3 MMBTU/H Carbon Monoxide Natural Gas Combustion Only, Proper 37.23 LB/MMCF 3-Hr Average Llc Heater Design And Good Combustion Practices

IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Ammonia Catalyst Startup 106.3 MMBTU/H GHG Natural Gas Combustion Only, Proper 59.61 TON/MMCF 3-Hr Average Llc Heater Design And Good Combustion Practices

IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Ammonia Catalyst Startup 106.3 MMBTU/H Nitrogen Oxides (Nox) Natural Gas Combustion Only, Proper 183.7 LB/MMCF 3-Hr Average Llc Heater Design And Good Combustion Practices

IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Ammonia Catalyst Startup 106.3 MMBTU/H Particulate Matter, Total Natural Gas Combustion Only, Proper 7.6 LB/MMCF 3-Hr Average Llc Heater Design And Good Combustion Practices

IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Ammonia Catalyst Startup 106.3 MMBTU/H Particulate Matter, Total Natural Gas Combustion Only, Proper 7.6 LB/MMCF 3-Hr Average Llc Heater Design And Good Combustion Practices

IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Ammonia Catalyst Startup 106.3 MMBTU/H Particulate Matter, Total Natural Gas Combustion Only, Proper 1.9 LB/MMCF 3-Hr Average Llc Heater Design And Good Combustion Practices

IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Ammonia Catalyst Startup 106.3 MMBTU/H Volatile Organic Natural Gas Combustion Only, Proper 5.5 LB/MMCF 3-Hr Average Llc Heater Compounds (VOC) Design And Good Combustion Practices

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 1 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT *TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 STRIPPER HEATER 117.3 MMBTU/H Carbon Monoxide Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 STRIPPER HEATER 117.3 MMBTU/H GHG Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 STRIPPER HEATER 117.3 MMBTU/H Nitrogen Oxides (NOx) The heater is equipped with ultra-low NOx 0.035 LB/MMBTU LLC REFINERY AND burners. GHGPSDTX121M1 Tier III cost analysis determined $140,596 per controlled. SCR is not considered economically feasible. No SCR equipped.

Fuel usage is monitored continuously and exiting emission are monitored via CEMS.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 STRIPPER HEATER 117.3 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 STRIPPER HEATER 117.3 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 STRIPPER HEATER 117.3 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 2 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT *TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 STRIPPER HEATER 117.3 MMBTU/H Sulfur Dioxide (SO2) Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 STRIPPER HEATER 117.3 MMBTU/H Volatile Organic Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Compounds (VOC) reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

OK-0166 Holly Rfnry And Mktg - Tulsa Rfnry West 2010-599-C(M- 4/20/2015 Process Heater 125 MMBTUH Carbon Monoxide Ultra Low-Nox Burners. 0.04 LB/MMBTU 3-Hr Tulsa Llc 3)PSD OK-0166 Holly Rfnry And Mktg - Tulsa Rfnry West 2010-599-C(M- 4/20/2015 Process Heater 125 MMBTUH GHG Gas Fuel And Energy Efficiency. 146 LB/MMBTU None Listed Tulsa Llc 3)PSD OK-0166 Holly Rfnry And Mktg - Tulsa Rfnry West 2010-599-C(M- 4/20/2015 Process Heater 125 MMBTUH Nitrogen Oxides (Nox) Ultra Low-Nox Burners. 0.03 LB/MMBTU 3-Hr Tulsa Llc 3)PSD OK-0166 Holly Rfnry And Mktg - Tulsa Rfnry West 2010-599-C(M- 4/20/2015 Process Heater 125 MMBTUH Particulate Matter, Total Ultra Low-Nox Burners And Use Of Gas 0.0075 LB/MMBTU 3-Hours Tulsa Llc 3)PSD Fuel. OK-0166 Holly Rfnry And Mktg - Tulsa Rfnry West 2010-599-C(M- 4/20/2015 Process Heater 125 MMBTUH Particulate Matter, Total Ultra Low-Nox Burners And Use Of Gas 0.0075 LB/MMBTU 3-Hours Tulsa Llc 3)PSD Fuel. OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 127 MMBTUH Carbon Monoxide Ultra Low-Nox Burners And Gas Fuel 0.04 LB/MMBTU None Listed Tulsa Llc 1)PSD OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 127 MMBTUH GHG Gas Fuel;Energy Efficiency 146 LB/MMBTU None Listed Tulsa Llc 1)PSD OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 127 MMBTUH Nitrogen Oxides (Nox) Ultra Low-Nox Burners 0.03 LB/MMBTU None Listed Tulsa Llc 1)PSD OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 127 MMBTUH Particulate Matter, Total Gas Fuel 0.0075 LB/MMBTU None Listed Tulsa Llc 1)PSD OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 127 MMBTUH Particulate Matter, Total Gas Fuel 0.0075 LB/MMBTU None Listed Tulsa Llc 1)PSD LA-0282 Phillips 66 Company Alliance Refinery PSD-LA-696(M-2) 4/2/2015 Low Sulfur Gasoline Feed 130 MM Btu/hr Nitrogen Oxides (Nox) Ultra Low Nox Burners With Internal Flue 6 LB/HR Hourly Heater No. 1 (294-H-1, Eqt Gas Recirculation Maximum 0017) LA-0282 Phillips 66 Company Alliance Refinery PSD-LA-696(M-2) 4/2/2015 Low Sulfur Gasoline Feed 130 MM Btu/hr Volatile Organic Good Combustion Practices And Good 0.81 LB/HR Hourly Heater No. 1 (294-H-1, Eqt Compounds (VOC) Engineering Design Maximum 0017) *TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Greater than 100 MMBtu/lb 140.1 MMBTU/H Carbon Monoxide Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Fractionation Heater reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 3 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT *TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Greater than 100 MMBtu/lb 140.1 MMBTU/H GHG Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Fractionation Heater reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Greater than 100 MMBtu/lb 140.1 MMBTU/H Nitrogen Oxides (NOx) Maximum heating capacity greater than 100 0.035 LB/MMBTU LLC REFINERY AND Fractionation Heater MMBtu/hr and required to be equipped GHGPSDTX121M1 with ultra-low NOx burners. Tier III cost analysis determined $53,200 per controlled ton. SCR is not considered economically feasible. No SCR equipped.

Good combustion practices will be used to reduce NOx including maintain proper air- to-fuel ratio, necessary residence time, temperature and turbulent.

Fuel usage is monitored continuously and exiting emission are monitored via CEMS.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Greater than 100 MMBtu/lb 140.1 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Fractionation Heater reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Greater than 100 MMBtu/lb 140.1 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Fractionation Heater reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Greater than 100 MMBtu/lb 140.1 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Fractionation Heater reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Greater than 100 MMBtu/lb 140.1 MMBTU/H Sulfur Dioxide (SO2) Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Fractionation Heater reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Greater than 100 MMBtu/lb 140.1 MMBTU/H Volatile Organic Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Fractionation Heater Compounds (VOC) reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 4 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT TX-0756 CASTLETON CCI CORPUS CHRISTI 116072 AND 6/19/2015 Charge Heaters, H-1 andH- 153 MMBtu/hr (max) Volatile Organic Good combustion practices will limit VOC 0.005 LB/ 100 SCF EACH HEATER COMMODITIES CONDENSATE PSDTX1388 2 Compounds (VOC) emissions to 0.005 lb per 1000 scf. Fuel flow INTERNATIONAL (CCI) SPLITTER FACILITY will be measured. CORPUS C LA-0283 Phillips 66 Company Alliance Refinery PSD-LA-696(M-3) 8/14/2015 Low Sulfur Gasoline Feed 168 MM BTU/HR Nitrogen Oxides (Nox) Ultra Low Nox Burners With Internal Flue 10.08 LB/HR Hourly Heater No. 1 (294-H-1, Eqt Gas Recirculation Maximum 0017) LA-0283 Phillips 66 Company Alliance Refinery PSD-LA-696(M-3) 8/14/2015 Low Sulfur Gasoline Feed 168 MM BTU/HR Volatile Organic Good Combustion Practices And Good 0.91 LB/HR Hourly Heater No. 1 (294-H-1, Eqt Compounds (VOC) Engineering Design Maximum 0017) LA-0290 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Hot Oil Heater (Eqt 623) 171 MMBTU/HR Carbon Monoxide Good Combustion Practices And The Tune- 7.34 LB/HR Hourly Complex Gtl Lab-2 Unit Up Provisions Of 40 Cfr 63 Subpart Maximum DDDDD LA-0290 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Hot Oil Heater (Eqt 623) 171 MMBTU/HR GHG Use Of Natural Gas As Feedstock And 89564 TPY Annual Complex Gtl Lab-2 Unit Good Combustion Practices Maximum

LA-0290 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Hot Oil Heater (Eqt 623) 171 MMBTU/HR Nitrogen Oxides (Nox) Ultra Low Nox Burners (Ulnb) 7.97 LB/HR Hourly Complex Gtl Lab-2 Unit Maximum

LA-0290 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Hot Oil Heater (Eqt 623) 171 MMBTU/HR Particulate Matter, Total Use Of Gaseous Fuels And Good 1.56 LB/HR Hourly Complex Gtl Lab-2 Unit Combustion Practices Maximum

LA-0290 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Hot Oil Heater (Eqt 623) 171 MMBTU/HR Particulate Matter, Total Use Of Gaseous Fuels And Good 1.56 LB/HR Hourly Complex Gtl Lab-2 Unit Combustion Practices Maximum

LA-0290 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Hot Oil Heater (Eqt 623) 171 MMBTU/HR Sulfur Dioxide (SO2) Use Of Gaseous Fuels With A Sulfur 12.34 LB/HR Hourly Complex Gtl Lab-2 Unit Content Of No More Than 0.005 Gr/Scf Maximum (Annual Average) LA-0290 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Hot Oil Heater (Eqt 623) 171 MMBTU/HR Volatile Organic Good Combustion Practices And The Tune- 1.13 LB/HR Hourly Complex Gtl Lab-2 Unit Compounds (VOC) Up Provisions Of 40 Cfr 63 Subpart Maximum DDDDD *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Fractionator Feed Heater 191.07 MMBtu/hr Carbon Monoxide None Listed 0.035 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Fractionator Feed Heater 191.07 MMBtu/hr Nitrogen Oxides (Nox) Low Nox Burner And Low Btu Fuel Gas 0.03 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Fractionator Feed Heater 191.07 MMBtu/hr Particulate Matter, Total None Listed 0.0039 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Fractionator Feed Heater 191.07 MMBtu/hr Particulate Matter, Total None Listed 0.0009 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Fractionator Feed Heater 191.07 MMBtu/hr Particulate Matter, Total None Listed 0.0008 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Fractionator Feed Heater 191.07 MMBtu/hr Sulfur Dioxide (SO2) Low Sulfur Content Fuel Gas 0.0006 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Fractionator Feed Heater 191.07 MMBtu/hr Volatile Organic None Listed 0.0054 LB/MMBTU None Listed Gtl Plant Compounds (VOC) OK-0143 Holly Refinery And Tulsa Refinery West 98-014-C(M-19)PSD 3/1/2012 Natural Gas And Refinery 214.6 MMBTUH GHG Use Of An Economizer And 206 LB CO2E/1000 30-Day Rolling Marketing - Tulsa Llc Gas-Fired Boiler Microprocessor-Based Control System. LB STEA Avg

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 5 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT DE-0020 Valero Energy Corp Valero Delaware City AQM-003/00016 2/26/2010 Package Boilers (2004) 216 MMBtu per hour Nitrogen Oxides (Nox) None Listed 0.02 LB/MMBTU 3-Hr Average Refinery IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Four (4) Natural Gas-Fired 218 MMBTU/HR, Carbon Monoxide Proper Design And Good Combustion 37.22 LB/MMCF 3-Hr Average Llc Boilers EACH Practices IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Four (4) Natural Gas-Fired 218 MMBTU/HR, GHG Proper Design And Good Combustion; 59.61 TONS/MMCF 3-Hr Average Llc Boilers EACH Energy Efficient Design: Air Inlet Controls, Heat Recovery, Condensate Recovery And Blowdown Heat Recovery

IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Four (4) Natural Gas-Fired 218 MMBTU/HR, Nitrogen Oxides (Nox) Ultra Low Nox Burners Flue Gas 20.4 LB/MMCF 24-Hr Average Llc Boilers EACH Recirculation IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Four (4) Natural Gas-Fired 218 MMBTU/HR, Particulate Matter, Total Proper Design And Good Combustion 7.6 LB/MMCF 3-Hr Average Llc Boilers EACH Practices IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Four (4) Natural Gas-Fired 218 MMBTU/HR, Particulate Matter, Total Proper Design And Good Combustion 7.6 LB/MMCF 3-Hr Average Llc Boilers EACH IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Four (4) Natural Gas-Fired 218 MMBTU/HR, Particulate Matter, Total Proper Design And Good Combustion 1.9 LB/MMCF 3-Hr Average Llc Boilers EACH Practices IN-0179 Ohio Valley Resources, Llc Ohio Valley Resources, 147-32322-00062 9/25/2013 Four (4) Natural Gas-Fired 218 MMBTU/HR, Volatile Organic Proper Design And Good Combustion 5.5 LB/MMCF 3-Hr Average Llc Boilers EACH Compounds (VOC) Practices *TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Isomar Charge Heater 220.4 MMBTU/H Carbon Monoxide Good combustion practices will be used to 50 PPMV 3% O2 LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Isomar Charge Heater 220.4 MMBTU/H GHG Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Isomar Charge Heater 220.4 MMBTU/H Nitrogen Oxides (NOx) The heater is equipped with ultra-low NOx 0.035 LB/MMBTU HOURLY LLC REFINERY AND burners and a SCR1. GHGPSDTX121M1 Fuel usage is monitored continuously and exiting emission are monitored via CEMS. Good combustion practices will be used to reduce emissions including maintain proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 6 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT *TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Isomar Charge Heater 220.4 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Isomar Charge Heater 220.4 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Isomar Charge Heater 220.4 MMBTU/H Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Isomar Charge Heater 220.4 MMBTU/H Sulfur Dioxide (SO2) Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 Isomar Charge Heater 220.4 MMBTU/H Volatile Organic Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Compounds (VOC) reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulence. Combustion of pipeline-quality natural gas.

WY-0071 Sinclair Wyoming Refining Sinclair Refinery MD-12620 10/15/2012 581 Crude Heater 233 MMBTU/H Carbon Monoxide Good Combustion Practices 0.04 LB/MMBTU 3-Hr Average Company WY-0071 Sinclair Wyoming Refining Sinclair Refinery MD-12620 10/15/2012 581 Crude Heater 233 MMBTU/H Nitrogen Oxides (Nox) Ultra Low Nox Burners 0.03 LB/MMBTU 3-Hr Average Company WY-0071 Sinclair Wyoming Refining Sinclair Refinery MD-12620 10/15/2012 581 Crude Heater 233 MMBTU/H Sulfur Dioxide (SO2) Follow Subpart Ja Fuel Gas H2S Limits 0 None Listed None Listed Company DE-0020 Valero Energy Corp Valero Delaware City AQM-003/00016 2/26/2010 Crude Unit Vacuum Heater 240 MMBTU/H Ammonia (NH3) Ammonia Slip From SCR 10 PPMVD @ 3% O2 None Listed Refinery 21-H-2 LA-0303 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-779 5/23/2014 Hot Oil Heater (Eqt 1161) 240 MM BTU/HR Carbon Monoxide Good Combustion Practices And 8.4 LB/HR Hourly Complex Ziegler Alcohol Compliance With The Applicable Maximum Unit Provisions Of 40 Cfr 63 Subpart DDDDD

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 7 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT LA-0303 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-779 5/23/2014 Hot Oil Heater (Eqt 1161) 240 MM BTU/HR GHG Good Combustion Practices 145933 TPY Annual Complex Ziegler Alcohol Maximum Unit DE-0020 Valero Energy Corp Valero Delaware City AQM-003/00016 2/26/2010 Crude Unit Vacuum Heater 240 MMBTU/H Nitrogen Oxides (Nox) SCR 0.04 LB/MMBTU 3-Hr Rolling Av Refinery 21-H-2 LA-0303 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-779 5/23/2014 Hot Oil Heater (Eqt 1161) 240 MM BTU/HR Nitrogen Oxides (Nox) Ultra Low Nox Burners (Ulnb) 9.12 LB/HR Hourly Complex Ziegler Alcohol Maximum Unit LA-0303 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-779 5/23/2014 Hot Oil Heater (Eqt 1161) 240 MM BTU/HR Particulate Matter, Total Use Of Gaseous Fuels And Good 1.79 LB/HR Hourly Complex Ziegler Alcohol Combustion Practices Maximum Unit LA-0303 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-779 5/23/2014 Hot Oil Heater (Eqt 1161) 240 MM BTU/HR Particulate Matter, Total Use Of Gaseous Fuels And Good 1.79 LB/HR Hourly Complex Ziegler Alcohol Combustion Practices Maximum Unit LA-0303 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-779 5/23/2014 Hot Oil Heater (Eqt 1161) 240 MM BTU/HR Sulfur Dioxide (SO2) Use Of Gaseous Fuels With A Sulfur 14.12 LB/HR Hourly Complex Ziegler Alcohol Content Of No More Than 0.005 Grains Per Maximum Unit Standard Cubic Foot (Gr/Scf) (Annual Average) LA-0303 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-779 5/23/2014 Hot Oil Heater (Eqt 1161) 240 MM BTU/HR Volatile Organic Good Combustion Practices And 1.29 LB/HR Hourly Complex Ziegler Alcohol Compounds (VOC) Compliance With The Applicable Maximum Unit Provisions Of 40 Cfr 63 Subpart DDDDD

OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 248 MMBTUH Carbon Monoxide Ultra Low-Nox Burners And Gas Fuel 0.04 LB/MMBTU None Listed Tulsa Llc 1)PSD TX-0847 Premcor Refining Group Valero Port Arthur 6825A, N65, 9/16/2018 Heater Epn E-02-843 248 MMBTU/HR Carbon Monoxide Good Combustion 50 PPMVD None Listed Refinery PSDTX49M1, GHGPSDT OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 248 MMBTUH GHG Gas Fuel And Energy Efficiency. 146 LB/MMBTU None Listed Tulsa Llc 1)PSD TX-0847 Premcor Refining Group Valero Port Arthur 6825A, N65, 9/16/2018 Heater Epn E-02-843 248 MMBTU/HR GHG Fuel Gas, Good Combustion Practices 0 None Listed None Listed Refinery PSDTX49M1, GHGPSDT LA-0326 Citgo Petroleum Corporation Lake Charles PSD-LA-222(M-2) 11/7/2017 3(Xxii)1 C-Reformer B-501, 248 MM BTU/H Nitrogen Oxides (Nox) Good Combustion Practices With 0.19 LB/MM BTU One Hour Block Manufacturing Complex - B-502, B-506 Furnaces, Continuous Oxygen Monitor In The Flue. Average Reformer Area Normal Operations Maintain Proper Flue Gas Oxygen Content.

LA-0326 Citgo Petroleum Corporation Lake Charles PSD-LA-222(M-2) 11/7/2017 3(Xxii)1 C-Reformer B-501, 248 MM BTU/H Nitrogen Oxides (Nox) Good Combustion Practices. 47.12 LB/H Hourly Manufacturing Complex - 502, 506 Furnace, Start- Maximum Reformer Area Up/Shutdown

OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 248 MMBTUH Nitrogen Oxides (Nox) Ultra Low-Nox Burners And Gas Fuel. 0.03 LB/MMBTU None Listed Tulsa Llc 1)PSD TX-0847 Premcor Refining Group Valero Port Arthur 6825A, N65, 9/16/2018 Heater Epn E-02-843 248 MMBTU/HR Nitrogen Oxides (Nox) Good Combstion & SCR 0.015 LB/MMBTU None Listed Refinery PSDTX49M1, GHGPSDT OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 248 MMBTUH Particulate Matter, Total Gas Fuel. 0.0075 LB/MMBTU None Listed Tulsa Llc 1)PSD

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 8 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT OK-0167 Holly Rfnry And Mktg - Tulsa Rfnry East 2012-1062-C(M- 4/20/2015 Process Heater 248 MMBTUH Particulate Matter, Total Gas Fuel. 0.0075 LB/MMBTU None Listed Tulsa Llc 1)PSD TX-0847 Premcor Refining Group Valero Port Arthur 6825A, N65, 9/16/2018 Heater Epn E-02-843 248 MMBTU/HR Particulate Matter, Total Fuel Gas, Good Combustion Practices 0.0075 LB/MMBTU None Listed Refinery PSDTX49M1, GHGPSDT TX-0847 Premcor Refining Group Valero Port Arthur 6825A, N65, 9/16/2018 Heater Epn E-02-843 248 MMBTU/HR Particulate Matter, Total Fuel Gas, Good Combustion Practices 0.0075 LB/MMBTU None Listed Refinery PSDTX49M1, GHGPSDT TX-0847 Premcor Refining Group Valero Port Arthur 6825A, N65, 9/16/2018 Heater Epn E-02-843 248 MMBTU/HR Volatile Organic Good Combustion 0.0054 LB/MMBTU None Listed Refinery PSDTX49M1, Compounds (VOC) GHGPSDT LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Fractionator Feed Heaters 248.7 MMBTU/H Carbon Monoxide Good Combustion Practices And The Tune- 8.86 LB/HR Hourly Complex Gtl Unit (Eqt 737 &Amp; 774) Up Provisions Of 40 Cfr 63 Subpart Maximum DDDDD LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Fractionator Feed Heaters 248.7 MMBTU/H GHG Use Of Natural Gas As Feedstock And 153286 TPY Annual Complex Gtl Unit (Eqt 737 &Amp; 774) Good Combustion Practices Maximum (Eqt 737) LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Fractionator Feed Heaters 248.7 MMBTU/H Nitrogen Oxides (Nox) Ultra Low Nox Burners (Ulnb) 9.62 LB/HR Hourly Complex Gtl Unit (Eqt 737 &Amp; 774) Maximum

LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Fractionator Feed Heaters 248.7 MMBTU/H Particulate Matter, Total Use Of Gaseous Fuels And Good 1.89 LB/HR Hourly Complex Gtl Unit (Eqt 737 &Amp; 774) Combustion Practices Maximum

LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Fractionator Feed Heaters 248.7 MMBTU/H Particulate Matter, Total Use Of Gaseous Fuels And Good 1.89 LB/HR Hourly Complex Gtl Unit (Eqt 737 &Amp; 774) Combustion Practices Maximum

LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Fractionator Feed Heaters 248.7 MMBTU/H Sulfur Dioxide (SO2) Use Of Gaseous Fuels With A Sulfur 14.89 LB/HR Hourly Complex Gtl Unit (Eqt 737 &Amp; 774) Content Of No More Than 0.005 Gr/Scf Maximum (Annual Average) LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Fractionator Feed Heaters 248.7 MMBTU/H Volatile Organic Good Combustion Practices And The Tune- 1.37 LB/HR Hourly Complex Gtl Unit (Eqt 737 &Amp; 774) Compounds (VOC) Up Provisions Of 40 Cfr 63 Subpart Maximum DDDDD

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 9 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT Firing Rates Between 300 MMBtu/hr and 500 MMBtu/hr IL-0128 Citgo Petroleum Corporation Citgo Petroleum 17060030 4/11/2018 Two Rfg-Fired Boilers 340 mmBtu/hr GHG Energy Efficient Design, Good Combustion 230 LB/LB STEAM 12-Month Corporation Practices, Boiler Maintenance And Annual Rolling Average Tune-Ups. IL-0128 Citgo Petroleum Corporation Citgo Petroleum 17060030 4/11/2018 Two Rfg-Fired Boilers 340 mmBtu/hr Particulate Matter, Total Energy Efficient Design And Operation 0.0075 LB/MMBTU 3-Hour Average Corporation With Good Combustion Practices.

IL-0128 Citgo Petroleum Corporation Citgo Petroleum 17060030 4/11/2018 Two Rfg-Fired Boilers 340 mmBtu/hr Particulate Matter, Total Energy Efficient Design And Operated 0.0075 LB/MMBTU 3-Hour Average Corporation With Good Combustion Practices. *TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 REFORMATE HEATER 353.4 MMBtu Carbon Monoxide Good combustion practices will be used to 50 PPMV 3% O2 LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulent.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 REFORMATE HEATER 353.4 MMBtu GHG Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulent.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 REFORMATE HEATER 353.4 MMBtu Nitrogen Oxides (NOx) The heater equipped with ultra-low NOx 0.035 LB/MMBTU HOURLY LLC REFINERY AND burners and a SCR. GHGPSDTX121M1 Fuel usage is monitored continuously and exiting emissions are monitored via CEMS.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 REFORMATE HEATER 353.4 MMBtu Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulent.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 REFORMATE HEATER 353.4 MMBtu Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulent.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 REFORMATE HEATER 353.4 MMBtu Particulate Matter, Total Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulent.

*TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 REFORMATE HEATER 353.4 MMBtu Sulfur Dioxide (SO2) Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND reduce emissions including maintain GHGPSDTX121M1 proper air-to-fuel ratio, necessary residence time, temperature and turbulent. Use of natural gas.

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 10 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT *TX-0873 MOTIVA ENTERPRISES PORT ARTHUR PSDTX1062M3 2/4/2020 REFORMATE HEATER 353.4 MMBtu Volatile Organic Good combustion practices will be used to 0 None Listed None Listed LLC REFINERY AND Compounds (VOC) reduce VOC including maintain proper air- GHGPSDTX121M1 to-fuel ratio, necessary residence time, temperature and turbulent.

TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 364.6 MMBTU/H Carbon Monoxide None Listed 50 PPM None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu) TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 364.6 MMBTU/H GHG None Listed 130 LB/MMBTU None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu) TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 364.6 MMBTU/H Nitrogen Oxides (Nox) Selective Catalytic Reduction (SCR) 0.015 LB/MMBTU None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu) TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 364.6 MMBTU/H Particulate Matter, Total None Listed 2.72 LB/HR None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu) LA-0270 Phillips 66 Company Lake Charles Refinery PSD-LA-763 9/16/2013 High Pressure Boiler B-7 375 MMBTU/H GHG Energy Efficiency Measures: A Non- 81.6 TONS/MM LB 12-Month (Eqt 0586) Condensing Economizer, An Automated STEAM Rolling Average Blowdown System, Advanced Burner Controls, And Water Pre-Heaters. Boiler Will Be Equipped With Ultra-Low Nox Burners, And Phillips 66 Will Employ Advanced Burner Controls Which Measure The Stack Gas Oxygen Concentration And Automatically Adjust The Inlet Air At The Burner For Optimum Efficiency.

*AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Sgu Process Heater 391.5 MMBtu/hr Carbon Monoxide None Listed 0.035 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Sgu Process Heater 391.5 MMBtu/hr Nitrogen Oxides (Nox) Low Nox Burners And Low Btu Fuel Gas 0.03 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Sgu Process Heater 391.5 MMBtu/hr Particulate Matter, Total None Listed 0.0039 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Sgu Process Heater 391.5 MMBtu/hr Particulate Matter, Total None Listed 0.0009 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Sgu Process Heater 391.5 MMBtu/hr Particulate Matter, Total None Listed 0.0008 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Sgu Process Heater 391.5 MMBtu/hr Sulfur Dioxide (SO2) Low Sulfur-Content Fuel Gas 0.0006 LB/MMBTU None Listed Gtl Plant *AR-0162 None Listed Energy Security Partners 2409-AOP-R0 1/10/2020 Sgu Process Heater 391.5 MMBtu/hr Volatile Organic None Listed 0.0054 LB/MMBTU None Listed Gtl Plant Compounds (VOC) IL-0115 Phillips 66 Company Wood River Refinery 6050052 1/23/2015 Boiler 19 405 MMBTU/H Carbon Monoxide Good Combustion Practices 0.02 LB/MMBTU, 30-Day Average HHV

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 11 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT IL-0115 Phillips 66 Company Wood River Refinery 6050052 1/23/2015 Boiler 19 405 MMBTU/H GHG Good Combustion Practices 0.168 LB/LB STEAM 12-Month PRODUCED Running Total IL-0115 Phillips 66 Company Wood River Refinery 6050052 1/23/2015 Boiler 19 405 MMBTU/H Volatile Organic Good Combustion Practices 0.003 LB/MMBTU, 30-Day Average Compounds (VOC) HHV LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Process Heaters (Eqt 690, 424.8 MMBTU/H Carbon Monoxide Good Combustion Practices And The Tune- 15.03 LB/H Hourly Complex Gtl Unit 691, 692, 751, 752, &Amp; Up Provisions Of 40 Cfr 63 Subpart Maximum 753) DDDDD LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Process Heaters (Eqt 690, 424.8 MMBTU/H GHG Use Of Natural Gas As Feedstock And 353891 T/YR Annual Complex Gtl Unit 691, 692, 751, 752, &Amp; Good Combustion Practices Maximum 753) LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Process Heaters (Eqt 690, 424.8 MMBTU/H Nitrogen Oxides (Nox) Ultra Low Nox Burners (Ulnb) And 21.47 LB/H Hourly Complex Gtl Unit 691, 692, 751, 752, &Amp; Selective Catalytic Reduction (SCR) Maximum 753) LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Process Heaters (Eqt 690, 424.8 MMBTU/H Particulate Matter, Total Use Of Gaseous Fuels And Good 3.2 LB/H Hourly Complex Gtl Unit 691, 692, 751, 752, &Amp; Combustion Practices Maximum 753) LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Process Heaters (Eqt 690, 424.8 MMBTU/H Particulate Matter, Total Use Of Gaseous Fuels And Good 3.2 LB/H Hourly Complex Gtl Unit 691, 692, 751, 752, &Amp; Combustion Practices Maximum 753) LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Process Heaters (Eqt 690, 424.8 MMBTU/H Sulfur Dioxide (SO2) Use Of Gaseous Fuels With A Sulfur 25.25 LB/H Hourly Complex Gtl Unit 691, 692, 751, 752, &Amp; Content Of No More Than 0.005 Gr/Scf Maximum 753) (Annual Average) LA-0291 Sasol Chemicals (Usa) Llc Lake Charles Chemical PSD-LA-778 5/23/2014 Process Heaters (Eqt 690, 424.8 MMBTU/H Volatile Organic Good Combustion Practices And The Tune- 2.32 LB/H Hourly Complex Gtl Unit 691, 692, 751, 752, &Amp; Compounds (VOC) Up Provisions Of 40 Cfr 63 Subpart Maximum 753) DDDDD *TX-0881 Exxon Mobil Oil Company Exxonmobil Beaumont 49138, 1/10/2020 Boilers 442.9 MMBTU/HR Carbon Monoxide Proper Equipment Design And Operation. 100 PPMV 3% O2 Hourly Refinery PSDTX1506M1, Good Combustion Practices And Use Of PSDTX768M2 Gaseous Fuels. *TX-0881 Exxon Mobil Oil Company Exxonmobil Beaumont 49138, 1/10/2020 Boilers 442.9 MMBTU/HR GHG Good Combustion Practices And Clean 0.0054 LB/MMBTU None Listed Refinery PSDTX1506M1, Fuels PSDTX768M2 *TX-0881 Exxon Mobil Oil Company Exxonmobil Beaumont 49138, 1/10/2020 Boilers 442.9 MMBTU/HR Particulate Matter, Total Good Combustion Practices And Clean 0.0075 LB/MMBTU None Listed Refinery PSDTX1506M1, Fuel PSDTX768M2 *TX-0881 Exxon Mobil Oil Company Exxonmobil Beaumont 49138, 1/10/2020 Boilers 442.9 MMBTU/HR Particulate Matter, Total Good Combustion Practices And Clean 0.0075 LB/MMBTU None Listed Refinery PSDTX1506M1, Fuels PSDTX768M2 *TX-0881 Exxon Mobil Oil Company Exxonmobil Beaumont 49138, 1/10/2020 Boilers 442.9 MMBTU/HR Sulfur Dioxide (SO2) Good Combustion And Clean Fuels 162 PPMV H2S Hourly Refinery PSDTX1506M1, PSDTX768M2 TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 462.3 MMBTU/H Carbon Monoxide None Listed 50 PPM None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu) TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 462.3 MMBTU/H GHG None Listed 130 LB CO2/MMBTU None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu)

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 12 of 13 Table B-1 RBLC Search Results for Process Heaters and Boilers Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 11.390 and 12.390 (Fuel Combustion Sources, Other Gaseous Fuels and Gaseous Fuel Mixtures, 100 MMBtu/hr - 250 MMBtu/hr and 250+ MMBtu/hr)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 462.3 MMBTU/H Nitrogen Oxides (Nox) None Listed 0.04 LB/MMBTU None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu) TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 462.3 MMBTU/H Particulate Matter, Total None Listed 3.44 LB/HR None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu) TX-0763 Phillips 66 Company Borger Refinery 85872, 9/4/2015 Utility And Industrial 462.3 MMBTU/H Particulate Matter, Total None Listed 3.44 LB/HR None Listed PSDTX1158M1, Boiler Greater Than 250 GHGPSDTX13 Million British Thermal Units (Mmbtu)

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 13 of 13 Table B-2 RBLC Search Results for Equipment Fugitives Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: RBLC Permits Issued After January 2010 and Process Type = 50.007 (Petroluem Refining Equipment Leaks/Fugitive Emissions)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT TX-0847 PREMCOR REFINING VALERO PORT ARTHUR 6825A, N65, PSDTX49M1, 9/16/2018 Equipment Leaks/Fugitive Emissions GHG 28 VHP N/A N/A N/A GROUP REFINERY GHGPSDT TX-0847 PREMCOR REFINING VALERO PORT ARTHUR 6825A, N65, PSDTX49M1, 9/16/2018 Equipment Leaks/Fugitive Emissions Hydrogen Sulfide 28 VHP N/A N/A N/A GROUP REFINERY GHGPSDT IL-0115 PHILLIPS 66 COMPANY WOOD RIVER REFINERY 6050052 1/23/2015 EQUIPMENT LEAKS/FUGITIVE Volatile Organic LDAR BUT LOWER LEAK N/A N/A N/A EMISSIONS Compounds (VOC) DEFINITION FOR VALVES IN G/LL SERVICE (500 PPM) AND PUMP SEALS IN LL (2000 PPM); LOW EMISSION VALVES WHERE APPROPRIATE. LA-0245 VALERO REFINING - NEW HYDROGEN PLANT PSD-LA-750 12/15/2010 Hydrogen Plant Fugitives (FUG0030) Volatile Organic LDAR program that meets LA N/A N/A N/A ORLEANS, LLC Compounds (VOC) Refinery MACT with Consent Decree Enhancements (July 26, 1994)

LA-0282 PHILLIPS 66 COMPANY ALLIANCE REFINERY PSD-LA-696(M-2) 4/2/2015 Unit Fugitives for the Low Sulfur Volatile Organic Louisiana MACT Determination N/A N/A N/A Gasoline Unit (294-FF, FUG 0004) Compounds (VOC) for Refinery Equipment Leaks (Fugitive Emission Sources) dated July 26, 1994

LA-0283 PHILLIPS 66 COMPANY ALLIANCE REFINERY PSD-LA-696(M-3) 8/14/2015 UNIT FUGITIVES FOR LOW Volatile Organic LDAR: Louisiana MACT N/A N/A N/A SULFUR GASOLINE UNIT (294-FF, Compounds (VOC) Determination for Refinery FUG 0004) Equipment Leaks (Fugitive Emission Sources) dated July 26, 1994 TX-0731 MAGELLAN PROCESSING CORPUS CHRISTI TERMINAL 118270 AND PSDTX1398 4/10/2015 , Petroleum Refining Equipment Volatile Organic Quarterly instrumental N/A N/A N/A LP CONDENSATE SPLITTER Leaks/Fugitive Emissions Compounds (VOC) monitoring using a method 21 gas analyzer for all valves, pump seals, compressor seals, and agitator seals with a leak definition of 500 parts per million volume (ppmv) for valves and 2,000 ppmv for pump, compressor and agitator seals. Leaking components must be repaired within 15 days of detection of the leak.

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 1 of 2 Table B-2 RBLC Search Results for Equipment Fugitives Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: RBLC Permits Issued After January 2010 and Process Type = 50.007 (Petroluem Refining Equipment Leaks/Fugitive Emissions)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT TX-0812 GRAVITY MIDSTREAM CRUDE OIL PROCESSING 9342A, 9343A, PSDTX963M1, 10/31/2016 Equipment Leaks Volatile Organic Quarterly instrumental N/A N/A N/A CORPUS CHRISTI LLC FACILITY GHGP Compounds (VOC) monitoring of accessible pumps, compressors and valves in vapor or light liquid service, with leak definitions of 500 ppmv (valves) and 2,000 ppmv (pump and compressor seals). Upon detection of a leak, a first attempt to repair must be made within 5 days, and repairs must be completed within 15 days.

TX-0847 PREMCOR REFINING VALERO PORT ARTHUR 6825A, N65, PSDTX49M1, 9/16/2018 Equipment Leaks/Fugitive Emissions Volatile Organic 28 VHP N/A N/A N/A GROUP REFINERY GHGPSDT Compounds (VOC) TX-0760 NUSTAR LOGISTICS LP CORPUS CHRISTI TERMINAL 32769/ PSDTX1258M1/ O- 8/6/2015 Fugitives Volatile Organic Fugitive Leak Detection and N/A N/A N/A 1238 Compounds (VOC) Repair (LDAR) per the 28 MID Monitoring program that requires quarterly monitoring of all components with a leak definition of 500 ppmv and directed maintenance.

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 2 of 2 Table B-3 RBLC Search Results for Planned MSS Operations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Contains "MSS"

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE UNIT EMISSION PERIOD LIMIT *TX-0872 Magellan Processing, L.P. Condensate Splitter Facility 118270 PSDTX1398M1 10/31/2019 Flare (Routine and MSS) N/A N/A Carbon Monoxide Use of natural gas. Good N/A N/A N/A GHGPSDTX62 combustion practices will be used to reduce CO including maintaining proper air-to-fuel ratio, necessary residence time, temperature and turbulence.

TX-0574 Valero Three Rivers Refinery Diamond Shamrock Refining PSDTX1017M1 AND 50607 8/19/2010 FLARE MSS N/A N/A Carbon Monoxide Best Practices N/A N/A SEE NOTES Company L.P. TX-0574 Valero Three Rivers Refinery Diamond Shamrock Refining PSDTX1017M1 AND 50607 8/19/2010 MSS FOR PROCESS N/A N/A Carbon Monoxide Best Practices N/A N/A SEE NOTE Company L.P. EQUIPMENT AND STORAGE TANKS TX-0827 Praxair Clear Lake Plant Praxair Inc 144239, PSDTX1512, 10/19/2017 HyCO Process Condensate N/A N/A Carbon Monoxide None Listed N/A N/A N/A GHGPSDTX164 Stripper MSS TX-0830 Praxiar Clear Lake Praxiar Inc 144239, PSDTX1512, AND 10/20/2017 HyCO Process Condensate N/A N/A Carbon Monoxide None Listed 1 TON/YR N/A GHGPSDT Stripper MSS TX-0843 Victoria Plant Invista S.A.R.L. PSDTX1079M2, 6/30/2018 MSS N/A N/A Carbon Monoxide None Listed 82 T/YR N/A GHGPSDTX145M1 *TX-0872 Magellan Processing, L.P. Condensate Splitter Facility 118270 PSDTX1398M1 10/31/2019 Flare (Routine and MSS) N/A N/A GHG Use of natural gas. Good N/A N/A N/A GHGPSDTX62 combustion practices will be used to reduce CO2e including maintaining proper air-to-fuel ratio, necessary residence time, temperature and turbulence.

*TX-0881 Exxon Mobil Oil Company Exxonmobil Beaumont 49138, PSDTX1506M1, 1/10/2020 Equipment MSS N/A N/A GHG Limited Frequency and N/A N/A N/A Refinery PSDTX768M2 Duration TX-0827 Praxair Clear Lake Plant Praxair Inc 144239, PSDTX1512, 10/19/2017 HyCO Process Condensate N/A N/A GHG None Listed N/A N/A N/A GHGPSDTX164 Stripper MSS TX-0830 Praxiar Clear Lake Praxiar Inc 144239, PSDTX1512, AND 10/20/2017 HyCO Process Condensate N/A N/A GHG Nonar Casted N/A N/A N/A GHGPSDT Stripper MSS TX-0682 Galena Park Terminal Km Liquids Terminals Llc 101199 & N158 6/12/2013 MSS-Heaters N/A N/A Nitrogen Oxides NOx emission factor will be 0.025 LB/MMBTU DURING 8 HRS (NOx) 0.025 lb/MMbtu, during 8 hours AT STARTUP at startup and 4 hours of AND 4 HRS OF shutdown NOx anual emission SHU factor from heaters when they are abating MSS emissions will be 0.006 lb/MMBtu, annually

TX-0843 Victoria Plant Invista S.A.R.L. PSDTX1079M2, 6/30/2018 MSS N/A N/A Nitrogen Oxides None Listed 14 T/YR N/A GHGPSDTX145M1 (NOx)

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 1 of 5 Table B-3 RBLC Search Results for Planned MSS Operations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Contains "MSS"

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE UNIT EMISSION PERIOD LIMIT TX-0724 Point Comfort Plant Formosa Plastics Corporation 7699 AND PSDTX226M7 11/30/2012 MSS Activities N/A N/A Particulate Matter, To control VOC with a vapor 25.18 POUND HOUR Texas Total pressure of 0.5 psia or greater at 95 degrees F, vapors will be routed to the incinerator/scrubber system until the equipment or storage tank VOC has a concentration of 10,000 ppmv or less.

TX-0574 Valero Three Rivers Refinery Diamond Shamrock Refining PSDTX1017M1 AND 50607 8/19/2010 FLARE MSS N/A N/A Sulfur Oxides (SOx) Best Practices 0 N/A SEE NOTE Company L.P. TX-0574 Valero Three Rivers Refinery Diamond Shamrock Refining PSDTX1017M1 AND 50607 8/19/2010 MSS FOR PROCESS N/A N/A Sulfur Oxides (SOx) Best Practices 0 N/A SEE NOTE Company L.P. EQUIPMENT AND STORAGE TANKS TX-0756 Castleton Commodities CCI Corpus Christi 116072 AND PSDTX1388 6/19/2015 Condensate Splitter - Process N/A N/A Volatile Organic All process equipment is N/A N/A N/A International (CCI) Corpus Condensate Splitter Facility Equipment Shutdown and Compounds (VOC) degassed to a flare meeting the C Clearing (MSS) requirements 40CFR60.18

*TX-0872 Magellan Processing, L.P. Condensate Splitter Facility 118270 PSDTX1398M1 10/31/2019 Flare (Routine and MSS) N/A N/A Volatile Organic Control for desalter N/A N/A N/A GHGPSDTX62 Compounds (VOC) wastewater, piping/vessel degassing and pressurized tank vapors. Authorized for fuel gas combustion wherein the heaters are out-of-service.

The flare is designed to meet 40 CFR §60.18 with a VOC DRE of 98% for compounds with four carbons and more, and 99% for compounds with three or less. The flare has a continuous flow monitor and composition analyzer installed.

TX-0574 Valero Three Rivers Refinery Diamond Shamrock Refining PSDTX1017M1 AND 50607 8/19/2010 FLARE MSS N/A N/A Volatile Organic Best Practices N/A N/A N/A Company L.P. Compounds (VOC)

TX-0574 Valero Three Rivers Refinery Diamond Shamrock Refining PSDTX1017M1 AND 50607 8/19/2010 MSS FOR PROCESS N/A N/A Volatile Organic VENT TO CONTROL UNTIL N/A N/A N/A Company L.P. EQUIPMENT AND Compounds (VOC) VOC CONCENTRATION < STORAGE TANKS 10,000 PPMV

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 2 of 5 Table B-3 RBLC Search Results for Planned MSS Operations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Contains "MSS"

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE UNIT EMISSION PERIOD LIMIT TX-0711 Celanese Clear Lake Plant Celanese Ltd 103626, N164, PSDTX1296 9/16/2013 Maintenance, Startup and N/A N/A Volatile Organic Small emissions are vented to N/A N/A N/A Shutdown (MSS) Compounds (VOC) the atmosphere. Larger emissions (for equipment containing materials with VP>0.5 psia) are vented to a new flare. The new flare will be constructed and operated to meet the minimum heating value and maximum exit velocity requiements of 40CFR60.18 when waste gas is routed to it.

TX-0715 Sitewide Mss Activities Formosa Plastics Corporation 83763,PSDTX1230 11/30/2012 Maintenance, Startup and N/A N/A Volatile Organic None Listed N/A N/A N/A Shutdown (MSS) Compounds (VOC)

TX-0716 High Density Polyethylene Formosa Plastics Corporation 40157,PSDTX1222 11/30/2012 Maintenance, Startup and N/A N/A Volatile Organic MSS emissions from the 10000 PPM VOC CONC IN Ii Plant Shutdown (MSS) Compounds (VOC) Attachment C MSS activities EQUIP. AFTER may be routed to the flare until VENT. TO the concentration of VOC in the FLARE equipment goes down to 10,000 ppm or reaches 10% of LEL. After that, equipment is opened to atmosphere. Flare will achieve 98% DRE for MSS VOC vented to it.

Low emitting activities are not controlled

TX-0718 Linear Low Density Formosa Plastics Corporation 20203, PSDTX1224 11/30/2012 Maintenance, Startup and N/A N/A Volatile Organic Equipments are vented to a 10000 PPMV N/A Polyethylene Plant Shutdown (MSS) Compounds (VOC) flare (98% DRE) until VOC conc. remaining in the equipments goes down to 10,000 ppm. After that, equipments are opened to atmosphere to do maintenance and repair. If LEL meters are used, equipments vented to a flare until VOC concentration reaches down to 10% LEL in the vent gases to the Flare.

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 3 of 5 Table B-3 RBLC Search Results for Planned MSS Operations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Contains "MSS"

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE UNIT EMISSION PERIOD LIMIT TX-0719 Olefins Plant Formosa Plastics Corporation 19168,PSDTX1226 11/30/2012 Maintenance, Startup and N/A N/A Volatile Organic Degassing emissions from the 10000 PPMV N/A Shutdown (MSS) Compounds (VOC) equipment will be routed to one of the Plant Flare meeting 40CFR60.18 requiements until VOC concentration remaining in the equipment goes down o 10,000 ppm or 10% of LEL (lower explosive limit). After that equipments are opened to atmosphere to do repair and maintenance.

TX-0722 Organic Chemical Chevron Phillips Chemical Lp N178 & 37063 3/14/2014 MSS N/A N/A Volatile Organic Process equipment will only be 10000 PPMV N/A Manufacturing Compounds (VOC) opened for inspection and maintenance after purging to the flare to minimize VOC content down to <10,000 ppmv or 10% of the LEL

TX-0724 Point Comfort Plant Formosa Plastics Corporation 7699 AND PSDTX226M7 11/30/2012 MSS Activities N/A N/A Volatile Organic To control VOC with a vapor 10000 PPMV N/A Texas Compounds (VOC) pressure of 0.5 psia or greater at 95 degrees F, vapors will be routed to the incinerator/scrubber system until the equipment or storage tank VOC has a concentration of 10,000 ppmv or less.

TX-0756 Cci Corpus Christi Castleton Commodities 116072 AND PSDTX1388 6/19/2015 Condensate Splitter - Process 70000 scf/hr Volatile Organic All process equipment is 178.65 LB/HR N/A Condensate Splitter Facility International (Cci) Corpus C Equipment Shutdown and Compounds (VOC) degassed to a flare meeting the Clearing (MSS) requirements 40CFR60.18

TX-0798 Cedar Bayou Plant Chevron Phillips Chemical Co. 135086, N224 5/13/2016 Boiler MSS N/A N/A Volatile Organic flares N/A N/A N/A Compounds (VOC)

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 4 of 5 Table B-3 RBLC Search Results for Planned MSS Operations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: Draft Determinations and RBLC Permits Issued After January 2010 and Contains "MSS"

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE UNIT EMISSION PERIOD LIMIT TX-0823 Lyondell Chemical Bayport Lyondell Chemical Company 137789 AND N244 6/7/2017 MSS N/A N/A Volatile Organic preparations for equipment N/A N/A N/A Choate Plant Compounds (VOC) openings, storage tank maintenance, vacuum truck operations; controlled landed roof operations, with off-float emissions routed to flare; pumping process and residual storage vessel liquids to closed vessels; depressurizing and degassing process equipment and storage vessels to below 10000 ppmv concentrations prior to opening to atmosphere; routing to control the exhaust vapors (>100 ppm) from vacuum trucks in service for materials of vapor pressures greater than 0.50 psia; controlled filling vapors at frac tanks (>0.5 psia vapor pressure service) by routing to control; control device maintenance.

TX-0851 Rio Bravo Pipeline Facility Rio Grande Lng Llc 140792, PSDTX1498, 12/17/2018 Maintenance, Startup and N/A N/A Volatile Organic GROUND FLARES N/A N/A N/A GHGPSDTX158 Shutdown (MSS) Compounds (VOC)

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 5 of 5 Table B-4 RBLC Search Results for Process Unit Sumps Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: RBLC Permits Issued After January 2010 and Contains "Sump", Draft Determinations and RBLC Permits Issued After January 2010 and Process Type = 50.009 (Petroleum Refining Wastewater and Wastewater Treatment)

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT LA-0276 COLONIAL PIPELINE BATON ROUGE JUNCTION PSD-LA-741(M4) 12/15/2016 Sumps (2) and Oil/Water None Listed None Listed Volatile Organic Good housekeeping practices None Listed None Listed None Listed COMPANY FACILITY Separators (2) Compounds (VOC) and closed top design

LA-0277 SASOL CHEMICALS (USA) COMONIMER-1 UNIT PSD-LA-814 9/1/2016 Perimeter Ditch and None Listed None Listed Volatile Organic Good Operating Practices None Listed None Listed None Listed LLC Sump Compounds (VOC) LA-0301 SASOL CHEMICALS (USA) LAKE CHARLES CHEMICAL PSD-LA-779 5/23/2014 Wastewater Drums and None Listed None Listed Volatile Organic Flare None Listed None Listed None Listed LLC COMPLEX ETHYLENE 2 UNIT Sumps Compounds (VOC)

LA-0302 SASOL CHEMICALS (USA) LAKE CHARLES CHEMICAL PSD-LA-779 5/23/2014 Glycol Sump (EQT 1075) None Listed None Listed Volatile Organic Flare None Listed None Listed None Listed LLC COMPLEX EO/MEG UNIT Compounds (VOC)

LA-0319 SASOL CHEMICALS (USA) LAKE CHARLES CHEMICAL PSD-LA-814 9/1/2016 perimeter ditch and None Listed None Listed Volatile Organic good operating practices None Listed None Listed None Listed LLC COMPLEX - COMONOMER-1 sump - pds Compounds (VOC) UNIT TX-0756 CASTLETON CCI CORPUS CHRISTI 116072 AND 6/19/2015 Wastewater Treatment None Listed None Listed Volatile Organic Overall system to achieve 90% 4.56 LB/HR None Listed COMMODITIES CONDENSATE SPLITTER PSDTX1388 Plant Compounds (VOC) of VOC from treated INTERNATIONAL (CCI) FACILITY wastewater. Oil/water CORPUS C separator is enclosed and routed to a carbon adsorption system (CAS). Process drains to be equipped with a water seal. Wastewater sewers will be enclosed. Aerobic digesters will be enclosed and directed to a CAS.

TX-0731 MAGELLAN PROCESSING CORPUS CHRISTI TERMINAL 118270 AND 4/10/2015 Petroleum Refining None Listed None Listed Volatile Organic Process wastewater shall be 0.4 TPY None Listed LP CONDENSATE SPLITTER PSDTX1398 Wastewater and Compounds (VOC) immediately directed to a Wastewater Treatment covered system. All lift stations, manholes, junction boxes, conveyances, and any other wastewater facilities shall be covered and all emissions routed to a vapor combustor with a guaranteed DRE of 99% for control.

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 1 of 1 Table B-5 RBLC Search Results for CCR Regeneration Vents Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Search: RBLC Permits Issued After January 2010 and Process Type = 50.003 Petroleum Refining Conversion Process (cracking, reforming, etc.)), SIC = 2911 RBLC Permits Issued After January 2010 and Process Contains: Continuous Catalytic Reformer or Process Contains: CCR, SIC Code: 2911 RBLC Permits Issued After January 2010 and Process Contains: Catalyst

RBLCID COMPANY NAME FACILITY NAME PERMIT # ISSUANCE PROCESS NAME T-PUT T-PUT UNIT POLLUTANT CONTROL METHOD PRIMARY UNIT AVERAGING DATE EMISSION PERIOD LIMIT MS-0092 EMBERCLEAR GTL MS EMBERCLEAR GTL MS LLC 0040-00055 5/8/2014 Catalyst Decoking 0 Carbon 44.74 LB/H 3-HR AVERAGE Monoxide *TX-0657 BEAUMONT GAS TO NATGASOLINE LLC PSDTX1340 AND 5/16/2014 Catalyst Regeneration 0 Carbon Proper operating technique to 70.73 TPY GASOLINE PLANT 107764 Monoxide limit number of events TX-0550 BASF FINA NAFTA BASF FINA 36644 2/10/2010 N-10, CATALYST 2100 CFS GHG 0 SEE NOTE - NO REGION OLEFINS PETROCHEMICALS REGENERATION EMISSION LIMIT COMPLEX LIMITED PARTNERSHIP EFFLUENT AVAILABLE TX-0675 ETHYLENE/PROPYLENE BASF FINA 36644 2/10/2010 N-10, Catalyst 0 GHG 2318 TPY OF CO2E 12-MONTH CRACKER AND PETROCHEMICALS Regeneration Effluent ROLLING TOTAL COGENERATION LIMITED PARTNERSHIP FACILITY TX-0754 PROPANE THE DOW CHEMICAL 100787 AND 7/10/2015 Propane 0 Hydrochloric Vent Scrubber with continuous 10 PPMV DEHYDROGENATION COMPANY PSDTX1314M1 Dehydrogenation-Reactor Acid emission monitoring system UNIT and Catalyst (CEMS) Regeneration Process LA-0326 LAKE CHARLES CITGO PETROLEUM PSD-LA-222(M-2) 11/7/2017 3(XXII)3 C-Reformer CCR 1100 ACFM Nitrogen Oxides 1.12 LB/H HOURLY MANUFACTURING CORPORATION Vent Gas (NOx) MAXIMUM COMPLEX - REFORMER AREA *TX-0874 PORT ARTHUR MOTIVA ENTERPRISES PSDTX1062M3, AND 2/4/2020 Continuous Catalytic 0 Nitrogen Oxides Good combustion practices will 0 REFINERY LLC GHGPSDTX156 Reformer1 Vent (NOx) be used to reduce VOC including maintain proper air-to- fuel ratio, necessary residence time, temperature and turbulent.

White Burn Mode. *TX-0874 PORT ARTHUR MOTIVA ENTERPRISES PSDTX1062M3, AND 2/4/2020 Continuous Catalytic 0 Sulfur Dioxide Good combustion practices will 0 REFINERY LLC GHGPSDTX156 Reformer1 Vent (SO2) be used to reduce VOC including maintain proper air-to- fuel ratio, necessary residence time, temperature and turbulent.

White Burn Mode.

Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Page 1 of 1

APPENDIX C: CRITERIA POLLUTANT EMISSION CALCULATIONS The following tables are included in this appendix: • Table C-1: Emissions Summary - New Sources; • Table C-2: Detailed Heater Calculations; • Table C-3: CCR Regeneration Emissions; • Table C-4: Detailed Fugitive Emission Calculations; • Table C-5: Emission Factors and Control Efficiencies; • Table C-6: Emissions Summary - Planned MSS; • Table C-7a: Turnaround - Initial Clearing Emissions (CCR); • Table C-7b: Turnaround Clearing Emissions - Pressure Purge Simulation (CCR); • Table C-8a: Turnaround - Initial Clearing Emissions (Naphtha Splitter); • Table C-8b: Turnaround Clearing Emissions - Pressure Purge Simulation (Naphtha Splitter); • Table C-9: Insignificant and Routine Equipment Maintenance; • Table C-10: Maintenance, Startup, and Shutdown Emissions - Catalyst Changeout; • Table C-11: CCR Sump Emissions.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Table C-1 Emissions Summary - New Sources Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

FIN EPN Description Hourly Emission Rates Annual Emission Rates Ref.

NOX CO SO2 PM PM10 PM2.5 VOC H2S Ammonia Chlorine HCl NOX CO SO2 PM PM10 PM2.5 VOC H2S Ammoni Chlorine HCl Table(s) a (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) 28-H3 (1) 28-H3 Crude Charge 2.89 13.48 6.16 1.43 1.43 1.43 1.04 -- 0.83 -- -- 12.65 29.51 10.12 6.28 6.28 6.28 4.55 -- 3.65 -- -- C-2 Furnace 28-H3 MSS (1) 28-H3 MSS Crude Charge 6.35 50.53 ------C-2 Furnace MSS 28-H4 (1) 28-H4 Crude Charge 2.89 13.48 6.16 1.43 1.43 1.43 1.04 -- 0.83 -- -- 12.65 29.51 10.12 6.28 6.28 6.28 4.55 -- 3.65 -- -- C-2 Furnace 28-H4 MSS (1) 28-H4 MSS Crude Charge 6.35 50.53 ------C-2 Furnace MSS 88-H1.1, 1.2, 88-H1 CCR Charger and 6.19 28.90 13.21 3.08 3.08 3.08 2.23 -- 1.79 -- -- 27.13 63.30 21.70 13.48 13.48 13.48 9.75 -- 7.83 -- -- C-2 1.3 (1) Interheaters 88-H1.1, 1.2, 88-H1 MSS CCR Charger and 9.29 108.39 ------C-2 1.3 MSS (1) Interheaters MSS CCRV 88-V1 CCR Vent 0.03 0.31 0.70 ------0.11 -- -- 0.97 0.02 0.11 1.35 3.08 ------0.46 -- -- 4.26 0.08 C-3 F-CrudeFlex F-CrudeFlex CCR/Crude Flex ------16.15 0.10 0.09 ------70.72 0.46 0.40 -- -- C-4 Fugitives F-SUMPCCR F-SUMPCCR CCR Sump ------0.40 ------1.75 ------C-11 MSS MSS Planned MSS 56.79 410.21 0.69 0.21 0.10 0.01 1,064.56 ------0.17 1.10 <0.01 <0.01 <0.01 <0.01 7.30 ------C-6 Emissions (2) Total Authorized Annual Emissions (for Public Notice) (3) 52.70 124.76 45.01 26.04 26.04 26.04 99.07 0.46 15.53 4.26 0.08 Sum

Notes (1) Annual MSS emissions from the heaters are authorized as part of the normal emissions. (2) Phillips 66 Borger Refinery is requesting a sub-cap for hourly and annual planned MSS emissions. Hourly emission rates are based on the maximum value of any one activity. Annual emissions are summed for each activity. (3) Differences in these sums and the values on the Public Notice sheet in Table 1 are due to rounding.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-2 Detailed Heater Calculations

0 1 2 5 Crude Flexibility and Modernization6 Project7 - Phillips 66 Borger9 Refinery 11 12 13 15 17 Table C-2a: Hourly Emissions FIN EPN Description Hourly Firing Fuel Heating Fuel Gas Fd Emission Factors Hourly Emission Rates (1) Rate Value Factor

(4) (5) (3) (2) (2) (6) NOX CO SO2 PM VOC Ammonia NOX CO SO2 PM VOC Ammoni a

(MMBtu/hr) (Btu/Scf) dscf/MMBtu (lb/MMBtu) (lb/MMBtu) (gr/scf H2S) (lb/MMBtu) (lb/MMBtu) (ppmvd) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (HHV) (HHV) 28-H3 28-H3 Crude Charge Heater 192.50 840.54 8,406.25 0.015 0.070 0.1 0.0075 0.0054 10 2.89 13.48 6.16 1.43 1.04 0.83 28-H4 28-H4 Crude Charge Heater 192.50 840.54 8,406.25 0.015 0.070 0.1 0.0075 0.0054 10 2.89 13.48 6.16 1.43 1.04 0.83 88-H1.1, 1.2, 88-H1 CCR Charge Heaters 412.90 840.54 8,406.25 0.015 0.070 0.1 0.0075 0.0054 10 6.19 28.90 13.21 3.08 2.23 1.79 1.3 and Interheaters 60 Table C-2b: Annual Emissions FIN EPN Description Annual Firing Fuel Heating Fuel Gas Fd Emission Factors Annual Emission Rates(1) Rate Value Factor

(4) (5) (3) (2) (2) (6) NOX CO SO2 PM VOC Ammonia NOX CO SO2 PM VOC Ammoni a

(MMBtu/hr) (Btu/Scf) dscf/MMBtu (lb/MMBtu) (lb/MMBtu) (gr/scf H2S) (lb/MMBtu) (lb/MMBtu) (ppmvd) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (HHV) (HHV) 28-H3 28-H3 Crude Charge Heater 192.50 840.54 8,406.25 0.015 0.035 0.0375 0.0075 0.0054 10 12.65 29.51 10.12 6.28 4.55 3.65 28-H4 28-H4 Crude Charge Heater 192.50 840.54 8,406.25 0.015 0.035 0.0375 0.0075 0.0054 10 12.65 29.51 10.12 6.28 4.55 3.65 88-H1.1, 1.2, 88-H1 CCR Charge Heaters 412.90 840.54 8,406.25 0.015 0.035 0.0375 0.0075 0.0054 10 27.13 63.30 21.70 13.48 9.75 7.83 1.3 and Interheaters

Table C-2c: MSS Emissions FIN EPN Description Hourly Firing Fuel Heating Fuel Gas Fd Emission Factors MSS Emission Rates (1) Rate (7) Value Factor

(4) (5) NOX (MSS) CO (MSS) NOx (MSS) CO (MSS)

(MMBtu/hr) (Btu/Scf) dscf/MMBtu (lb/MMBtu) (lb/MMBtu) (lb/hr) (lb/hr) (HHV) (HHV) 28-H3 28-H3 Crude Charge Heater 144.38 840.54 8,406.25 0.044 0.350 6.35 50.53 28-H4 28-H4 Crude Charge Heater 144.38 840.54 8,406.25 0.044 0.350 6.35 50.53 88-H1.1, 1.2, 88-H1 CCR Charge Heaters 309.68 840.54 8,406.25 0.030 0.350 9.29 108.39 1.3 and Interheaters

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 3 Table C-2 Detailed Heater Calculations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Table C-2d: Total Authorized Emission Rates FIN EPN Hourly Emission Rates (1) Annual Emission Rates(1)

NOX - Normal NOX - MSS CO - Normal CO - MSS SO2 PM VOC Ammonia NOX CO SO2 PM VOC Ammon (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy)i 28-H3 28-H3 2.89 6.35 13.48 50.53 6.16 1.43 1.04 0.83 12.65 29.51 10.12 6.28 4.55 3.65 28-H4 28-H4 2.89 6.35 13.48 50.53 6.16 1.43 1.04 0.83 12.65 29.51 10.12 6.28 4.55 3.65 88-H1.1, 1.2, 88-H1 6.19 9.29 28.90 108.39 13.21 3.08 2.23 1.79 27.13 63.30 21.70 13.48 9.75 7.83 1.3

Notes: (1) The emission factors used to estimate emissions for each pollutant from this equipment are not meant to be operational constraints. Concentrations and other operational parameters may vary. Compliance is determined based on emission rates (lb/hr and tpy). (2) PM and VOC emission factors are determined based on 1998 AP-42 factors (7.6 lb/MMscf and 5.5 lb/MMscf respectively). The factors are converted into lb/MMBtu by dividing by 1020 Btu/scf, as per Note (a) in Table 1.4-2.

(3) SO2 emissions are based on an hourly limit of 0.1 grains/dscf and an annual limit 0.0375 grains/dscf, which are equivalent to the hourly and annual NSPS Ja limitations of 162 ppmv and 60 ppmv, respectively.

(4) NOX emissions for units with SCR are based on BACT of 0.015 lb NOX/MMBtu during normal operation (refinery fuel gas) and vendor burner guarantees during MSS activities.

(5) CO emissions are based on 100 ppmv on a short-term basis to account for short-term operational variability and 50 ppmv on an annual basis, consistent with BACT requirements, during normal operation. CO emissions during MSS operations are based on 500 ppmv, consistent with the allowable limit in the TCEQ Air Quality Standard Permit for Boilers (November 3, 2006).

(6) For heaters with SCR, NH3 emissions are based on a 10 ppmv NH3 ammonia slip at 3% O2, consistent with BACT. (7) Firing rate during MSS operations is based on 75% of the design firing rate.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 2 of 3 Table C-2 Detailed Heater Calculations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery Sample Calculations: 28-H3 (Crude Charge Heater)

Proposed Maximum Short Term Emission Rates (All Pollutants except SO2 and NH3).

ERh = FRh * EFh

ERh, NOx = 192.50 MMBtu/hr * 0.015 lb/MMBtu = 2.89 lb/hr

ERh, CO = 192.50 MMBtu/hr * 0.070 lb/MMBtu = 13.48 lb/hr

ERh, PM = 192.50 MMBtu/hr * 0.0075 lb/MMBtu = 1.43 lb/hr

ERh, VOC = 192.50 MMBtu/hr * 0.0054 lb/MMBtu = 1.04 lb/hr

Proposed Maximum Short Term Emission Rate for SO2.

ERh, SO2 = (FRh * 1,000,000 Btu/MMBtu / (Btu/scf)) * EFh / (7000 gr H2S/lb H2S) / (34 lb H2S/ lb-mol H2S) * (1 lb-mol SO2/ lb-mol H2S) * (64 lb SO2/ lb-mol SO2)

ERh, SO2 = (192.50 MMBtu/hr * 1,000,000 / 840.54 Btu/scf) * 0.1 gr/scf H2S / 7,000 gr H2S / 34 lb H2S * (1 lb-mol SO2 / lb-mol H2S) * 64 lb SO2 = 6.16 lb/hr

Proposed Maximum Short Term Emission Rate for NH3 - (CCR Heaters, 88-H1)

ERh,NH3 = FRh * (Concentration in ppmvd / 1,000,000) * MW * Fd * ((20.9 - 0) / (20.9 - %O2)) / Std Vol in dscf/lb-mol

ERh,NH3 = 412.90 MMBtu/hr * (10 pppmv NH3 / 1,000,000) * 17 lb NH3/lb-mole * 8,406.25 dscf/MMBtu * ((20.9 - 0)/(20.9 - 3) / 385.40 scf/lb-mole = 1.79 lb/hr

Proposed Average Annual Emission Rates (All Pollutants except SO2 and NH3).

ERa = FRa * EFa * 8,760 / 2,000

ERa,NOx = 192.5 MMBtu/hr * 0.02 lb/MMBtu * 8,760 hr/year / 2,000 lb/ton = 12.65 tpy

ERa,CO = 192.5 MMBtu/hr * 0.035 lb/MMBtu * 8,760 hrs/year / 2,000 lb/ton = 29.51 tpy

ERa,PM = 192.5 MMBtu/hr * 0.0075 lb/MMBtu * 8,760 hrs/year / 2,000 lb/ton = 6.28 tpy

ERa,VOC = 192.5 MMBtu/hr * 0.0054 lb/MMBtu * 8,760 hrs/year / 2,000 lb/ton = 4.55 tpy

Proposed Average Annual Emission Rate for SO2.

ERa,SO2 = (FRh * 1,000,000 Btu/MMBtu / (Btu/scf)) * EFh / (7000 gr H2S/lb H2S) / (34 lb H2S/ lb-mol H2S) * (1 lb-mol SO2/ lb-mol H2S) * (64 lb SO2/ lb-mol SO2) * 8,760 hr / 2,000 lb

ERa,SO2 = (192.50 MMBtu/hr * 1,000,000 / 840.54 Btu/scf) * 0.038 gr/scf H2S / 7,000 gr H2S / 34 lb H2S * (1 lb-mol SO2 / lb-mol H2S) * 64 lb SO2 * 8,760 hrs/year / 2,000 lb/ton = 10.12 tpy

Proposed Average Annual Emission Rate for NH3 - (CCR Heaters, 88-H1)

ERa,NH3 = ERh,NH3 * 8,760 hr/year / 2,000 lb/ton

ERa,NH3 = 1.79 lb/hr * 8760 hr/year / 2,000 lb/ton = 7.83 tpy

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 3 of 3 Table C-3 CCR Regeneration Emissions Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Emission Point Number: 88-V1

Parameters Values Units Regenerator Flue Gas Mass Flow Rate (1) 1,644 lb/hr Regenerator Flue Gas Volumetric Flow Rate (1) 21,141 scf/hr (2) Cl2 Concentration in Flue Gas 0.03 vol% (2) NOX Concentration in Flue Gas 0.001 vol% (2) SO2 Concentration in Flue Gas 0.02 vol% CO Concentration in Flue Gas (2) 0.02 vol% VOC Concentration in Flue Gas (2) 0.01 vol% HCl Concentration in Flue Gas (2) 0.001 vol%

Cl2 Molecular Weight 70.91 lb/lb-mole

NOX Molecular Weight 46.01 lb/lb-mole

SO2 Molecular Weight 64.06 lb/lb-mole CO Molecular Weight 28.01 lb/lb-mole VOC Molecular Weight 16.04 lb/lb-mole HCl Molecular Weight 34.46 lb/lb-mole

Pollutant Maximum Emission Rate (3), (4) Annual Emission Rate (3), (4)

(lb/hr) (tpy)

Cl2 0.97 4.26

NOX 0.03 0.11

SO2 0.70 3.08 CO 0.31 1.35 VOC 0.11 0.46 HCl 0.02 0.08

Notes (1) The mass flow rate is converted to volumetric flow using the flue gas composition. (2) The contaminant concentrations are based on the engineering design documentation. (3) The emission factors used to estimate emissions for each pollutant from this equipment are not meant to be operational constraints. Concentrations and other operational parameters may vary. Compliance is determined based on emission rates (lb/hr and tpy).

(4) Sample Calculations (HCl) 21,141 scf/hr * 0.0010 vol% / 100 / 385.40 scf/lbmol * 34.46 lb HCl/lb-mole = 0.019 lb/hr 21,141 scf/hr * 0.0010 vol% / 100 / 385.40 scf/lbmol * 34.46 lb HCl/lb-mole * 8,760 hours/year / 2,000 lb/ton = 0.08 tpy

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-4 Detailed Fugitive Emission Calculations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Unit Fugitive Emission LDAR Component Count EPN Factors Program Lines Valves Valves Valves Pumps Pumps Flanges Flanges Flanges Sampling Sampling w/ Controlw/ Controlw/ Controlw/ Connections Open-Ended Open-Ended Relief ValvesRelief ValvesRelief ValvesRelief ValvesRelief ValvesRelief ValvesRelief Compressors Process Drains GV LL HL GV LL HL LL HL GV GV LL HL GV LL HL All All All CCR Unit F-CCR Refinery 28VHP / 1,874 1,493 115 4,759 3,873 303 52 3 5 37 0 0 0 0 0 0 34 3 28PI CCR Unit - F-CCR Refinery 28PI 188 -0- -0- 476 -0- -0- -0- 0 1 4 -0- -0- -0- -0- -0- -0- -0- -0- Natural Gas Naphtha F-NS Refinery 28VHP / 192 511 59 288 767 94 11 -0- -0- 6 -0- -0- -0- -0- -0- -0- 8 3 Splitter Unit 28PI Naphtha F-NS Refinery 28PI 20 -0- -0- 29 -0- -0- -0- -0- -0- 1 -0- -0- -0- -0- -0- -0- -0- -0- Splitter Unit - Natural Gas

Crude F-32 Refinery 28VHP / 35 255 -0- 120 630 -0- 7 -0- -0- 3 -0- -0- -0- -0- -0- 42 -0- 11 Desalter 28PI Crude Unit F-28 Refinery 28VHP / 11 62 19 9 120 34 1 1 -0- 2 -0- -0- -0- -0- -0- 14 1 1 28PI SCR F-SCR SOCMI 28AVO 147 -0- -0- 588 -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- Fugitives w/out C2 Unit 6 F-6 SOCMI 28VHP / -0- 3 -0- -0- 5 -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- Columns w/out C2 28PI Unit 2 F-2 Refinery 28VHP / -0- 16 -0- -0- 30 -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- -0- Columns 28PI Tank Farm F-53-1 Refinery 28VHP / -0- 29 -0- -0- 91 -0- 4 -0- -0- 1 -0- -0- -0- -0- -0- 15 1 1 Fugitives 28PI GOHDS Unit F-42 Refinery 28VHP / 30 54 36 16 76 31 1 1 1 1 -0- -0- -0- -0- -0- 14 -0- 1 28PI

Notes (1) Air Permit Technical Guidance Package for Chemical Sources - Equipment Leak Fugitives, TCEQ (June 2018). (2) Controlled emissions based on control efficiencies from the specified LDAR program, as shown in Table C-5. (3) Sampling connection emission factor is based on lb/hour per sample taken. The calculations conservatively assume that all sampling connections may be sampled in the same hour, for 8760 hours/year.

(4) Sample Calculations (Light Liquid Valves - CCR Unit) 1493 components * 0.024 lb/hr-component * (1 - 0.97) = 1.07 lb/hr 1.07 lb/hr * (8,760 hr/yr) * (1 ton/2,000 lbs) = 4.71 tpy Sample Calculations - Fugitive Emissions (Sampling Connections)

3 sampling connection * 0.033 lb/hr per sample taken = 0.10 lb/hr 3 sampling connection * 0.033 lb/hr per sample taken * 1 sample/hr * (8760 samples/year)/ 2,000 lb/ton = 0.43 tpy (5) Component counts and speciated emissions are based on engineering judgment and should not be considered limits.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 5 Table C-4 Detailed Fugitive Emission Calculations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Unit Fugitive Emission LDAR Uncontrolled Emission Factor (lb/hr per Component) (1), (3) EPN Factors Program Lines Valves Valves Valves Device Device Device Pumps Pumps Flanges Flanges Flanges Sampling Sampling w/ Controlw/ Controlw/ Controlw/ Connections Open-Ended Open-Ended Relief ValvesRelief ValvesRelief ValvesRelief ValvesRelief ValvesRelief ValvesRelief Compressors Process Drains GV LL HL GV LL HL LL HL GV GV LL HL GV LL HL All All All CCR Unit F-CCR Refinery 28VHP / 0.059 0.024 0.00051 0.00055 0.00055 0.00055 0.251 0.046 1.399 0.35 0.024 0.00051 0.35 0.024 0.00051 0.0051 0.07 0.033 28PI CCR Unit - F-CCR Refinery 28PI 0.059 0.024 0.00051 0.00055 0.00055 0.00055 0.251 0.046 1.399 0.35 0.024 0.00051 0.35 0.024 0.00051 0.0051 0.07 0.033 Natural Gas Naphtha F-NS Refinery 28VHP / 0.059 0.024 0.00051 0.00055 0.00055 0.00055 0.251 0.046 1.399 0.35 0.024 0.00051 0.35 0.024 0.00051 0.0051 0.07 0.033 Splitter Unit 28PI Naphtha F-NS Refinery 28PI 0.059 0.024 0.00051 0.00055 0.00055 0.00055 0.251 0.046 1.399 0.35 0.024 0.00051 0.35 0.024 0.00051 0.0051 0.07 0.033 Splitter Unit - Natural Gas

Crude F-32 Refinery 28VHP / 0.059 0.024 0.00051 0.00055 0.00055 0.00055 0.251 0.046 1.399 0.35 0.024 0.00051 0.35 0.024 0.00051 0.0051 0.07 0.033 Desalter 28PI Crude Unit F-28 Refinery 28VHP / 0.059 0.024 0.00051 0.00055 0.00055 0.00055 0.251 0.046 1.399 0.35 0.024 0.00051 0.35 0.024 0.00051 0.0051 0.07 0.033 28PI SCR F-SCR SOCMI 28AVO 0.0089 0.0035 0.0007 0.0029 0.0005 0.00007 0.0386 0.0161 0.503 0.2293 0.0035 0.0007 0.2293 0.0035 0.0007 0.004 0.07 0.033 Fugitives w/out C2 Unit 6 F-6 SOCMI 28VHP / 0.0089 0.0035 0.0007 0.0029 0.0005 0.00007 0.0386 0.0161 0.503 0.2293 0.0035 0.0007 0.2293 0.0035 0.0007 0.004 0.07 0.033 Columns w/out C2 28PI Unit 2 F-2 Refinery 28VHP / 0.0590 0.0240 0.0005 0.0006 0.0006 0.00055 0.2510 0.0460 1.399 0.3500 0.0240 0.0005 0.3500 0.0240 0.0005 0.005 0.07 0.033 Columns 28PI Tank Farm F-53-1 Refinery 28VHP / 0.0590 0.0240 0.0005 0.0006 0.0006 0.00055 0.2510 0.0460 1.399 0.3500 0.0240 0.0005 0.3500 0.0240 0.0005 0.005 0.07 0.033 Fugitives 28PI GOHDS Unit F-42 Refinery 28VHP / 0.0590 0.0240 0.0005 0.0006 0.0006 0.00055 0.2510 0.0460 1.399 0.3500 0.0240 0.0005 0.3500 0.0240 0.0005 0.005 0.07 0.033 28PI

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 2 of 5 Table C-4 Detailed Fugitive Emission Calculations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Unit Fugitive Emission LDAR Control Efficiency (% per Component Type) EPN Factors Program evice evice evice Lines Valves Valves Valves D D D Pumps Pumps Flanges Flanges Flanges Sampling Sampling w/ Controlw/ Controlw/ Controlw/ Connections Open-Ended Open-Ended Relief ValvesRelief ValvesRelief ValvesRelief ValvesRelief ValvesRelief ValvesRelief Compressors Process Drains GV LL HL GV LL HL LL HL GV GV LL HL GV LL HL All All All CCR Unit F-CCR Refinery 28VHP / 97% 97% 30% 30% 30% 30% 85% 30% 85% 100% 100% 100% 97% 97% 30% 100% 75% 0% 28PI CCR Unit - F-CCR Refinery 28PI 30% 30% 30% 30% 30% 30% 30% 30% 30% 100% 100% 100% 30% 30% 30% 100% 75% 0% Natural Gas Naphtha F-NS Refinery 28VHP / 97% 97% 30% 30% 30% 30% 85% 30% 85% 100% 100% 100% 97% 97% 30% 100% 75% 0% Splitter Unit 28PI Naphtha F-NS Refinery 28PI 30% 30% 30% 30% 30% 30% 30% 30% 30% 100% 100% 100% 30% 30% 30% 100% 75% 0% Splitter Unit - Natural Gas

Crude F-32 Refinery 28VHP / 97% 97% 30% 30% 30% 30% 85% 30% 85% 100% 100% 100% 97% 97% 30% 100% 75% 0% Desalter 28PI Crude Unit F-28 Refinery 28VHP / 97% 97% 30% 30% 30% 30% 85% 30% 85% 100% 100% 100% 97% 97% 30% 100% 75% 0% 28PI SCR F-SCR SOCMI 28AVO 97% 97% 97% 97% 97% 97% 93% 93% 95% 100% 100% 100% 97% 97% 97% 97% 75% 0% Fugitives w/out C2 Unit 6 F-6 SOCMI 28VHP / 97% 97% 30% 30% 30% 30% 85% 30% 85% 100% 100% 100% 97% 97% 30% 100% 75% 0% Columns w/out C2 28PI Unit 2 F-2 Refinery 28VHP / 97% 97% 30% 30% 30% 30% 85% 30% 85% 100% 100% 100% 97% 97% 30% 100% 75% 0% Columns 28PI Tank Farm F-53-1 Refinery 28VHP / 97% 97% 30% 30% 30% 30% 85% 30% 85% 100% 100% 100% 97% 97% 30% 100% 75% 0% Fugitives 28PI GOHDS Unit F-42 Refinery 28VHP / 97% 97% 30% 30% 30% 30% 85% 30% 85% 100% 100% 100% 97% 97% 30% 100% 75% 0% 28PI

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 3 of 5 Table C-4 Detailed Fugitive Emission Calculations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Unit Fugitive Emission LDAR Controlled Emissions (lb/hr) (2) EPN Factors Program evice evice evice Lines Valves Valves Valves D D D Pumps Pumps Flanges Flanges Flanges Sampling Sampling w/ Controlw/ Controlw/ Controlw/ Connections Open-Ended Open-Ended Relief ValvesRelief ValvesRelief ValvesRelief ValvesRelief ValvesRelief ValvesRelief Compressors Process Drains GV LL HL GV LL HL LL HL GV GV LL HL GV LL HL All All All CCR Unit F-CCR Refinery 28VHP / 3.32 1.07 0.04 1.83 1.49 0.12 1.96 0.10 1.05 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.60 0.10 28PI CCR Unit - F-CCR Refinery 28PI 7.76 0.00 0.00 0.18 0.00 0.00 0.00 0.01 0.98 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Natural Gas Naphtha F-NS Refinery 28VHP / 0.34 0.37 0.02 0.11 0.30 0.04 0.41 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.14 0.10 Splitter Unit 28PI Naphtha F-NS Refinery 28PI 0.83 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Splitter Unit - Natural Gas

Crude F-32 Refinery 28VHP / 0.06 0.18 0.00 0.05 0.24 0.00 0.26 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.36 Desalter 28PI Crude Unit F-28 Refinery 28VHP / 0.02 0.04 0.01 0.00 0.05 0.01 0.04 0.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.02 0.03 28PI SCR F-SCR SOCMI 28AVO 0.04 0.00 0.00 0.05 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Fugitives w/out C2 Unit 6 F-6 SOCMI 28VHP / 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Columns w/out C2 28PI Unit 2 F-2 Refinery 28VHP / 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Columns 28PI Tank Farm F-53-1 Refinery 28VHP / 0.00 0.02 0.00 0.00 0.04 0.00 0.15 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.02 0.03 Fugitives 28PI GOHDS Unit F-42 Refinery 28VHP / 0 0 0 0 0 0 0 0 0 -0- -0- -0- -0- -0- -0- -0- -0- 0 28PI

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 4 of 5 Table C-4 Detailed Fugitive Emission Calculations Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Unit Fugitive Emission LDAR Emission Rates (5) EPN Factors Program Total Total Percent Percent Percent VOC Emissions Ammonia Emissions H2S Emissions

Hourly Annual VOC Ammonia H2S Emissions Emissions (4) (4)

lb/hr tpy (%) (%) (%) lb/hr tpy lb/hr tpy lb/hr tpy CCR Unit F-CCR Refinery 28VHP / 11.67 51.12 100.00 0 0.5 11.67 51.12 -0- -0- 0.06 0.26 28PI CCR Unit - F-CCR Refinery 28PI 8.94 39.14 5.00 0 0 0.45 1.96 -0- -0- -0- -0- Natural Gas Naphtha F-NS Refinery 28VHP / 1.82 7.99 100.00 0 0.5 1.82 7.99 -0- -0- 0.01 0.04 Splitter Unit 28PI Naphtha F-NS Refinery 28PI 0.84 3.67 5.00 0 0 0.04 0.18 -0- -0- -0- -0- Splitter Unit - Natural Gas

Crude F-32 Refinery 28VHP / 1.16 5.08 100.00 0 1.36 1.16 5.08 -0- -0- 0.02 0.07 Desalter 28PI Crude Unit F-28 Refinery 28VHP / 0.25 1.11 100.00 0 1.30 0.25 1.11 -0- -0- <0.01 0.01 28PI SCR F-SCR SOCMI 28AVO 0.09 0.40 -0- 100 0 -0- -0- 0.09 0.40 -0- -0- Fugitives w/out C2 Unit 6 F-6 SOCMI 28VHP / <0.01 0.01 100.00 0 0 <0.01 0.01 -0- -0- -0- -0- Columns w/out C2 28PI Unit 2 F-2 Refinery 28VHP / 0.02 0.10 100.00 0 0 0.02 0.10 -0- -0- -0- -0- Columns 28PI Tank Farm F-53-1 Refinery 28VHP / 0.26 1.13 100.00 0 0.04 0.26 1.13 -0- -0- <0.01 <0.01 Fugitives 28PI GOHDS Unit F-42 Refinery 28VHP / 0.46 2.04 100.00 0 3.88 0.46 2.04 -0- -0- 0.02 0.08 28PI

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 5 of 5 Table C-5 Emission Factors and Control Efficiencies Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Component Stream Uncontrolled Emission Factor (1) Monitoring Program Emission Reduction Type Credits (1), (2) Refinery SOCMI w/out 28VHP / 28PI 28PI 28AVO C2 (lb/hr/comp.) (lb/hr/comp.) Valves GV 0.059 0.0089 97% 30% 97% Valves LL 0.024 0.0035 97% 30% 97% Valves HL 0.00051 0.0007 30% 30% 97% Pumps LL 0.251 0.0386 85% 30% 93% Pumps HL 0.046 0.0161 30% 30% 93% Flanges GV 0.00055 0.0029 30% 30% 97% Flanges LL 0.00055 0.0005 30% 30% 97% Flanges HL 0.00055 0.00007 30% 30% 97% Compressors GV 1.399 0.5027 85% 30% 95% Relief Valves GV 0.35 0.2293 97% 30% 97% Relief Valves LL 0.024 0.0035 97% 30% 97% Relief Valves HL 0.00051 0.0007 30% 30% 97% Relief Valves w/ Control GV 0.35 0.2293 100% 100% 100% Device (3) Relief Valves w/ Control LL 0.024 0.0035 100% 100% 100% Device (3) Relief Valves w/ Control HL 0.00051 0.0007 100% 100% 100% Device (3) Open-ended Lines ALL 0.0051 0.004 100% 100% 97% Sampling Connections ALL 0.033 0.033 0% 0% 0% Process Drains (4) ALL 0.07 0.07 75% 75% 75%

Notes: (1) APDG 6422 Air Permit Technical Guidance for Chemical Sources - Fugitive Guidance , TCEQ (06/2018). (2) 30% reduction taken for valves and pumps in heavy liquid service to take credit for weekly visual walk through. (3) Relief Valves w/ Control Device values were used for relief valves that were routed to a control device or back to process or equipped with a rupture disc. (4) Process drains are given a 75% control efficiency since they will be equipped with p-traps and will comply with the monitoring/inspection requirements of BWON/NSPS QQQ.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-6 Emissions Summary - Planned MSS Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

FIN EPN Description Hourly Emission Rates (2) Annual Emission Rates (2) Reference

NOX CO SO2 PM PM10 PM2.5 VOC NOX CO SO2 PM PM10 PM2.5 VOC Table(s) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) CCR-MSS CCR-MSS_C Turn Around Clearing - 56.79 410.21 0.69 ------1,064.56 0.14 0.96 <0.01 ------2.44 C-7b CCR (Flare) CCR-MSS CCR-MSS_U Turn Around Clearing ------31.20 ------0.16 C-7a CCR (Atmosphere) NS-MSS NS-MSS_C Turn Around Clearing - 46.51 239.61 0.40 ------621.82 0.03 0.14 <0.01 ------0.36 C-8b Naphtha Splitter (Flare) NS-MSS NS-MSS_U Turn Around Clearing ------4.56 ------0.02 C-8a Naphtha Splitter (Atmosphere) MISC-MSS MISC-MSS Insignificant and Routine 0.05 0.05 0.05 0.21 0.10 0.01 224.45 <0.01 <0.01 <0.01 <0.01 <0.01 <0.01 4.32 C-9 MSS MSS MSS Planned MSS Emissions (1) 56.79 410.21 0.69 0.21 0.10 0.01 1,064.56 0.17 1.10 <0.01 <0.01 <0.01 <0.01 7.30 Sum of Above

Notes (1) Annual MSS emissions from the heaters are authorized as part of the normal emissions. (2) The emission factors used to estimate emissions for each pollutant from these activities are not meant to be operational constraints. Concentrations and other operational parameters may vary. Compliance is determined based on emission rates (lb/hr and tpy).

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-7a Turnaround - Initial Clearing Emissions (CCR) Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Parameter Symbol Value Units Notes

Temperature T = 80 °F Estimated temperature

Unit Volume V = 189,128 ft³ Estimated volume from Engineering documents

Unit Surface Area SA = 364,836 ft² Estimated volume from Engineering documents

Vapor Molecular Weight MW = 65 lb/mol Estimated average vapor molecular weight

Initial VOC Concentration CVOC = 100 % Conservatively assume 100% VOC (1) Initial Pressure PI = 114.7 psia Estimated initial pressure (100 psig + 14.7 psi)

Initial moles of Vapor in Unit Ni,v = 3,746.21 lb-mol = PI * V * CVOC / (10.73 * (T + 459.67))

Clingage Thickness tc = 0.0004 in Conservative estimate - from TCEQ Guidance Document Specific Gravity of Liquid SG = 0.80 dim-less Estimated specific gravity of liquids 3 Initial Moles of Liquid in Unit Ni,l = 9.3 mole = SA * tc * 8.34 lb/gal * 7.48 gal/ft * SG / MW (2) Initial moles of VOC in Unit Ni = 3,755.5 mole = Ni,v + Ni,l

Flare Pressure Pmin = 14.696 psia (3) Moles in Depressured Equipment Nmin = 480.0 moles = Pmin*V/(10.73*(T+459.67))

Control Pressure Pmax = 20 psia Assumed pressure at top of pressure purge. (4) Moles in Pressurized Unit Nmax = 653.2 mole = Pmax*V/(10.73*(T+459.67)) Destruction Efficiency η = 98 % TCEQ Guidance Document for Flares and Vapor Oxidizers (October 2000) Heating Value HHV = 22,000 Btu/lb Assumed heating value of hydrocarbon (5) Moles purged N = 173.23 mole = Nmax - Nmin

Post-Degassing Concentration xVOC = 10,000 ppmv TCEQ BACT for Equipment Opening

Flare BTU Target HHVmin = 270 btu/scf MACT CC Minimum Allowable BTU Value Events/year n = 1 event/year Assume one event per year Degassing time t = 10 hours Estimated degassing duration

Residual VOC in Unit mvoc,atme = 311.99 lb/event = xVOC/10^6*MW*Pmin*V/(10.73*(T+459.67))

Residual VOC to Atmosphere - Hrly mvoc,atmh = 31.20 lb/hr = mvoc,atme / t

Residual VOC to Atmosphere - Ann. mvoc,atma = 0.16 tpy = mvoc,atme * n / 2,000 lb/ton

Notes: (1) Initial pressure at unit shutdown. (2) Represents the initial moles contained inside the CCR Unit. Used as basis for material balance after each purge. (3) Calculation of the total moles in the unit at the bottom of the depressure cycle. Ideal Gas law using flare header pressure. (4) Calculation of the total moles in the tank at the top of the pressure cycle. Ideal Gas law using relief valve set pressure.

(5) Mole balance for one pressure purge. Moles of N2 are brought in to pressure the vessel up and dilute the VOC. Depressurization releases the same moles at the new concentration. It is assumed that each purge cycle uses the same moles of N2.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-7b Turnaround Clearing Emissions - Pressure Purge Simulation (CCR) Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) (3) (4) (9), (10) (12) (12) (14) Purge HC in Unit Moles, HC Frac HC Flared Moles N2 Flare BTU NG to Flare Adjusted VOC Emissions Flare Combustion CO Emission NOx Emissions SO2 Emissions Cycle Pressurized (2) Purged (5) Value (6) (7) Flare Heating Heat Release (11) Value (8)

Ni Nmax xi Nvoc,i NN2,i LHVi NNG,i LHVa mvoc,i Q (number) (mole) (mole) (frac) (mole) (mole) (Btu/scf) (mole) (Btu/scf) (lb/purge) (lb/hr) (MMBtu) (lb) (lb/hr) (lb) (lb/hr) (lb) (lb/hr) 0 3,755.55 1.00 3,275.56 3,711.70 0.00 3,711.70 4,258.23 1,064.56 4,684.05 1,640.82 410.21 227.18 56.79 2.76 0.69 1 479.99 653.22 0.735 127.29 45.94 2,727.36 0.00 2,727.36 165.48 41.37 182.03 63.76 15.94 12.38 3.09 0.11 2.68E-02 2 352.69 653.22 0.54 93.53 79.70 2,004.06 0.00 2,004.06 121.59 30.40 133.75 46.85 11.71 9.10 2.27 0.08 1.97E-02 3 259.16 653.22 0.40 68.73 104.50 1,472.59 0.00 1,472.59 89.35 22.34 98.28 34.43 8.61 6.68 1.67 0.06 1.45E-02 4 190.43 653.22 0.29 50.50 122.73 1,082.06 0.00 1,082.06 65.65 16.41 72.22 25.30 6.32 4.91 1.23 0.04 1.06E-02 5 139.93 653.22 0.21 37.11 136.12 795.09 0.00 795.09 48.24 12.06 53.07 18.39 4.60 3.61 0.90 3.12E-02 7.80E-03 6 102.82 653.22 0.16 27.27 145.97 584.24 0.00 584.24 35.45 8.86 38.99 13.51 3.38 2.65 0.66 2.29E-02 5.73E-03 7 75.55 653.22 0.12 20.04 153.20 429.30 0.00 429.30 26.05 6.51 28.65 9.93 2.48 1.95 0.49 1.69E-02 4.21E-03 8 55.52 653.22 0.08 14.72 158.51 315.45 0.00 315.45 19.14 4.78 21.05 7.29 1.82 1.43 0.36 1.24E-02 3.10E-03 9 40.79 653.22 0.06 10.82 162.42 231.79 14.49 270.00 14.06 3.52 19.53 6.77 1.69 1.33 0.33 1.15E-02 2.87E-03 10 29.97 653.22 0.05 7.95 165.28 170.32 37.80 270.00 10.33 2.58 21.95 7.61 1.90 1.49 0.37 1.29E-02 3.23E-03 11 22.03 653.22 0.03 5.84 167.39 125.15 54.94 270.00 7.59 1.90 23.73 8.22 2.06 1.61 0.40 1.40E-02 3.49E-03 12 16.18 653.22 0.02 4.29 168.94 91.96 67.52 270.00 5.58 1.39 25.04 8.68 2.17 1.70 0.43 1.47E-02 3.68E-03 13 11.89 653.22 0.02 3.15 170.08 67.57 76.77 270.00 4.10 1.02 26.01 9.01 2.25 1.77 0.44 1.53E-02 3.82E-03 14 8.74 653.22 0.01 2.32 170.92 49.65 83.57 270.00 3.01 0.75 26.71 9.26 2.31 1.82 0.45 1.57E-02 3.93E-03 15 6.42 653.22 0.01 1.70 171.53 36.48 88.56 270.00 2.21 0.55 27.23 9.44 2.36 1.85 0.46 1.60E-02 4.00E-03 Annual tpy (13) Max lb/hr Annual (MMBtu/yr) Annual tpy (13) Max lb/hr Annual tpy (13) Max lb/hr Annual tpy (13) Max lb/hr 2.44 1,064.56 798.3 0.96 410.21 0.14 56.79 0.002 0.69 Notes

(1) Initial HC in unit is based on Table C-7a. After the initial purge cycle, Ni = (Ni-1 - NVOCi - 1)

(2) Based on Nmax from Table C-7a.

(3) Mole fraction of hydrocarbon in the unit on each pressure purge. [xi = Ni/Nmax]

(4) The amount of VOC released during the purge is the product of the mole fraction and the moles purged. [Nvoc,i = xi*N]

(5) The balance of the purge amount and the amount of VOC released during the purge. [NN2,i = N - Nvoc,i]

(6) Aggregate BTU value of VOC and Nitrogen. [LHV = Nvoc,i*MW*LHVvoc/(N*10.73*527.7/14.696)] (7) Moles of fuel gas required to increase the flare heating value to 270 Btu/scf if the aggregate heating value is lower than 270 Btu/scf.

(8) Aggregate BTU value of hydrocarbon and Nitrogen with Natural Gas added. Total BTU's divided by total scf. [LHV = (Nvoc,i*MW*LHV+NNG,i*16*17,500)/((Nvoc,i+NN2,i+NNG,i)*10.73*527.7/14.696)]

(9) Mass emission rates, on a per purge basis, taking into account the 98% flare destruction efficiency. [mvoc,i = Nvoc,i*MW*(1-η)] (10) Hourly emission rates assume that each purge cycle takes 4 hours, based on a flow limitation through the 1/2" flare valve.

(11) Heat Released from burning hydrocarbons in the flare. Assumes a MW of 16 for fuel gas (pure methane) and a heating value of 17,500 Btu/lb [Q = (Nvoc,i*MW*LHVvoc+NNG,i*16*17,500)/10^6]

(12) Emission factors for CO and NOX are for steam-assisted flares from TCEQ's Guidance Document for "Flares and Vapor Oxidizers" (October 2000). The emissions factors are listed below: High Btu Low Btu

EFCO = 0.3503 0.3465 lb/MMBtu

EFNOx = 0.0485 0.068 lb/MMBtu (13) Annual emissions are based on the sum of emissions from each purge cycle, divided by 2,000, assuming one event per year.

(14) SO2 emissions are calculated using an emission factor 0.6 lb/MMScf from Table 1.4-2 from AP-42 Chapter 1.4 (July 200) to account for a natual gas purge. Minimal sulfur is expected in the unit since it is downstream of a hydrotreating unit. The emission factor is converted to lb/MMBtu by dividing by 1020 Btu/scf (0.6 lb/MMScf / 1020 Btu/scf = 0.0006 lb/MMBtu).

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-8a Turnaround - Initial Clearing Emissions (Naphtha Splitter) Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Parameter Symbol Value Units Notes

Temperature T = 80 °F Estimated temperature Unit Volume V = 27,618 ft³ Estimated volume of unit Unit Surface Area SA = 46,173 ft² Estimated surface area of unit Vapor Molecular Weight MW = 65 lb/mol Estimated average vapor molecular weight

Initial VOC Concentration CVOC = 100 % Conservatively assume 100% VOC (1) Initial Pressure PI = 115 psia Estimated initial pressure (100 psig + 14.7)

Initial moles of Vapor in Unit Ni,v = 547.05 lb-mol = PI * V * CVOC / (10.73 * (T + 459.67))

Clingage Thickness tc = 0.0004 in Conservative estimate - from TCEQ Guidance Document Specific Gravity of Liquid SG = 0.80 dim-less Estimated specific gravity of liquids 3 Initial Moles of Liquid in Unit Ni,l = 1.2 mole = SA * tc * 8.34 lb/gal * 7.48 gal/ft * SG / MW (2) Initial moles of VOC in Unit Ni = 548.2 mole = Ni,v + Ni,l

Flare Pressure Pmin = 14.696 psia (3) Moles in Depressured Equipment Nmin = 70.1 moles = Pmin*V/(10.73*(T+459.67))

Control Pressure Pmax = 20 psia Assumed pressure at top of pressure purge. (4) Moles in Pressurized Unit Nmax = 95.4 mole = Pmax*V/(10.73*(T+459.67)) Destruction Efficiency η = 98 % TCEQ Guidance Document for Flares and Vapor Oxidizers (October 2000) Heating Value HHV = 22,000 Btu/lb Assumed heating value of hydrocarbon (5) Moles purged N = 25.30 mole = Nmax - Nmin

Post-Degassing Concentration xVOC = 10,000 ppmv TCEQ BACT for Equipment Opening

Flare BTU Target HHVmin = 270 btu/scf MACT CC Minimum Allowable BTU Value Events/year n = 1 event/year Assume one event per year Degassing time t = 10 hours Estimated degassing duration

Residual VOC in Unit mvoc,atme = 45.56 lb/event = xVOC/10^6*MW*Pmin*V/(10.73*(T+459.67))

Residual VOC to Atmosphere - Hrly mvoc,atmh = 4.56 lb/hr = mvoc,atme / t

Residual VOC to Atmosphere - Ann. mvoc,atma = 0.02 tpy = mvoc,atme * n / 2,000 lb/ton

Notes: (1) Initial pressure at unit shutdown. (2) Represents the initial moles contained inside the Naphtha Splitter Unit. Used as basis for material balance after each purge. (3) Calculation of the total moles in the unit at the bottom of the depressure cycle. Ideal Gas law using flare header pressure. (4) Calculation of the total moles in the tank at the top of the pressure cycle. Ideal Gas law using relief valve set pressure.

(5) Mole balance for one pressure purge. Moles of N2 are brought in to pressure the vessel up and dilute the VOC. Depressurization releases the same moles at the new concentration. It is assumed that each purge cycle uses the same moles of N2.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-8b Turnaround Clearing Emissions - Pressure Purge Simulation (Naphtha Splitter) Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) (3) (4) (9), (10) (12) (12) (14) Purge HC in Unit Moles, HC Frac HC Flared Moles N2 Flare BTU NG to Flare Adjusted VOC Emissions Flare Combustion CO Emission NOx Emissions SO2 Emissions Cycle Pressurized (2) Purged (5) Value (6) (7) Flare Heating Heat Release (11) Value (8)

Ni Nmax xi Nvoc,i NN2,i LHVi NNG,i LHVa mvoc,i Q (number) (mole) (mole) (frac) (mole) (mole) (Btu/scf) (mole) (Btu/scf) (lb/purge) (lb/hr) (MMBtu) (lb) (lb/hr) (lb) (lb/hr) (lb) (lb/hr) 0 548.23 1.00 478.14 3,711.70 0.00 3,711.70 621.58 621.58 683.74 239.51 239.51 46.49 46.49 0.40 0.40 1 70.09 95.39 0.73 18.59 6.71 2,727.36 0.00 2,727.36 24.16 24.16 26.58 9.31 9.31 1.81 1.81 0.02 1.56E-02 2 51.50 95.39 0.54 13.66 11.64 2,004.06 0.00 2,004.06 17.76 17.76 19.53 6.84 6.84 1.33 1.33 0.01 1.15E-02 3 37.84 95.39 0.40 10.04 15.26 1,472.59 0.00 1,472.59 13.05 13.05 14.35 5.03 5.03 0.98 0.98 0.01 8.44E-03 4 27.81 95.39 0.29 7.37 17.92 1,082.06 0.00 1,082.06 9.59 9.59 10.55 3.69 3.69 0.72 0.72 0.01 6.20E-03 5 20.43 95.39 0.21 5.42 19.88 795.09 0.00 795.09 7.04 7.04 7.75 2.69 2.69 0.53 0.53 4.56E-03 4.56E-03 6 15.01 95.39 0.16 3.98 21.32 584.24 0.00 584.24 5.18 5.18 5.69 1.97 1.97 0.39 0.39 3.35E-03 3.35E-03 7 11.03 95.39 0.12 2.93 22.37 429.30 0.00 429.30 3.80 3.80 4.18 1.45 1.45 0.28 0.28 2.46E-03 2.46E-03 8 8.11 95.39 0.08 2.15 23.15 315.45 0.00 315.45 2.79 2.79 3.07 1.07 1.07 0.21 0.21 1.81E-03 1.81E-03 9 5.96 95.39 0.06 1.58 23.72 231.79 2.12 270.00 2.05 2.05 2.85 0.99 0.99 0.19 0.19 1.68E-03 1.68E-03 10 4.38 95.39 0.05 1.16 24.14 170.32 5.52 270.00 1.51 1.51 3.21 1.11 1.11 0.22 0.22 1.89E-03 1.89E-03 11 3.22 95.39 0.03 0.85 24.44 125.15 8.02 270.00 1.11 1.11 3.47 1.20 1.20 0.24 0.24 2.04E-03 2.04E-03 12 2.36 95.39 0.02 0.63 24.67 91.96 9.86 270.00 0.81 0.81 3.66 1.27 1.27 0.25 0.25 2.15E-03 2.15E-03 13 1.74 95.39 0.02 0.46 24.84 67.57 11.21 270.00 0.60 0.60 3.80 1.32 1.32 0.26 0.26 2.23E-03 2.23E-03 14 1.28 95.39 0.01 0.34 24.96 49.65 12.20 270.00 0.44 0.44 3.90 1.35 1.35 0.27 0.27 2.29E-03 2.29E-03 Annual tpy (13) Max lb/hr Annual (MMBtu/yr) Annual tpy (13) Max lb/hr Annual tpy (13) Max lb/hr Annual tpy (13) Max lb/hr 0.36 621.58 796.3 0.14 239.51 0.03 46.49 2.34E-04 0.40 Notes

(1) Initial HC in unit is based on Table C-8a. After the initial purge cycle, Ni = (Ni-1 - NVOCi - 1)

(2) Based on Nmax from Table C-8a.

(3) Mole fraction of hydrocarbon in the unit on each pressure purge. [xi = Ni/Nmax]

(4) The amount of VOC released during the purge is the product of the mole fraction and the moles purged. [Nvoc,i = xi*N]

(5) The balance of the purge amount and the amount of VOC released during the purge. [NN2,i = N - Nvoc,i]

(6) Aggregate BTU value of VOC and Nitrogen. [LHV = Nvoc,i*MW*LHVvoc/(N*10.73*527.7/14.696)] (7) Moles of fuel gas required to increase the flare heating value to 270 Btu/scf if the aggregate heating value is lower than 270 Btu/scf.

(8) Aggregate BTU value of hydrocarbon and Nitrogen with Natural Gas added. Total BTU's divided by total scf. [LHV = (Nvoc,i*MW*LHV+NNG,i*16*17,500)/((Nvoc,i+NN2,i+NNG,i)*10.73*527.7/14.696)]

(9) Mass emission rates, on a per purge basis, taking into account the 98% flare destruction efficiency. [mvoc,i = Nvoc,i*MW*(1-η)] (10) Hourly emission rates assume that each purge cycle takes 4 hours, based on a flow limitation through the 1/2" flare valve.

(11) Heat Released from burning hydrocarbons in the flare. Assumes a MW of 16 for fuel gas (pure methane) and a heating value of 17,500 Btu/lb [Q = (Nvoc,i*MW*LHVvoc+NNG,i*16*17,500)/10^6]

(12) Emission factors for CO and NOX are for steam-assisted flares from TCEQ's Guidance Document for "Flares and Vapor Oxidizers" (October 2000).. The emissions factors are listed below: High Btu Low Btu

EFCO = 0.3503 0.3465 lb/MMBtu

EFNOx = 0.0485 0.068 lb/MMBtu (13) Annual emissions are based on the sum of emissions from each purge cycle, divided by 2,000, assuming one event per year.

(14) SO2 emissions are calculated using an emission factor 0.6 lb/MMScf from Table 1.4-2 from AP-42 Chapter 1.4 (July 200) to account for a natual gas purge. Minimal sulfur is expected in the unit since it is downstream of a hydrotreating unit. The emission factor is converted to lb/MMBtu by dividing by 1020 Btu/scf.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-9 Insignificant and Routine Equipment Maintenance Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Maintenance Activity Attachment Events / Hour Events / Year VOC Emissions CO Emissions SO2 Emissions PM Emissions PM10 Emissions PM2.5 Emissions NOx Emissions Emissions/ Event (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) VOC (lbs) Replacement of analyzer filters/screens Attachment A 0.05 1 100 0.05 2.50E-03

Replacement of process filters/screens Attachment A 0.2 1 100 0.20 0.01

Calibration of CEMS Analyzers (1) Attachment A 0.005 10 100 0.05 2.50E-04 0.05 2.50E-04 0.05 2.50E-04 0.05 2.50E-04 Calibration/maintenance of process Attachment A 0.1 1 100 0.10 5.00E-03 instrumentation Catalyst Changeout Attachment A See Table C-10 See Table C-10 See Table C-10 0.00 0.00E+00 0.21 8.59E-04 0.10 7.56E-04 0.01 6.77E-04 Piping Maintenance/Replacement Attachment B 0.04 1 200 0.04 3.98E-03 Valve Maintenance/Replacement Attachment B 0.002 1 200 1.69E-03 1.69E-04 Relieve Valve Maintenance/Replacement Attachment B 0.01 1 200 0.01 8.44E-04

Filter/Meter Maintenance/Replacement Attachment B 0.01 1 200 0.01 8.44E-04

Spare pump startup - HL service (2) Attachment A 0.06 1 60 0.06 1.80E-03 Carbon canister replacement (valve Attachment A 0.05 1 100 0.05 2.50E-03 disconnect) Spare pump startup - LL service (3) Attachment A 0.5 1 200 0.50 0.05 Pipeline Pigging Attachment B 5.84 1 1 5.84 2.92E-03 Compressor maintenance Attachment B 0.08 1 10 0.08 4.22E-04 Seal inspections and other tank inspection Attachment A 0.5 1 20 0.50 5.00E-03 activities Water washing empty drums, totes, and Attachment A 0.5 1 100 0.50 0.025 misc. small equipment Maintenance on Light Liquid pumps Attachment B 0.008 1 100 0.01 4.22E-04 Maintenance on Heavy Liquid pumps Attachment B 0.008 1 100 0.01 4.22E-04 Sample Purge and Discharge from Attachment A 0.1 1 10 0.10 5.00E-04 Analyzers/Area Monitors Drain equipment to controlled sewer hubs Attachment B 0.1 1 10 0.10 5.00E-04

Sample system purging Attachment A 0.1 1 50 0.10 2.50E-03 Acid and Caustic washing Attachment A 0.1 1 10 0.10 5.00E-04 Blowdowns of natural gas, liquid Attachment A 0.1 1 100 0.10 5.00E-03 hydrocarbons, compressed air, and steam lines Combustion shutoff devices Attachment A 0.1 1 10 0.10 5.00E-04 Insulation addition or removal Attachment A 0.1 1 10 0.10 5.00E-04 Pneumatic starts on reciprocating Attachment A 0.1 1 100 0.10 5.00E-03 engines, turbines, or compressors Machine blowdowns Attachment A 0.1 1 10 0.10 5.00E-04 Sampling Attachment B 0.1 1 10 0.10 5.00E-04 Heat Exchanger Maintenance (Heavy Attachment B 75.6 1 10 75.61 0.38 Liquid-Small)

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 2 Table C-9 Insignificant and Routine Equipment Maintenance Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Maintenance Activity Attachment Events / Hour Events / Year VOC Emissions CO Emissions SO2 Emissions PM Emissions PM10 Emissions PM2.5 Emissions NOx Emissions Emissions/ Event (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) VOC (lbs) Heat Exchanger Maintenance (Heavy Attachment B 124.7 1 10 124.75 0.62 Liquid-Medium) Heat Exchanger Maintenance (Heavy Attachment B 210.0 1 10 210.05 1.05 Liquid-Large) Heat Exchanger Maintenance (Light Attachment B 74.4 1 10 74.44 0.37 Liquid-Small) Heat Exchanger Maintenance (Light Attachment B 125.1 1 10 125.11 0.63 Liquid-Medium) Heat Exchanger Maintenance (Light Attachment B 220.2 1 10 220.25 1.10 Liquid-Large) Clearing/draining of process equipment Attachment A 4.21 lb/event 1 50 4.21 0.04 (other than vacuum trucks and frac tanks) (hourly) (4) 1.78 lb/event (annual) Ultrasonic cleaning Attachment A 0.1 1 10 0.10 0.0005 Attachment B 220.25 4.16 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Attachment A 4.21 0.16 0.05 2.50E-04 0.05 2.50E-04 0.21 8.59E-04 0.10 7.56E-04 0.01 6.77E-04 0.05 2.50E-04 Notes Total 224.45 4.32 0.05 2.50E-04 0.05 2.50E-04 0.21 8.59E-04 0.10 7.56E-04 0.01 6.77E-04 0.05 2.50E-04 Combinations of the identified miscellaneous maintenance activities are authorized provided the combined emissions do not exceed representations. (1) CEMS gases based on: 1 bottle/month per analyzer; 1.0 ft3 bottle at 2000 psig; 500 ppm CO, NOx, or SO2. (2) Based on average casing volume = 2.5 ft3, averine piping volume = 1.23 ft3, purge quantity = 1 quart, evaporated amount from purge = 4oz., percent saturation = 47%, and chemical properties of gasoline. (3) Based on average casing volume = 2.5 ft3, averine piping volume = 1.23 ft3, purge quantity = 1 quart, evaporated amount from purge = 4oz., percent saturation = 47%, and chemical properties of gasoline. (4) The event total emissions represents emissions from loading loss and clingage evaportion. (5) The number of events are used only to determine the Total Miscellaneous Maintenance Activities Emissions; actual number of events can be greater as long as the represented Total Miscellaneous Maintenance Activities Emission Rate is not exceeded.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 2 of 2 Table C-10 Maintenance, Startup, and Shutdown Emissions - Catalyst Changeout Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Catalyst Annual Emission Rates Usage Control Efficiency PM Generated Process Description Catalyst Type Density Throughput Pollutant (ft3) (3) (1) Factor (2) (lb/ft3) (tons) lb/hr (4) TPY (5)

TSP 0.11 0.001

Reformer Catalyst R-334 35 6359 111 50% 100% PM10 0.05 0.001

PM2.5 0.01 0.001

TSP 0.10 1.96E-04 Net Gas Chloride CLR-204 47 1400 33 50% 100% PM 0.05 9.27E-05 Treater Adsorbent (5 x 8) 10

PM2.5 7.02E-03 1.40E-05 TSP 0.21 0.001

Total Emission Rates PM10 0.10 0.001

PM2.5 0.01 0.001 Mean Wind Speed (6) = 12.80 mph Moisture Content (7) = 0.92 % Adsorbent Catalyst 4 hours Changeout Duration (8) Reformer Catalyst 12 hours Changeout Duration (8)

Emission Particle Size Pollutant Factors Multiplier (9) (lb / ton) (10)

TSP 0.74 0.0238

PM10 0.35 0.0113

PM2.5 0.053 0.0017

Notes: (1) The catalyst is loaded by lowering socks into the vessels. These socks are assumed to have a 50% control efficiency. (2) The catalysts are not in dust/fines form, but are in pieces of high density catalyst; however, it is conservatively assumed that 100% of the catalyst will cause PM emissions to result during the loading. (3) Catalyst usage is based on the design requirements of the vessel/operation. It is assumed that the catalyst changeout may occur 1xyear. (4) Hourly calculation is as follows: (Emission Factor (lbs Pollutant / ton Catalyst)) * (100-Control Efficiency (%)) *(Catalyst Usage per Changeout (tons) * PM Generated Factor/100) / (Changeout Duration (hours/event) ) (5) Annual calculation is as follows: (Emission Factor (lbs Pollutant / ton Catalyst)) * (100-Control Efficiency (%)) *(Catalyst Usage per Changeout (tons) * PM Generated Factor/100) / (2000 lbs/ton ) (6) Mean wind speed is based on average wind speed data from the November 2019 version of AP-42 Chapter 7.1 Table 7.1-7 for Amarillo, Texas. (7) Moisture content of catalyst is based on the moisture content of slag in iron and steel production from AP-42, Chapter 13.2.4, Table 13.2.4-1, Typical Silt and Moisture Contents of Materials at Various Industries. (8) Estimated durations of catalyst loading. (9) Particle size multiplier is taken from AP-42, Chapter 13.2.4, Aerodynamic Particle Size Multiplier (k). (10) Emission Factor calculation is as follows: (k) * (0.0032)* (U/5 (mph)^1.3) / (M/2 (%)^1.4) from AP-42, Chapter 13.2.4, Aggregate Handling and Storage Piles , Equation 1.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table C-11 CCR Sump Emissions Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Parameter Symbol Value Units Notes Reformer Unit Throughput Q 32 MBPD Engineering Estimate Average Flow Factor -- 1.5 -- Table 7-8 from "Emissions Estimation Protocol for Petroleum Refineries" (April 2015)

Sump Throughput QSUMP 2,000 gal/hr = 32 * 1000 BPD * 1.5 gal/barrel * / 24 hours/day

3 VOC Emission Factor EFvoc 0.2 lb/10 gal AP-42 Table 5.1-3 for covered or controlled oil- water separators

Hourly VOC Emissions ERvoc,ST 0.40 lb/hr = Q * EFvoc

Annual VOC Emissions ERvoc,A 1.75 tpy = ERvoc,ST * 8,760 / 2,000

Notes (1) The emission factors used to estimate emissions for each pollutant from this equipment are not meant to be operational constraints. Concentrations and other operational parameters may vary. Compliance is determined based on emission rates (lb/hr and tpy).

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1

APPENDIX D: PSD APPLICABILITY DETERMINATION – CRITERIA POLLUTANTS The following table is included in this appendix: • Table D-1: PSD Applicability Analysis; • Table D-2: Flexible Permit Cap Adjustment; • TCEQ Table 1F: Air Quality Application Supplement;

• TCEQ Table 2F: Project Emission Increases – NOX; • TCEQ Table 2F: Project Emission Increases – VOC; • TCEQ Table 2F: Project Emission Increases – CO;

• TCEQ Table 2F: Project Emission Increases – SO2; • TCEQ Table 2F: Project Emission Increases – PM;

• TCEQ Table 2F: Project Emission Increases – PM10;

• TCEQ Table 2F: Project Emission Increases – PM2.5;

• TCEQ Table 2F: Project Emission Increases – H2S;

• TCEQ Table 3F: Project Contemporaneous Change – NOX; • TCEQ Table 3F: Project Contemporaneous Change – VOC; • TCEQ Table 3F: Project Contemporaneous Change – CO;

• TCEQ Table 3F: Project Contemporaneous Change – SO2; • TCEQ Table 3F: Project Contemporaneous Change – PM;

• TCEQ Table 3F: Project Contemporaneous Change – PM10;

• TCEQ Table 3F: Project Contemporaneous Change – PM2.5; and

• TCEQ Table 3F: Project Contemporaneous Change – H2S.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: NOx CO SO2 PM Affected Source? 24 Mo. Period 8/1/2012 4/1/2012 2/1/2012 9/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) New Sources 28-H3 Crude Charge Heater New No TBD -- 12.65 12.65 -- 29.51 29.51 -- 10.12 10.12 -- 6.28 6.28 28-H4 Crude Charge Heater New No TBD -- 12.65 12.65 -- 29.51 29.51 -- 10.12 10.12 -- 6.28 6.28 88-H1 CCR Charger and Interheaters New No TBD -- 27.13 27.13 -- 63.30 63.30 -- 21.70 21.70 -- 13.48 13.48 88-V1 CCR Vent New No TBD -- 0.11 0.11 -- 1.35 1.35 -- 3.08 3.08 ------F-CrudeFlex CCR and Crude Flex Fugitives New No TBD ------MSS Planned MSS Activities New No TBD -- 0.17 0.17 -- 1.10 1.10 -- <0.01 <0.01 -- <0.01 <0.01 F-SUMPCCR CCR Sump New No TBD ------

Affected Sources - Flex Cap 50H1 Unit 50 Charge Heater Affected Yes 9868A 26.68 -- -- 1.61 -- -- 10.96 -- -- 4.12 -- -- 42H1 Unit 42 Reactor Chg Heater Affected Yes 9868A 9.73 -- -- 2.26 -- -- 0.34 -- -- 0.72 -- -- 42H2 Unit 42 Reactor Chg Heater Affected Yes 9868A 14.01 -- -- 0.24 -- -- 0.51 -- -- 0.97 -- -- 42H3 Unit 42 Fract Feed Heater Affected Yes 9868A 2.22 -- -- <0.01 -- -- <0.01 -- -- 0.20 -- -- 19H3 19.1 Naphtha HDS Chg Htr Affected Yes 9868A 60.34 ------1.30 -- -- 2.49 -- -- 29H4 Unit 29 DeC4 Reboiler Affected Yes 9868A 33.59 -- -- 3.57 -- -- 0.22 -- -- 1.76 -- -- 2H1 HDS Unit Charge Heater Affected Yes 9868A 22.84 -- -- 0.10 -- -- 0.21 -- -- 1.20 -- -- 2H2 DeOiler Charge Heater Affected Yes 9868A 24.77 -- -- 0.04 -- -- 0.06 -- -- 1.46 -- -- 4H1 Butamer Furnace Affected Yes 9868A 0.43 -- -- 0.13 -- -- <0.01 -- -- 0.04 -- -- 4H2 Butamer Regen Furnace Affected Yes 9868A 1.09 -- -- 0.17 -- -- 0.03 -- -- 0.08 -- -- 5H1 SRI Feed Heater A Affected Yes 9868A 1.18 -- -- 0.54 -- -- 0.04 -- -- 0.08 -- -- 5H3 SRI Feed Heater B Affected Yes 9868A 0.08 -- -- 0.23 -- -- 0.01 -- -- <0.01 -- -- 5H4 SRI Feed Heater C Affected Yes 9868A 0.08 -- -- 0.09 -- -- <0.01 -- -- <0.01 -- -- 6H1 ULACH Heater Affected Yes 9868A 0.60 -- -- 0.82 -- -- 0.01 -- -- 0.04 -- -- 6H3 C6 Dryer Regen Furnace Affected Yes 9868A 0.09 -- -- 0.06 -- -- <0.01 -- -- <0.01 -- -- 12H1 Regen Gas Furnace Affected Yes 9868A 2.12 -- -- 0.06 ------0.14 -- -- 26H1 DeC4 Reboiler Affected Yes 9868A 54.83 -- -- 0.83 -- -- 0.10 -- -- 2.42 -- -- 41H1 Unit 41 Reformer Furnace Affected Yes 9868A 130.72 -- -- 2.17 -- -- 7.59 -- -- 14.78 -- -- 50HT1 Coker Heater Tank 1 Affected Yes 9868A 0.18 -- -- 0.36 -- -- 0.13 -- -- 0.04 -- -- 50HT2 Coker Heater Tank 1 Affected Yes 9868A 0.18 -- -- 0.36 -- -- 0.13 -- -- 0.04 -- -- 50HT3 Coker Heater Tank 1 Affected Yes 9868A 0.18 -- -- 0.36 -- -- 0.13 -- -- 0.04 -- -- 51H1 Charge Heater - Vacuum Unit Affected Yes 9868A 32.95 -- -- 4.46 -- -- 10.86 -- -- 4.21 -- -- 98H1 SMR Charge Heater Affected Yes 9868A 34.79 -- -- 6.11 -- -- 2.40 -- -- 8.16 -- -- 19B2/19H4 Fractionator Feed Furnace Affected Yes 9868A 15.39 -- -- 5.60 -- -- 0.18 -- -- 2.84 -- -- 29P1 Unit 29 FCC Stack Affected Yes 9868A 37.58 -- -- 76.16 -- -- 21.65 -- -- 102.96 -- -- 40H1 Unit 40 Superheater No. 1 Affected Yes 9868A 18.65 -- -- 2.67 -- -- 0.39 -- -- 0.59 -- -- 40P1 Unit 40 FCC Stack Affected Yes 9868A 131.02 -- -- 364.77 -- -- 61.73 ------36H1 HDS Unit Charge Heater Affected Yes 9868A 21.27 -- -- 1.56 -- -- 0.01 -- -- 1.07 -- -- 22H1 Alky Reboiler Furnace Affected Yes 9868A 8.34 -- -- 0.13 -- -- 0.32 -- -- 0.48 -- -- 5001 Tank Affected Yes 9868A ------2675 Tank-Naphtha Affected Yes 9868A ------8011 Tank-Gas Oil Affected Yes 9868A ------9701 Tank-Gas Oil Affected Yes 9868A ------9200 Tank-Gas Oil Affected Yes 9868A ------

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: NOx CO SO2 PM Affected Source? 24 Mo. Period 8/1/2012 4/1/2012 2/1/2012 9/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) 9501 Tank-Naphtha Affected Yes 9868A ------8010 Tank-Naphtha Affected Yes 9868A ------5560 Tank-Naphtha Affected Yes 9868A ------5591 Tank-Naphtha Affected Yes 9868A ------9201 Tank-Naphtha Affected Yes 9868A ------8014 Tank-Naphtha Affected Yes 9868A ------8012 Tank-Sweet Gas Oil Affected Yes 9868A ------9702 Tank-Sweet Gas Oil Affected Yes 9868A ------2670 Tank-LCO Affected Yes 9868A ------552 Tank-LCO Affected Yes 9868A ------5592 Tank-Alkylate Affected Yes 9868A ------5593 Tank-Alkylate Affected Yes 9868A ------5583 Tank-FCC Gas Affected Yes 9868A ------5584 Tank-FCC Gas Affected Yes 9868A ------9502 Tank-FCC Gas Affected Yes 9868A ------4030 Tank-Gas Affected Yes 9868A ------5521 Tank-Gas Affected Yes 9868A ------5532 Tank-Gas Affected Yes 9868A ------5551 Tank-Gas Affected Yes 9868A ------5553 Tank-Gas Affected Yes 9868A ------5554 Tank-Gas Affected Yes 9868A ------5555 Tank-Gas Affected Yes 9868A ------5557 Tank-Gas Affected Yes 9868A ------8001 Tank-Gas Affected Yes 9868A ------8002 Tank-Gas Affected Yes 9868A ------8031 Tank-Gas Affected Yes 9868A ------8032 Tank-Gas Affected Yes 9868A ------8034 Tank-Gas Affected Yes 9868A ------9500 Tank-Gas Affected Yes 9868A ------9504 Tank-ULSD Affected Yes 9868A ------5596 Tank-ULSD Affected Yes 9868A ------8015 Tank-ULSD Affected Yes 9868A ------8033 Tank-ULSD Affected Yes 9868A ------9202 Tank-ULSD Affected Yes 9868A ------1064 Tank-Turbo Naphtha Affected Yes 9868A ------2571 Tank-Off Spec Affected Yes 9868A ------2575 Tank-Sweet Naphtha Affected Yes 9868A ------5599 Tank-Sweet Naphtha Affected Yes 9868A ------F-54-C2 Cooling Tower-#9 Ecodyne Affected Yes 9868A ------F-54-C3 Cooling Tower=#11 Sante Fe Affected Yes 9868A ------F-54-C4 Cooling Tower=-#13 Marley Affected Yes 9868A ------F-54-C6 Cooling Tower=-#10 Marley Affected Yes 9868A ------F-54-C7 Cooling Tower-#2 Refinery Affected Yes 9868A ------

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 2 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: NOx CO SO2 PM Affected Source? 24 Mo. Period 8/1/2012 4/1/2012 2/1/2012 9/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) F-54-C8 Cooling Tower-#4 Refinery Affected Yes 9868A ------F-54-C9 Cooling Tower-#7 Refinery Affected Yes 9868A ------F-54-C10 Cooling Tower-#9 Refinery Affected Yes 9868A ------F-54-C11 Cooling Tower-#3 Refinery Affected Yes 9868A ------F-54-C12 Cooling Tower=-#12 Marley Affected Yes 9868A ------F-54-C13 Cooling Tower-#14 Pritchard Affected Yes 9868A ------F-54-C14 Cooling Tower=-#15 Marley Affected Yes 9868A ------F-54-C15 Cooling Tower-#16 Pritchard Affected Yes 9868A ------F-54-C16 Cooling Tower-#18 Pritchard Affected Yes 9868A ------F-54-C17 Cooling Tower-#8 Refinery Affected Yes 9868A ------F-54-C18 Cooling Tower-#13 Refinery Affected Yes 9868A ------F-54-C19 Cooling Tower-#10 Refinery Affected Yes 9868A ------F-54-C20 Cooling Tower-#17 Ards Affected Yes 9868A ------F-54-C21 Cooling Tower-Vacuum Unit Affected Yes 9868A ------2.08 -- --

12E1 Gas Engine #41 Affected Yes 9868A 7.36 -- -- 8.56 -- -- 0.01 -- -- 0.15 -- -- 12E2 Gas Engine #42 Affected Yes 9868A 3.17 -- -- 11.95 -- -- 0.01 -- -- 0.15 -- -- 12E3 Gas Engine #43 Affected Yes 9868A 4.38 -- -- 9.72 -- -- 0.01 -- -- 0.15 -- -- 12E4 Gas Engine #44 Affected Yes 9868A 7.54 -- -- 11.95 -- -- 0.01 -- -- 0.15 -- -- 12E5 Gas Engine #45 Affected Yes 9868A 6.36 -- -- 13.93 -- -- 0.01 -- -- 0.15 -- -- 12E6 Gas Engine #46 Affected Yes 9868A 6.36 -- -- 9.04 -- -- <0.01 -- -- 0.11 -- -- 12E7 Gas Engine #47 Affected Yes 9868A 5.53 -- -- 4.61 -- -- <0.01 -- -- 0.11 -- -- 93E1 Gas Engine #37 Affected Yes 9868A 12.64 -- -- 5.68 -- -- <0.01 -- -- 0.10 -- -- 93E2 Gas Engine #38 Affected Yes 9868A 6.58 -- -- 5.38 -- -- <0.01 -- -- 0.10 -- -- 66FL1 Refinery East HC Flare Affected Yes 9868A 35.76 -- -- 178.74 -- -- 96.31 ------

66FL6 H2S Emergency Flare Affected Yes 9868A 0.65 -- -- 3.78 -- -- 0.39 ------66FL13 GOHDS Emergency Sulfur Flare Affected Yes 9868A 10.03 -- -- 51.14 -- -- 59.65 ------F-50A Coke Handling Affected Yes 9868A ------0.52 -- -- 53R1 Loading Affected Yes 9868A ------53R2 Loading Affected Yes 9868A ------

53R3 Loading Affected Yes 9868A ------53T1 Loading Affected Yes 9868A ------53T2 Loading Affected Yes 9868A ------109 Tank-Kerosene Affected Yes 9868A ------110 Tank-DFPO Affected Yes 9868A ------111 Tank-Light Slop Oil Affected Yes 9868A ------202 Tank-OSU Sludge Affected Yes 9868A ------401 Tank-Slop Oil Affected Yes 9868A ------511 Tank-Normal Heptane Affected Yes 9868A ------514 Tank-AvGas Stock Affected Yes 9868A ------562 Tank-Unleaded Gasoline Affected Yes 9868A ------572 Tank-Slop Oil Affected Yes 9868A ------

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 3 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: NOx CO SO2 PM Affected Source? 24 Mo. Period 8/1/2012 4/1/2012 2/1/2012 9/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) 573 Tank-Slop Oil Affected Yes 9868A ------1001 Tank-Plat Feed Affected Yes 9868A ------1002 Tank-Plat Feed Affected Yes 9868A ------1003 Tank-Benzene Hydro Feed Affected Yes 9868A ------1006 Tank-Normal Heptane Affected Yes 9868A ------1007 Tank-Normal Heptane Affected Yes 9868A ------1012 Tank-Toluene Affected Yes 9868A ------1013 Tank-Toluene Affected Yes 9868A ------1067 Tank-Orfom SX-7 Affected Yes 9868A ------1163 Tank-Gasoline Affected Yes 9868A ------1164 Tank-Plat Feed Affected Yes 9868A ------1165 Tank-Light Slop Oil Affected Yes 9868A ------1522 Tank-Methanol Affected Yes 9868A ------2072 Tank-Tot Alky Affected Yes 9868A ------2510 Tank-AvGas Affected Yes 9868A ------2530 Tank Affected Yes 9868A ------2553 Tank-Natural Gasoline Affected Yes 9868A ------2572 Tank-Philjet ASO Affected Yes 9868A ------2576 Tank-HP7 Affected Yes 9868A ------2577 Tank-Unit 7 Heavy Plat Affected Yes 9868A ------2578 Tank-Kerosene Distillate Affected Yes 9868A ------2579 Tank-Light Slop Oil Affected Yes 9868A ------2580 Tank-Diesel Affected Yes 9868A ------2672 Tank-Orfom SX-7 Affected Yes 9868A ------2673 Tank-Slop Oil Affected Yes 9868A ------2674 Tank-Naphtha Affected Yes 9868A ------2676 Tank-Philjet ASO Affected Yes 9868A ------2677 Tank-Philjet ASO Affected Yes 9868A ------2678 Tank-Philjet ASO Affected Yes 9868A ------3001 Tank-NC7 Affected Yes 9868A ------3002 Tank-NC6 Affected Yes 9868A ------3003 Tank-Sour Water Affected Yes 9868A ------5505 Tank-Natural Gasoline Affected Yes 9868A ------5508 Tank-Gas Oil Affected Yes 9868A ------5511 Tank-Gas Oil Affected Yes 9868A ------5520 Tank-Lt Alky Affected Yes 9868A ------5531 Tank-Philjet ASO Affected Yes 9868A ------5550 Tank-Various NGLs Affected Yes 9868A ------5556 Tank-100-LL (AvGas) Affected Yes 9868A ------5558 Tank-Natural Gasoline Affected Yes 9868A ------5559 Tank-Naphtha Affected Yes 9868A ------5578 Tank-Natural Gasoline Affected Yes 9868A ------5580 Tank-Natural Gasoline Affected Yes 9868A ------

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 4 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: NOx CO SO2 PM Affected Source? 24 Mo. Period 8/1/2012 4/1/2012 2/1/2012 9/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) 5587 Tank-Carbon Black Oil (Slurry) Affected Yes 9868A ------5588 Tank-Carbon Black Oil (Slurry) Affected Yes 9868A ------5589 Tank-Kerosene Affected Yes 9868A ------5590 Tank-Kerosene Affected Yes 9868A ------5597 Tank-U19 Plat Gas Affected Yes 9868A ------5598 Tank-Philjet ASO Affected Yes 9868A ------8013 Tank-Topped Crude Affected Yes 9868A ------9503 Tank-U19 Plat Gas Affected Yes 9868A ------9700 Tank-Gas Oil Affected Yes 9868A ------KG47 Tank-Sulfur Storage Tank Affected Yes 9868A ------0.06 -- -- 34I1 SRU Affected Yes 9868A 5.82 -- -- 23.92 -- -- 20.27 -- -- 0.66 -- -- 43I1 SRU Affected Yes 9868A 7.24 -- -- 61.33 -- -- 50.63 -- -- 1.40 -- -- 56-4 WW Affected Yes 9868A ------F-56-1-1 West Sump Affected Yes 9868A ------F-56-1-3 North Sump Affected Yes 9868A ------F-56-1-4-A Refinery Oil/Water Separators Affected Yes 9868A ------F-56-1-5 Hazardous Waste Impoundment Affected Yes 9868A ------F-56-1-6 Storm Water System Affected Yes 9868A ------F-56-2 Dixon Creek WWTP Affected Yes 9868A ------TKOFF1 WW Affected Yes 9868A ------TH1 WW Affected Yes 9868A ------TH2 WW Affected Yes 9868A ------53FL1 Loading Thermal Oxidizer Affected Yes 9868A ------FWP1 Fire Water Pump Affected Yes 9868A 0.02 -- -- <0.01 -- -- <0.01 -- -- <0.01 -- -- FWP2 Fire Water Pump Affected Yes 9868A 0.02 -- -- <0.01 -- -- <0.01 -- -- <0.01 -- -- FWP3 Fire Water Pump Affected Yes 9868A 0.02 -- -- <0.01 -- -- <0.01 -- -- <0.01 -- -- FWP4 Fire Water Pump Affected Yes 9868A 0.02 -- -- <0.01 -- -- <0.01 -- -- <0.01 -- -- FWP5 Fire Water Pump Affected Yes 9868A 0.02 -- -- <0.01 -- -- <0.01 -- -- <0.01 -- -- VF-1030 PAC Silo Affected Yes 9868A ------0.05 -- -- VF-2030 PAC Silo Affected Yes 9868A ------0.05 -- -- F-1 Fugitive Affected Yes 9868A ------F-1-6 Fugitive Affected Yes 9868A ------F-1-7 Fugitive Affected Yes 9868A ------F-2 Fugitive Affected Yes 9868A ------F-2-1 Fugitive Affected Yes 9868A ------F-2-5 Fugitive Affected Yes 9868A ------F-4 Fugitive Affected Yes 9868A ------F-5 Fugitive Affected Yes 9868A ------F-6 Fugitive Affected Yes 9868A ------F-9 Fugitive Affected Yes 9868A ------F-10 Fugitive Affected Yes 9868A ------F-11 Fugitive Affected Yes 9868A ------F-12 Fugitive Affected Yes 9868A ------

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 5 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: NOx CO SO2 PM Affected Source? 24 Mo. Period 8/1/2012 4/1/2012 2/1/2012 9/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) F-13 Fugitive Affected Yes 9868A ------F-19-1 Fugitive Affected Yes 9868A ------F-19-3 Fugitive Affected Yes 9868A ------F-22 Fugitive Affected Yes 9868A ------F-23 Fugitive Affected Yes 9868A ------F-26 Fugitive Affected Yes 9868A ------F-28 Fugitive Affected Yes 9868A ------F-29 Fugitive Affected Yes 9868A ------F-32 Fugitive Affected Yes 9868A ------F-34 Fugitive Affected Yes 9868A ------F-35 Fugitive Affected Yes 9868A ------F-36 Fugitive Affected Yes 9868A ------F-40 Fugitive Affected Yes 9868A ------F-41 Fugitive Affected Yes 9868A ------F-42 Fugitive Affected Yes 9868A ------F-43-1 Fugitive Affected Yes 9868A ------F-44 Fugitive Affected Yes 9868A ------F-50 Fugitive Affected Yes 9868A ------F-51 Fugitive Affected Yes 9868A ------F-53-1 Fugitive Affected Yes 9868A ------F-53-2 Fugitive Affected Yes 9868A ------F-55 Fugitive Affected Yes 9868A ------F-56 Fugitive Affected Yes 9868A ------F-66-1 Fugitive Affected Yes 9868A ------F-66-2 Fugitive Affected Yes 9868A ------F-66-3 Fugitive Affected Yes 9868A ------F-68-1a Fugitive Affected Yes 9868A ------F-68-1e Fugitive Affected Yes 9868A ------F-68-1n Fugitive Affected Yes 9868A ------F-68-1r Fugitive Affected Yes 9868A ------F-68-1s Fugitive Affected Yes 9868A ------F-68-1t Fugitive Affected Yes 9868A ------F-68-1w Fugitive Affected Yes 9868A ------F-68-2n Fugitive Affected Yes 9868A ------F-68-2s Fugitive Affected Yes 9868A ------F-68-3 Fugitive Affected Yes 9868A ------F-68-4t Fugitive Affected Yes 9868A ------F-68-5 Fugitive Affected Yes 9868A ------F-81 Fugitive Affected Yes 9868A ------F-82 Fugitive Affected Yes 9868A ------F-85-2 Fugitive Affected Yes 9868A ------F-98 Fugitive Affected Yes 9868A ------F-Tier 3 Fugitive Affected Yes 9868A ------

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 6 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: NOx CO SO2 PM Affected Source? 24 Mo. Period 8/1/2012 4/1/2012 2/1/2012 9/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) F-56-1-4-A(1) WW Affected Yes 9868A ------F-56-1-4-A(3) WW Affected Yes 9868A ------F-56-1-4-A(4) WW Affected Yes 9868A ------Sitewide Cap Totals (See Table D-2 for flexible permit cap adjustments) 805.47 2,121.52 1,316.05 875.18 3,264.38 2,389.20 346.72 2,847.85 2,501.13 156.96 995.67 838.70 Non Flexible Permit Cap Sources 85B2 Unit 40 Boiler Affected No 9868A 32.36 52.40 20.04 2.62 187.70 185.08 21.62 81.83 60.21 10.17 19.52 9.35 40H3 Unit 40 Superheater Affected No 9868A -- 3.63 3.63 -- 9.13 9.13 -- 1.88 1.88 -- 1.89 1.89 40H4 Unit 40 Preheater Furnace Affected No 9868A 10.84 10.84 -- 14.92 14.92 -- 5.61 5.61 -- 5.64 5.64 -- 34I1 Merox SRU TGI Affected No 9868A -- 0.82 0.82 -- 1.38 1.38 -- <0.01 <0.01 -- 0.13 0.13

F-56-1-4-A(2&5) West DAF Affected No 9868A ------F-56-1-12 Flash Mixing Affected No 9868A ------F-56-1-17 Flocculation Affected No 9868A ------53R4 Sulfur Loading Rates (Interim) Affected No 9868A ------0.12 0.17 0.05 40P1 Unit 40 FCC Stack Affected No 9868A ------103.76 447.00 343.24 50CDV1 Coker Drum Vent 1 (Post Coker Vent Affected No 9868A ------3.08 3.08 Improvement) 50CDV2 Coker Drum Vent 2 (Post Coker Vent Affected No 9868A ------3.08 3.08 Improvement) 50CDC1 Coker Drum Cutting 1 Affected No 9868A ------

50CDC2 Coker Drum Cutting 2 Affected No 9868A ------

50CDW Coker Drum Water Affected No 9868A ------

0310 T-310 Sulfur Loading Tank Final Rates Affected No 9868A ------0.05 0.07 0.02

66FL1, Flares - Routine Emissions Affected No 9868A 66FL2, 66FL3, & 66FL12 (Routine Emissions) 19.00 43.64 24.64 89.54 275.33 185.79 194.80 302.10 107.30 ------66FL1, 66FL2, Flares - Fuel Gas Long Scenario Affected No 9868A 66FL3, & 66FL12 (Fuel Gas Long) 66FL1, 66FL2, Flares - Flare Gas MSS Affected No 9868A 66FL3, & 66FL12 (Flare Gas MSS) 81B17 Boiler 2.4 Affected No 85872 58.89 71.50 12.61 25.12 31.04 5.92 1.39 8.03 6.64 3.42 4.63 1.21

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 7 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: NOx CO SO2 PM Affected Source? 24 Mo. Period 8/1/2012 4/1/2012 2/1/2012 9/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) BLR12 Boiler 12 Affected No 85872 -- 38.61 38.61 -- 166.06 166.06 -- 31.72 31.72 -- 18.28 18.28 SKDBLR Skid Boiler Affected No 85872 10.02 25.33 15.31 14.44 109.53 95.09 <0.01 20.65 20.65 1.93 11.90 9.97 T-0520 Tank 520 Affected No 71385 ------F-54-C22 Crude Unit Cooling Tower Modified No PBR 106.371 ------0.50 0.50 --

Total Increases 1,484.41 3,162.42 2,774.55 1,255.04

PSD Significance Threshold 40.00 100.00 40.00 25.00

Triggers Netting? Y Y Y Y

Notes (1) Project increases for sources in the flexible permit cap are calculated by summing baseline actual emissions and subtracting the summed baseline actual emissions from the adjusted cap (see Table D-2).

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 8 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: PM10 PM2.5 H2S VOC Affected Source? 24 Mo. Period 9/1/2012 9/1/2012 7/1/2012 7/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) New Sources 28-H3 Crude Charge Heater New No TBD -- 6.28 6.28 -- 6.28 6.28 ------4.55 4.55 28-H4 Crude Charge Heater New No TBD -- 6.28 6.28 -- 6.28 6.28 ------4.55 4.55 88-H1 CCR Charger and Interheaters New No TBD -- 13.48 13.48 -- 13.48 13.48 ------9.75 9.75 88-V1 CCR Vent New No TBD ------0.46 0.46 F-CrudeFlex CCR and Crude Flex Fugitives New No TBD ------0.46 0.46 -- 70.72 70.72 MSS Planned MSS Activities New No TBD -- <0.01 <0.01 -- <0.01 <0.01 ------7.30 7.30 F-SUMPCCR CCR Sump New No TBD ------1.75 1.75

Affected Sources - Flex Cap 50H1 Unit 50 Charge Heater Affected Yes 9868A 4.12 -- -- 4.12 ------0.43 -- -- 42H1 Unit 42 Reactor Chg Heater Affected Yes 9868A 0.72 -- -- 0.72 ------0.07 -- -- 42H2 Unit 42 Reactor Chg Heater Affected Yes 9868A 0.97 -- -- 0.97 ------0.12 -- -- 42H3 Unit 42 Fract Feed Heater Affected Yes 9868A 0.20 -- -- 0.20 ------0.07 -- -- 19H3 19.1 Naphtha HDS Chg Htr Affected Yes 9868A 2.49 -- -- 2.49 ------0.84 -- -- 29H4 Unit 29 DeC4 Reboiler Affected Yes 9868A 1.76 -- -- 1.76 ------0.38 -- -- 2H1 HDS Unit Charge Heater Affected Yes 9868A 1.20 -- -- 1.20 ------0.11 -- -- 2H2 DeOiler Charge Heater Affected Yes 9868A 1.46 -- -- 1.46 ------0.08 -- -- 4H1 Butamer Furnace Affected Yes 9868A 0.04 -- -- 0.04 ------0.03 -- -- 4H2 Butamer Regen Furnace Affected Yes 9868A 0.08 -- -- 0.08 ------0.06 -- -- 5H1 SRI Feed Heater A Affected Yes 9868A 0.08 -- -- 0.08 ------0.06 -- -- 5H3 SRI Feed Heater B Affected Yes 9868A <0.01 -- -- <0.01 ------0.01 -- -- 5H4 SRI Feed Heater C Affected Yes 9868A <0.01 -- -- <0.01 ------<0.01 -- -- 6H1 ULACH Heater Affected Yes 9868A 0.04 -- -- 0.04 ------0.03 -- -- 6H3 C6 Dryer Regen Furnace Affected Yes 9868A <0.01 -- -- <0.01 ------<0.01 -- -- 12H1 Regen Gas Furnace Affected Yes 9868A 0.14 -- -- 0.14 ------0.11 -- -- 26H1 DeC4 Reboiler Affected Yes 9868A 2.42 -- -- 2.42 ------0.37 -- -- 41H1 Unit 41 Reformer Furnace Affected Yes 9868A 14.78 -- -- 14.78 ------12.51 -- -- 50HT1 Coker Heater Tank 1 Affected Yes 9868A 0.04 -- -- 0.04 ------0.03 -- -- 50HT2 Coker Heater Tank 1 Affected Yes 9868A 0.04 -- -- 0.04 ------0.03 -- -- 50HT3 Coker Heater Tank 1 Affected Yes 9868A 0.04 -- -- 0.04 ------0.03 -- -- 51H1 Charge Heater - Vacuum Unit Affected Yes 9868A 4.21 -- -- 4.21 ------0.37 -- -- 98H1 SMR Charge Heater Affected Yes 9868A 8.16 -- -- 8.16 ------6.26 -- -- 19B2/19H4 Fractionator Feed Furnace Affected Yes 9868A 2.84 -- -- 2.84 ------0.20 -- -- 29P1 Unit 29 FCC Stack Affected Yes 9868A 90.19 -- -- 60.44 ------55.66 -- -- 40H1 Unit 40 Superheater No. 1 Affected Yes 9868A 0.59 -- -- 0.59 ------0.47 -- -- 40P1 Unit 40 FCC Stack Affected Yes 9868A ------60.02 -- -- 36H1 HDS Unit Charge Heater Affected Yes 9868A 1.07 -- -- 1.07 ------0.18 -- -- 22H1 Alky Reboiler Furnace Affected Yes 9868A 0.48 -- -- 0.48 ------0.38 -- -- 5001 Tank Affected Yes 9868A ------<0.01 -- -- 9.25 -- -- 2675 Tank-Naphtha Affected Yes 9868A ------21.21 -- -- 8011 Tank-Gas Oil Affected Yes 9868A ------2.55 -- -- 9701 Tank-Gas Oil Affected Yes 9868A ------1.30 -- -- 9200 Tank-Gas Oil Affected Yes 9868A ------1.70 -- --

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 9 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: PM10 PM2.5 H2S VOC Affected Source? 24 Mo. Period 9/1/2012 9/1/2012 7/1/2012 7/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) 9501 Tank-Naphtha Affected Yes 9868A ------1.20 -- -- 8010 Tank-Naphtha Affected Yes 9868A ------1.34 -- -- 5560 Tank-Naphtha Affected Yes 9868A ------1.23 -- -- 5591 Tank-Naphtha Affected Yes 9868A ------1.10 -- -- 9201 Tank-Naphtha Affected Yes 9868A ------1.84 -- -- 8014 Tank-Naphtha Affected Yes 9868A ------1.88 -- -- 8012 Tank-Sweet Gas Oil Affected Yes 9868A ------0.11 -- -- 9702 Tank-Sweet Gas Oil Affected Yes 9868A ------3.18 -- -- 2670 Tank-LCO Affected Yes 9868A ------1.55 -- -- 552 Tank-LCO Affected Yes 9868A ------0.33 -- -- 5592 Tank-Alkylate Affected Yes 9868A ------23.82 -- -- 5593 Tank-Alkylate Affected Yes 9868A ------23.99 -- -- 5583 Tank-FCC Gas Affected Yes 9868A ------8.62 -- -- 5584 Tank-FCC Gas Affected Yes 9868A ------23.67 -- -- 9502 Tank-FCC Gas Affected Yes 9868A ------18.16 -- -- 4030 Tank-Gas Affected Yes 9868A ------31.32 -- -- 5521 Tank-Gas Affected Yes 9868A ------35.79 -- -- 5532 Tank-Gas Affected Yes 9868A ------41.40 -- -- 5551 Tank-Gas Affected Yes 9868A ------29.99 -- -- 5553 Tank-Gas Affected Yes 9868A ------35.25 -- -- 5554 Tank-Gas Affected Yes 9868A ------41.23 -- -- 5555 Tank-Gas Affected Yes 9868A ------38.41 -- -- 5557 Tank-Gas Affected Yes 9868A ------33.33 -- -- 8001 Tank-Gas Affected Yes 9868A ------39.58 -- -- 8002 Tank-Gas Affected Yes 9868A ------37.38 -- -- 8031 Tank-Gas Affected Yes 9868A ------7.75 -- -- 8032 Tank-Gas Affected Yes 9868A ------36.78 -- -- 8034 Tank-Gas Affected Yes 9868A ------35.89 -- -- 9500 Tank-Gas Affected Yes 9868A ------41.02 -- -- 9504 Tank-ULSD Affected Yes 9868A ------0.62 -- -- 5596 Tank-ULSD Affected Yes 9868A ------0.34 -- -- 8015 Tank-ULSD Affected Yes 9868A ------0.55 -- -- 8033 Tank-ULSD Affected Yes 9868A ------0.30 -- -- 9202 Tank-ULSD Affected Yes 9868A ------6.36 -- -- 1064 Tank-Turbo Naphtha Affected Yes 9868A ------4.33 -- -- 2571 Tank-Off Spec Affected Yes 9868A ------1.46 -- -- 2575 Tank-Sweet Naphtha Affected Yes 9868A ------0.34 -- -- 5599 Tank-Sweet Naphtha Affected Yes 9868A ------8.58 -- -- F-54-C2 Cooling Tower-#9 Ecodyne Affected Yes 9868A ------0.04 -- -- 1.26 -- -- F-54-C3 Cooling Tower=#11 Sante Fe Affected Yes 9868A ------0.72 -- -- F-54-C4 Cooling Tower=-#13 Marley Affected Yes 9868A ------23.50 -- -- F-54-C6 Cooling Tower=-#10 Marley Affected Yes 9868A ------0.97 -- -- F-54-C7 Cooling Tower-#2 Refinery Affected Yes 9868A ------<0.01 -- -- 0.57 -- --

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 10 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: PM10 PM2.5 H2S VOC Affected Source? 24 Mo. Period 9/1/2012 9/1/2012 7/1/2012 7/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) F-54-C8 Cooling Tower-#4 Refinery Affected Yes 9868A ------<0.01 -- -- 1.12 -- -- F-54-C9 Cooling Tower-#7 Refinery Affected Yes 9868A ------<0.01 -- -- 0.36 -- -- F-54-C10 Cooling Tower-#9 Refinery Affected Yes 9868A ------0.05 -- -- 2.58 -- -- F-54-C11 Cooling Tower-#3 Refinery Affected Yes 9868A ------0.01 -- -- 0.53 -- -- F-54-C12 Cooling Tower=-#12 Marley Affected Yes 9868A ------0.91 -- -- F-54-C13 Cooling Tower-#14 Pritchard Affected Yes 9868A ------0.53 -- -- F-54-C14 Cooling Tower=-#15 Marley Affected Yes 9868A ------0.05 -- -- 3.25 -- -- F-54-C15 Cooling Tower-#16 Pritchard Affected Yes 9868A ------<0.01 -- -- 0.37 -- -- F-54-C16 Cooling Tower-#18 Pritchard Affected Yes 9868A ------<0.01 -- -- 0.41 -- -- F-54-C17 Cooling Tower-#8 Refinery Affected Yes 9868A ------<0.01 -- -- 0.86 -- -- F-54-C18 Cooling Tower-#13 Refinery Affected Yes 9868A ------0.47 -- -- 56.70 -- -- F-54-C19 Cooling Tower-#10 Refinery Affected Yes 9868A ------<0.01 -- -- 1.35 -- -- F-54-C20 Cooling Tower-#17 Ards Affected Yes 9868A ------0.07 -- -- 0.62 -- -- F-54-C21 Cooling Tower-Vacuum Unit Affected Yes 9868A ------0.76 -- --

12E1 Gas Engine #41 Affected Yes 9868A 0.15 -- -- 0.15 ------6.03 -- -- 12E2 Gas Engine #42 Affected Yes 9868A 0.15 -- -- 0.15 ------0.90 -- -- 12E3 Gas Engine #43 Affected Yes 9868A 0.15 -- -- 0.15 ------0.74 -- -- 12E4 Gas Engine #44 Affected Yes 9868A 0.15 -- -- 0.15 ------1.16 -- -- 12E5 Gas Engine #45 Affected Yes 9868A 0.15 -- -- 0.15 ------1.10 -- -- 12E6 Gas Engine #46 Affected Yes 9868A 0.11 -- -- 0.11 ------0.92 -- -- 12E7 Gas Engine #47 Affected Yes 9868A 0.11 -- -- 0.11 ------0.79 -- -- 93E1 Gas Engine #37 Affected Yes 9868A 0.10 -- -- 0.10 ------10.73 -- -- 93E2 Gas Engine #38 Affected Yes 9868A 0.10 -- -- 0.10 ------6.24 -- -- 66FL1 Refinery East HC Flare Affected Yes 9868A ------0.90 -- -- 28.59 -- --

66FL6 H2S Emergency Flare Affected Yes 9868A ------<0.01 -- -- 0.12 -- -- 66FL13 GOHDS Emergency Sulfur Flare Affected Yes 9868A ------0.66 -- -- 36.63 -- -- F-50A Coke Handling Affected Yes 9868A ------<0.01 -- -- 53R1 Loading Affected Yes 9868A ------0.17 -- -- 53R2 Loading Affected Yes 9868A ------

53R3 Loading Affected Yes 9868A ------8.32 -- -- 53T1 Loading Affected Yes 9868A ------<0.01 -- -- 53T2 Loading Affected Yes 9868A ------2.02 -- -- 109 Tank-Kerosene Affected Yes 9868A ------0.02 -- -- 110 Tank-DFPO Affected Yes 9868A ------0.03 -- -- 111 Tank-Light Slop Oil Affected Yes 9868A ------<0.01 -- -- 202 Tank-OSU Sludge Affected Yes 9868A ------<0.01 -- -- 401 Tank-Slop Oil Affected Yes 9868A ------511 Tank-Normal Heptane Affected Yes 9868A ------4.22 -- -- 514 Tank-AvGas Stock Affected Yes 9868A ------0.74 -- -- 562 Tank-Unleaded Gasoline Affected Yes 9868A ------26.90 -- -- 572 Tank-Slop Oil Affected Yes 9868A ------0.05 -- --

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 11 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: PM10 PM2.5 H2S VOC Affected Source? 24 Mo. Period 9/1/2012 9/1/2012 7/1/2012 7/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) 573 Tank-Slop Oil Affected Yes 9868A ------0.05 -- -- 1001 Tank-Plat Feed Affected Yes 9868A ------0.30 -- -- 1002 Tank-Plat Feed Affected Yes 9868A ------0.91 -- -- 1003 Tank-Benzene Hydro Feed Affected Yes 9868A ------0.21 -- -- 1006 Tank-Normal Heptane Affected Yes 9868A ------0.11 -- -- 1007 Tank-Normal Heptane Affected Yes 9868A ------3.87 -- -- 1012 Tank-Toluene Affected Yes 9868A ------0.99 -- -- 1013 Tank-Toluene Affected Yes 9868A ------1.62 -- -- 1067 Tank-Orfom SX-7 Affected Yes 9868A ------0.33 -- -- 1163 Tank-Gasoline Affected Yes 9868A ------36.87 -- -- 1164 Tank-Plat Feed Affected Yes 9868A ------1.84 -- -- 1165 Tank-Light Slop Oil Affected Yes 9868A ------2.42 -- -- 1522 Tank-Methanol Affected Yes 9868A ------2072 Tank-Tot Alky Affected Yes 9868A ------<0.01 -- -- 2510 Tank-AvGas Affected Yes 9868A ------24.77 -- -- 2530 Tank Affected Yes 9868A ------2553 Tank-Natural Gasoline Affected Yes 9868A ------9.79 -- -- 2572 Tank-Philjet ASO Affected Yes 9868A ------0.31 -- -- 2576 Tank-HP7 Affected Yes 9868A ------3.45 -- -- 2577 Tank-Unit 7 Heavy Plat Affected Yes 9868A ------0.01 -- -- 2578 Tank-Kerosene Distillate Affected Yes 9868A ------1.28 -- -- 2579 Tank-Light Slop Oil Affected Yes 9868A ------0.11 -- -- 2580 Tank-Diesel Affected Yes 9868A ------0.08 -- -- 2672 Tank-Orfom SX-7 Affected Yes 9868A ------0.28 -- -- 2673 Tank-Slop Oil Affected Yes 9868A ------3.04 -- -- 2674 Tank-Naphtha Affected Yes 9868A ------0.79 -- -- 2676 Tank-Philjet ASO Affected Yes 9868A ------1.09 -- -- 2677 Tank-Philjet ASO Affected Yes 9868A ------0.19 -- -- 2678 Tank-Philjet ASO Affected Yes 9868A ------0.90 -- -- 3001 Tank-NC7 Affected Yes 9868A ------2.53 -- -- 3002 Tank-NC6 Affected Yes 9868A ------3.69 -- -- 3003 Tank-Sour Water Affected Yes 9868A ------0.14 ------5505 Tank-Natural Gasoline Affected Yes 9868A ------21.59 -- -- 5508 Tank-Gas Oil Affected Yes 9868A ------4.62 -- -- 5511 Tank-Gas Oil Affected Yes 9868A ------18.75 -- -- 5520 Tank-Lt Alky Affected Yes 9868A ------0.43 -- -- 5531 Tank-Philjet ASO Affected Yes 9868A ------0.38 -- -- 5550 Tank-Various NGLs Affected Yes 9868A ------0.99 -- -- 5556 Tank-100-LL (AvGas) Affected Yes 9868A ------5.10 -- -- 5558 Tank-Natural Gasoline Affected Yes 9868A ------13.21 -- -- 5559 Tank-Naphtha Affected Yes 9868A ------10.28 -- -- 5578 Tank-Natural Gasoline Affected Yes 9868A ------19.70 -- -- 5580 Tank-Natural Gasoline Affected Yes 9868A ------1.94 -- --

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 12 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: PM10 PM2.5 H2S VOC Affected Source? 24 Mo. Period 9/1/2012 9/1/2012 7/1/2012 7/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) 5587 Tank-Carbon Black Oil (Slurry) Affected Yes 9868A ------1.19 -- -- 5588 Tank-Carbon Black Oil (Slurry) Affected Yes 9868A ------1.21 -- -- 5589 Tank-Kerosene Affected Yes 9868A ------5.93 -- -- 5590 Tank-Kerosene Affected Yes 9868A ------34.07 -- -- 5597 Tank-U19 Plat Gas Affected Yes 9868A ------12.45 -- -- 5598 Tank-Philjet ASO Affected Yes 9868A ------0.39 -- -- 8013 Tank-Topped Crude Affected Yes 9868A ------0.01 -- -- 9503 Tank-U19 Plat Gas Affected Yes 9868A ------25.95 -- -- 9700 Tank-Gas Oil Affected Yes 9868A ------24.15 -- -- KG47 Tank-Sulfur Storage Tank Affected Yes 9868A ------0.65 ------34I1 SRU Affected Yes 9868A 0.66 -- -- 0.66 -- -- 0.09 -- -- 0.46 -- -- 43I1 SRU Affected Yes 9868A 1.40 -- -- 1.40 -- -- 0.63 -- -- 0.53 -- -- 56-4 WW Affected Yes 9868A ------0.36 -- -- F-56-1-1 West Sump Affected Yes 9868A ------16.66 -- -- F-56-1-3 North Sump Affected Yes 9868A ------1.36 -- -- F-56-1-4-A Refinery Oil/Water Separators Affected Yes 9868A ------6.61 -- -- 29.85 -- -- F-56-1-5 Hazardous Waste Impoundment Affected Yes 9868A ------0.43 -- -- F-56-1-6 Storm Water System Affected Yes 9868A ------10.65 -- -- F-56-2 Dixon Creek WWTP Affected Yes 9868A ------1.07 -- -- 14.94 -- -- TKOFF1 WW Affected Yes 9868A ------TH1 WW Affected Yes 9868A ------TH2 WW Affected Yes 9868A ------53FL1 Loading Thermal Oxidizer Affected Yes 9868A ------13.03 -- -- FWP1 Fire Water Pump Affected Yes 9868A <0.01 ------<0.01 -- -- FWP2 Fire Water Pump Affected Yes 9868A <0.01 ------<0.01 -- -- FWP3 Fire Water Pump Affected Yes 9868A <0.01 ------<0.01 -- -- FWP4 Fire Water Pump Affected Yes 9868A <0.01 ------<0.01 -- -- FWP5 Fire Water Pump Affected Yes 9868A <0.01 ------<0.01 -- -- VF-1030 PAC Silo Affected Yes 9868A 0.05 ------VF-2030 PAC Silo Affected Yes 9868A 0.05 ------F-1 Fugitive Affected Yes 9868A ------103.64 -- -- F-1-6 Fugitive Affected Yes 9868A ------2.89 -- -- 42.94 -- -- F-1-7 Fugitive Affected Yes 9868A ------2.30 -- -- F-2 Fugitive Affected Yes 9868A ------185.05 -- -- F-2-1 Fugitive Affected Yes 9868A ------0.32 -- -- 39.06 -- -- F-2-5 Fugitive Affected Yes 9868A ------20.15 -- -- F-4 Fugitive Affected Yes 9868A ------16.01 -- -- F-5 Fugitive Affected Yes 9868A ------<0.01 -- -- 23.52 -- -- F-6 Fugitive Affected Yes 9868A ------80.45 -- -- F-9 Fugitive Affected Yes 9868A ------0.02 -- -- 3.69 -- -- F-10 Fugitive Affected Yes 9868A ------0.06 -- -- 5.05 -- -- F-11 Fugitive Affected Yes 9868A ------0.07 -- -- 22.30 -- -- F-12 Fugitive Affected Yes 9868A ------0.03 -- -- 15.20 -- --

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 13 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: PM10 PM2.5 H2S VOC Affected Source? 24 Mo. Period 9/1/2012 9/1/2012 7/1/2012 7/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) F-13 Fugitive Affected Yes 9868A ------38.90 -- -- F-19-1 Fugitive Affected Yes 9868A ------0.13 -- -- 13.89 -- -- F-19-3 Fugitive Affected Yes 9868A ------0.50 -- -- 16.33 -- -- F-22 Fugitive Affected Yes 9868A ------77.01 -- -- F-23 Fugitive Affected Yes 9868A ------0.08 -- -- 14.16 -- -- F-26 Fugitive Affected Yes 9868A ------0.20 -- -- 24.73 -- -- F-28 Fugitive Affected Yes 9868A ------0.03 -- -- 18.73 -- -- F-29 Fugitive Affected Yes 9868A ------0.34 -- -- 53.05 -- -- F-32 Fugitive Affected Yes 9868A ------0.05 -- -- 1.87 -- -- F-34 Fugitive Affected Yes 9868A ------2.08 -- -- 0.29 -- -- F-35 Fugitive Affected Yes 9868A ------1.17 -- -- 3.38 -- -- F-36 Fugitive Affected Yes 9868A ------0.57 -- -- 3.62 -- -- F-40 Fugitive Affected Yes 9868A ------0.13 -- -- 41.71 -- -- F-41 Fugitive Affected Yes 9868A ------0.15 -- -- 0.27 -- -- F-42 Fugitive Affected Yes 9868A ------1.04 -- -- 13.42 -- -- F-43-1 Fugitive Affected Yes 9868A ------5.56 -- -- <0.01 -- -- F-44 Fugitive Affected Yes 9868A ------0.91 -- -- <0.01 -- -- F-50 Fugitive Affected Yes 9868A ------3.58 -- -- F-51 Fugitive Affected Yes 9868A ------7.79 -- -- F-53-1 Fugitive Affected Yes 9868A ------<0.01 -- -- 6.39 -- -- F-53-2 Fugitive Affected Yes 9868A ------<0.01 -- -- 12.57 -- -- F-55 Fugitive Affected Yes 9868A ------0.37 -- -- F-56 Fugitive Affected Yes 9868A ------10.86 -- -- F-66-1 Fugitive Affected Yes 9868A ------<0.01 -- -- 2.89 -- -- F-66-2 Fugitive Affected Yes 9868A ------<0.01 -- -- 9.97 -- -- F-66-3 Fugitive Affected Yes 9868A ------<0.01 -- -- 2.89 -- -- F-68-1a Fugitive Affected Yes 9868A ------<0.01 -- -- 3.32 -- -- F-68-1e Fugitive Affected Yes 9868A ------<0.01 -- -- 11.43 -- -- F-68-1n Fugitive Affected Yes 9868A ------<0.01 -- -- 14.27 -- -- F-68-1r Fugitive Affected Yes 9868A ------<0.01 -- -- 3.24 -- -- F-68-1s Fugitive Affected Yes 9868A ------<0.01 -- -- 8.28 -- -- F-68-1t Fugitive Affected Yes 9868A ------<0.01 -- -- 3.88 -- -- F-68-1w Fugitive Affected Yes 9868A ------<0.01 -- -- 11.59 -- -- F-68-2n Fugitive Affected Yes 9868A ------0.01 -- -- 13.81 -- -- F-68-2s Fugitive Affected Yes 9868A ------<0.01 -- -- 10.26 -- -- F-68-3 Fugitive Affected Yes 9868A ------<0.01 -- -- 4.54 -- -- F-68-4t Fugitive Affected Yes 9868A ------<0.01 -- -- 10.37 -- -- F-68-5 Fugitive Affected Yes 9868A ------<0.01 -- -- 8.19 -- -- F-81 Fugitive Affected Yes 9868A ------5.84 -- -- F-82 Fugitive Affected Yes 9868A ------12.33 -- -- F-85-2 Fugitive Affected Yes 9868A ------<0.01 -- -- 9.42 -- -- F-98 Fugitive Affected Yes 9868A ------1.76 -- -- F-Tier 3 Fugitive Affected Yes 9868A ------

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 14 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: PM10 PM2.5 H2S VOC Affected Source? 24 Mo. Period 9/1/2012 9/1/2012 7/1/2012 7/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) F-56-1-4-A(1) WW Affected Yes 9868A ------F-56-1-4-A(3) WW Affected Yes 9868A ------F-56-1-4-A(4) WW Affected Yes 9868A ------Sitewide Cap Totals (See Table D-2 for flexible permit cap adjustments) 141.54 995.67 854.13 111.69 995.67 883.97 27.90 54.08 26.18 2,491.79 3,267.44 775.65 Non Flexible Permit Cap Sources 85B2 Unit 40 Boiler Affected No 9868A 10.17 19.52 9.35 10.17 19.52 9.35 ------0.88 14.13 13.25 40H3 Unit 40 Superheater Affected No 9868A -- 1.89 1.89 -- 1.89 1.89 ------2.76 2.76 40H4 Unit 40 Preheater Furnace Affected No 9868A 5.64 5.64 -- 5.64 5.64 ------8.24 8.24 -- 34I1 Merox SRU TGI Affected No 9868A -- 0.13 0.13 -- 0.13 0.13 ------0.82 0.82

F-56-1-4-A(2&5) West DAF Affected No 9868A ------7.91 7.91 -- 4.36 4.36 F-56-1-12 Flash Mixing Affected No 9868A ------0.06 0.06 -- 0.03 0.03 F-56-1-17 Flocculation Affected No 9868A ------0.24 0.24 -- 0.13 0.13 53R4 Sulfur Loading Rates (Interim) Affected No 9868A -- 0.17 0.17 -- 0.17 0.17 5.48 5.06 0.00 ------40P1 Unit 40 FCC Stack Affected No 9868A 90.89 447.00 356.11 60.91 447.00 386.09 ------50CDV1 Coker Drum Vent 1 (Post Coker Vent Affected No 9868A -- 3.08 3.08 -- 3.08 3.08 -- 2.33 2.33 -- 14.23 14.23 Improvement) 50CDV2 Coker Drum Vent 2 (Post Coker Vent Affected No 9868A -- 3.08 3.08 -- 3.08 3.08 -- 2.33 2.33 -- 14.23 14.23 Improvement) 50CDC1 Coker Drum Cutting 1 Affected No 9868A ------0.54 0.54 -- 3.26 3.26

50CDC2 Coker Drum Cutting 2 Affected No 9868A ------0.54 0.54 -- 3.26 3.26

50CDW Coker Drum Water Affected No 9868A ------12.18 12.18

0310 T-310 Sulfur Loading Tank Final Rates Affected No 9868A 0.05 0.07 0.02 0.05 0.07 0.02 3.49 2.93 ------

66FL1, Flares - Routine Emissions Affected No 9868A 66FL2, 66FL3, & 66FL12 (Routine Emissions) ------2.10 3.06 0.96 136.01 230.03 94.02 66FL1, 66FL2, Flares - Fuel Gas Long Scenario Affected No 9868A 66FL3, & 66FL12 (Fuel Gas Long) 66FL1, 66FL2, Flares - Flare Gas MSS Affected No 9868A 66FL3, & 66FL12 (Flare Gas MSS) 81B17 Boiler 2.4 Affected No 85872 3.42 4.63 1.21 3.42 4.63 1.21 ------2.78 3.35 0.57

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 15 of 16 Table D-1 PSD Evaluation - Criteria Pollutants Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

(1) EPN Description New/Modified/ Flex Cap? Pollutant: PM10 PM2.5 H2S VOC Affected Source? 24 Mo. Period 9/1/2012 9/1/2012 7/1/2012 7/1/2012 Ending: Permit Baseline PTE Project Baseline PTE Project Baseline PTE Project Baseline PTE Project Authorization (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) Increase (tpy) (tpy) (tpy) (tpy) BLR12 Boiler 12 Affected No 85872 -- 18.28 18.28 -- 18.28 18.28 ------13.23 13.23 SKDBLR Skid Boiler Affected No 85872 1.93 11.90 9.97 1.93 11.90 9.97 ------0.11 8.61 8.50 T-0520 Tank 520 Affected No 71385 ------0.10 0.20 0.10 F-54-C22 Crude Unit Cooling Tower Modified No PBR 106.371 0.26 0.26 -- <0.01 <0.01 ------1.47 1.47 --

Total Increases 1,283.45 1,343.28 41.55 1,059.66

PSD Significance Threshold 15.00 10.00 10.00 40.00

Triggers Netting? Y Y Y Y

Notes (1) Project increases for sources in the flexible permit cap are calculated by summing baseline actual emissions and subtracting the summed baseline actual emissions from the adjusted cap (see Table D-2).

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 16 of 16 Table D-2 Flexible Permit Cap Adjustment from Removing Sources to be Shut Down Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

FIN EPN Status Description Hourly Emission Cap Contribution (1) Annual Emission Rate Contribution (1)

NOX CO SO2 PM PM10 PM2.5 H2S VOC NOX CO SO2 PM PM10 PM2.5 H2S VOC

(lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) (tpy) (tpy) (tpy) H2S H2S (tpy) 7H1-4 7H1-4 Removed as part of project Heater -5.96 -3.48 -2.96 -1.50 -1.50 -1.50 0.00 -0.33 -26.11 -15.23 -12.98 -6.57 -6.57 -6.57 0.00 -1.43 9-1 9H1 Removed as part of project Heater -6.12 -3.57 -3.26 -1.66 -1.66 -1.66 0.00 -0.34 -26.81 -15.64 -14.28 -7.28 -7.28 -7.28 0.00 -1.49 10-1 10H1 Removed as part of project Heater -5.76 -3.36 -3.07 -1.56 -1.56 -1.56 0.00 -0.32 -25.22 -14.71 -13.43 -6.85 -6.85 -6.85 0.00 -1.40 T660.1, T660.2 19H5 Removed as part of project Heater -1.65 -0.96 -0.88 -0.45 -0.45 -0.45 0.00 -0.09 -7.23 -4.22 -3.85 -1.96 -1.96 -1.96 0.00 -0.40 19-6 19H6 Removed as part of project Heater -4.80 -2.80 -2.56 -1.30 -1.30 -1.30 0.00 -0.27 -21.02 -12.26 -11.19 -5.71 -5.71 -5.71 0.00 -1.17 28-1 28H1 Removed as part of project Heater -9.51 -5.55 -5.06 -0.94 -0.94 -0.94 0.00 -0.26 -41.66 -24.30 -22.18 -4.13 -4.13 -4.13 0.00 -1.16 19-1 19B1/19H1 Removed as part of project Heater -8.52 -4.97 -4.54 -2.31 -2.31 -2.31 0.00 -0.47 -37.32 -21.77 -19.87 -10.14 -10.14 -10.14 0.00 -2.07 T631.1, T631.2 19B1/19H2 Removed as part of project Heater -4.98 -2.90 -2.65 -1.35 -1.35 -1.35 0.00 -0.28 -21.81 -12.72 -11.61 -5.92 -5.92 -5.92 0.00 -1.21 7-E1 7E1 Removed as part of project Unit 7 Plat Engine #1 -4.06 -2.94 0.00 -0.03 -0.03 -0.03 0.00 -0.66 -17.77 -12.88 -0.01 -0.14 -0.14 -0.14 0.00 -2.89 7-E2 7E2 Removed as part of project Unit 7 Plat Engine #2 -4.06 -2.94 0.00 -0.03 -0.03 -0.03 0.00 -0.66 -17.77 -12.88 -0.01 -0.14 -0.14 -0.14 0.00 -2.89 7-E3 7E3 Removed as part of project Unit 7 Plat Engine #3 -4.06 -2.94 0.00 -0.03 -0.03 -0.03 0.00 -0.66 -17.77 -12.88 -0.01 -0.14 -0.14 -0.14 0.00 -2.89 7-E4 7E4 Removed as part of project Unit 7 Plat Engine #4 -4.06 -2.94 0.00 -0.03 -0.03 -0.03 0.00 -0.66 -17.77 -12.88 -0.01 -0.14 -0.14 -0.14 0.00 -2.89 7-E5 7E5 Removed as part of project Unit 7 Plat Engine #5 -4.06 -2.94 0.00 -0.03 -0.03 -0.03 0.00 -0.66 -17.77 -12.88 -0.01 -0.14 -0.14 -0.14 0.00 -2.89 7-E6 7E6 Removed as part of project Unit 7 Plat Engine #6 -4.06 -2.94 0.00 -0.03 -0.03 -0.03 0.00 -0.66 -17.77 -12.88 -0.01 -0.14 -0.14 -0.14 0.00 -2.89 P-7 F-7 Removed as part of project Unit 7 Fugitives 0.00 0.00 0.00 0.00 0.00 0.00 -0.0004 -11.34 0.00 0.00 0.00 0.00 0.00 0.00 -1.61E-03 -49.68 P-19-2 F-19-2 Removed as part of project Unit 19.2 Fugitives 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -2.43 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -10.64 See Above See Above All Removed Sources All Removed Sources -71.64 -45.24 -24.99 -11.28 -11.28 -11.28 -3.68E-04 -20.08 -313.80 -198.15 -109.46 -49.39 -49.39 -49.39 -1.61E-03 -87.96 ------All Removed Sources + 9% -78.09 -49.31 -27.24 -12.29 -12.29 -12.29 -4.01E-04 -21.89 -342.04 -215.99 -119.31 -53.83 -53.83 -53.83 -1.75E-03 -95.88 Insignificant Factor (2) ------Authorized Flexible Permit Caps 1,224.53 797.61 6,620.98 246.59 246.59 246.59 246.59 1,575.26 2,463.56 3,480.37 2,967.16 1,049.50 1,049.50 1,049.50 54.08 3,363.32 (3)

Multiple Multiple -- New Flexible Permit Caps 1,146.44 748.30 6,593.74 234.30 234.30 234.30 246.59 1,553.37 2,121.52 3,264.38 2,847.85 995.67 995.67 995.67 54.08 3,267.44

Notes

(1) There is no flexible permit cap for total PM emissions. For purposes of the PSD evaluation, it is conservatively assumed that PM = PM10 = PM2.5. (2) The 9% insignificant factor is being removed from source cap contributions as part of the Flexible Permit 9868A renewal/amendment application (TCEQ Project No.240881). However, because the renewal/amendment has not been isused yet, the cap contributions include the 9% insignificant factor for purposes of this table. (3) The current authorized flexible permit caps are those equal to the June 18, 2019 version of the Flexible Permit 9868A MAERT.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1of 1

Page ______of ______APDG 5881v1 (Draft 04/2008) FNSR Permits - Applicability Determination Page 37 of 37

TABLE 2F PROJECT EMISSION INCREASE

Pollutant1: CO Permit: TBD Baseline Period: May 1, 2010 to April 30, 2012 A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table D-1 in Appendix D for equivalent. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >100

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___1__ of _2____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___2__ of ___2__ TABLE 2F PROJECT EMISSION INCREASE

1 Pollutant : H2S Permit: TBD Baseline Period: August 1, 2010 to July 31, 2012 A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table D-1 in Appendix D for equivalent. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >10

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___1__ of _2____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___2__ of ___2__ TABLE 2F PROJECT EMISSION INCREASE

1 Pollutant : NOX Permit: TBD Baseline Period: September 1, 2010 to August 31, 2012 A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table D-1 in Appendix D for equivalent. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >40

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page _____ of _____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page _____ of _____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant1: PM Permit: TBD Baseline Period: October 1, 2010 to September 30, 2012 A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table D-1 in Appendix D for equivalent. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >25

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___1__ of _2____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___2__ of ___2__ TABLE 2F PROJECT EMISSION INCREASE

1 Pollutant : PM2.5 Permit: TBD Baseline Period: October 1, 2010 to September 30, 2012 A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table D-1 in Appendix D for equivalent. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >25

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___1__ of _2____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___2__ of ___2__ TABLE 2F PROJECT EMISSION INCREASE

1 Pollutant : PM10 Permit: TBD Baseline Period: October 1, 2010 to September 30, 2012 A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table D-1 in Appendix D for equivalent. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >25

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___1__ of _2____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___2__ of ___2__ TABLE 2F PROJECT EMISSION INCREASE

1 Pollutant : SO2 Permit: TBD Baseline Period: March 1, 2010 to February 29, 2012 A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table D-1 in Appendix D for equivalent. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >40

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___1__ of _2____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___2__ of ___2__ TABLE 2F PROJECT EMISSION INCREASE

Pollutant1: VOC Permit: TBD Baseline Period: August 1, 2010 to July 31, 2012 A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table D-1 in Appendix D for equivalent. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >40

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___1__ of _2____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___2__ of ___2__ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company Permit Application Number: TBD Criteria Pollutant: CO A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table D-1 in Appendix D for equivalent.

2. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not 3. perform a netting analysis and perform a PSD review for all applicable pollutants.

4. A list of all emission increases that occurred during the contemporaneous period, other than those from this project, will be provided with the Air Quality and Additional Impacts Analysis (air dispersion modeling) report to be submitted subsequent to this application. 5. 6. 7. 8. 9. 10. Page Subtotal8 >100 Summary of Contemporaneous Changes Total >100

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page __1___ of ___1__ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company

Permit Application Number: TBD Criteria Pollutant: H2S A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table D-1 in Appendix D for equivalent.

2. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not 3. perform a netting analysis and perform a PSD review for all applicable pollutants.

4. 5. 6. 7. 8. 9. 10. Page Subtotal8 >10 Summary of Contemporaneous Changes Total >10

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page __1___ of __1___ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company

Permit Application Number: TBD Criteria Pollutant: NOX A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table D-1 in Appendix D for a list of emission changes associated with this project.

2. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not 3. perform a netting analysis and perform a PSD review for all applicable pollutants.

4. A list of all emission increases that occurred during the contemporaneous period, other than those from this project, will be provided with the Air Quality and Additional Impacts Analysis (air dispersion modeling) report to be submitted subsequent to this application. 5. 6. 7. 8. 9. 10. Page Subtotal8 >40 Summary of Contemporaneous Changes Total >40

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page ___1__ of __1___ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company Permit Application Number: TBD Criteria Pollutant: PM A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table D-1 in Appendix D for a list of emission changes associated with this project.

2. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not 3. perform a netting analysis and perform a PSD review for all applicable pollutants.

4. 5. 6. 7. 8. 9. 10. Page Subtotal8 >25 Summary of Contemporaneous Changes Total >25

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page __1___ of _1____ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company

Permit Application Number: TBD Criteria Pollutant: PM10 A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table D-1 in Appendix D for a list of emission changes associated with this project.

2. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not 3. perform a netting analysis and perform a PSD review for all applicable pollutants.

4. A list of all emission increases that occurred during the contemporaneous period, other than those from this project, will be provided with the Air Quality and Additional Impacts Analysis (air dispersion modeling) report to be submitted subsequent to this application. 5. 6. 7. 8. 9. 10. Page Subtotal8 >15 Summary of Contemporaneous Changes Total >15

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page __1___ of __1___ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company

Permit Application Number: TBD Criteria Pollutant: PM2.5 A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table D-1 in Appendix D for a list of emission changes associated with this project.

2. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not 3. perform a netting analysis and perform a PSD review for all applicable pollutants.

4. A list of all emission increases that occurred during the contemporaneous period, other than those from this project, will be provided with the Air Quality and Additional Impacts Analysis (air dispersion modeling) report to be submitted subsequent to this application. 5. 6. 7. 8. 9. 10. Page Subtotal8 >10 Summary of Contemporaneous Changes Total >10

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page ___1__ of __1___ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company

Permit Application Number: TBD Criteria Pollutant: SO2 A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table D-1 in Appendix D for a list of emission changes associated with this project.

2. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not 3. perform a netting analysis and perform a PSD review for all applicable pollutants.

4. A list of all emission increases that occurred during the contemporaneous period, other than those from this project, will be provided with the Air Quality and Additional Impacts Analysis (air dispersion modeling) report to be submitted subsequent to this application. 5. 6. 7. 8. 9. 10. Page Subtotal8 >40 Summary of Contemporaneous Changes Total >40

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page __1___ of __1___ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company Permit Application Number: TBD Criteria Pollutant: VOC A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table D-1 in Appendix D for a list of emission changes associated with this project.

2. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not 3. perform a netting analysis and perform a PSD review for all applicable pollutants.

4. A list of all emission increases that occurred during the contemporaneous period, other than those from this project, will be provided with the Air Quality and Additional Impacts Analysis (air dispersion modeling) report to be submitted subsequent to this application. 5. 6. 7. 8. 9. 10. Page Subtotal8 >40 Summary of Contemporaneous Changes Total >40

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page ___1__ of __1___

APPENDIX E: GHG POLLUTANT EMISSION CALCULATIONS The following tables are included in this appendix: • Table E-1: Emissions Summary and PSD Evaluation - GHG Emissions; • Table E-2: Detailed Heater Calculations - GHG Emissions; • Table E-3: CCR Regeneration Emissions - GHG Emissions; • Table E-4: Detailed Flare MSS Calculations - GHG Emissions; • Table E-5: Detailed Fugitive Emission Calculations - GHG;

• TCEQ Table 2F: Project Emission Increases – CO2e; and

• TCEQ Table 3F: Project Contemporaneous Change – CO2e.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Table E-1 Emissions Summary - GHG Emissions Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

FIN EPN Description Annual Emission Rates Reference Table(s)

CO2 CH4 N2O CO2e (tpy) (tpy) (tpy) (tpy) 28-H3 28-H3 Crude Charge Furnace 109,640 5.57 1.11 110,111 E-2 28-H4 28-H4 Crude Charge Furnace 109,640 5.57 1.11 110,111 E-2 88-H1.1, 1.2, 88-H1.1, 1.2, CCR Charger and Interheaters 235,170 11.96 2.39 236,182 E-2 1.3 1.3 88-V1 88-V1 CCR Vent 2,695.76 -- -- 2,695.76 E-3 F-CrudeFlex F-CrudeFlex CCR/Crude Flex Fugitives -- 49.24 -- 1,230.97 E-5 CCR-MSS CCR-MSS_C Turn Around Clearing - CCR 51.73 0.16 <0.01 55.78 E-4 (Flare) CCR-MSS CCR-MSS_U Turn Around Clearing - CCR ------No GHGs (Atmosphere) NS-MSS NS-MSS_C Turn Around Clearing - Naphtha 51.62 0.16 <0.01 55.67 E-4 Splitter (Flare) NS-MSS NS-MSS_U Turn Around Clearing - Naphtha ------No GHGs Splitter (Atmosphere)

MISC-MSS MISC-MSS Insignificant and Routine MSS ------No GHGs See Above MSS Planned MSS Emissions 103.34 0.31 <0.01 111.45 Sum of Above -- -- Total Emissions (tpy) 457,249.18 72.66 4.62 460,443.16 ------PSD Significance Threshold (tpy) ------75,000.00 ------Triggers PSD Review? (1) ------Yes --

Notes (1) See Section 3.2.3 in the permit application for a discussion on the PSD evaluation for GHG emissions.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table E-2 Detailed Heater Calculations - GHG Emissions Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery 0 1 2 5 6 7 11 12 13 (3) CO2e Factor (ton CO2e / ton) : 1 298 25 FIN EPN Description Annual Firing Emission Factors (2) Annual Emission Rates(1) Rate

CO2 N2O CH4 CO2 N2O CH4 CO2e

(MMBtu/hr) (kg/MMBtu) (kg/MMBtu) (kg/MMBtu) (tpy) (tpy) (tpy) (tpy) (HHV) 28-H3 28-H3 Crude Charge Heater 192.50 59 0.0006 0.003 109,640 1.11 5.57 110,111 28-H4 28-H4 Crude Charge Heater 192.50 59 0.0006 0.003 109,640 1.11 5.57 110,111 88-H1.1, 1.2, 1.3 88-H1 CCR Charger and Interheaters 412.90 59 0.0006 0.003 235,170 2.39 11.96 236,182

Notes: (1) The emission factors used to estimate emissions for each pollutant from this equipment are not meant to be operational constraints. Concentrations and other operational parameters may vary. Compliance is determined based on emission rates (lb/hr and tpy). (2) Emission factors based on the fuel gas factors in Table C-1 and Table C-2 in 40 CFR Part 98 Subpart C.

(3) CO2 equivalency factors are based on Table A-1 in 40 CFR Part 98 Subpart A.

Sample Calculations: 28-H3 (Crude Charge Heater)

Proposed Average Annual Emission Rates (CO2, N2O, CH4).

ERa = FRa * EFa * 2.204 * 8,760 / 2,000

ERa,CO2 = 192.50 MMBtu/hr * 59 kg CO2/MMBtu * 2.204 lb/kg * 8,760 hours/year / 2,000 lb/ton = 109,640 tpy CO2

ERa,N2O = 192.50 MMBtu/hr * 0.0006 kg N2O/MMBtu * 2.204 lb/kg * 8,760 hours/year / 2,000 lb/ton = 1.11 tpy N2O

ERa,CH4 = 192.50 MMBtu/hr * 0.003 kg CH4/MMBtu * 2.204 lb/kg * 8,760 hours/year / 2,000 lb/ton = 5.57 tpy CH4

Proposed Average Annual Emission Rates (CO2e).

ERa = CO2eCO2*ERCO2 +CO2eN2O*ERN2O + CO2eCH4*ERCH4

ERCO2e = 1 ton CO2e / ton CO2 * 109,640 tpy CO2 + 298 ton CO2e / ton N2O * 1.11 tpy N2O + 25 ton CO2e / ton CH4 * 5.57 tpy CH4 = 110,111 tpy CO2e

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table E-3 CCR Regeneration Emissions - GHG Emissions Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

Emission Point Number: 88-V1

Parameters Values Units Regenerator Flue Gas Mass Flow Rate (1) 1,644 lb/hr Regenerator Flue Gas Volumetric Flow Rate (1) 21,141 scf/hr (2) CO2 Concentration in Flue Gas 25.50 vol%

CO2 Molecular Weight 44.00 lb/lbmole

Pollutant Annual Emission Rate (4)

(tpy)

CO2 2,695.76 (3) CO2e 2,695.76

Notes (1) The mass flow rate is converted to volumetric flow using the flue gas composition.

(2) The CO2 concentrations is based on design engineering documents.

(3) CO2e is based on a global warming potential of 1 ton CO2e / ton of CO2, as per Table A-1 in 40 CFR Part 98 Subpart A. (4) The emission factors used to estimate emissions for each pollutant from these activities are not meant to be operational constraints. Concentrations and other operational parameters may vary. Compliance is determined based on emission rates (tpy).

Sample Calculations (CO2) 21,141 scf/hr * 25.50 vol% / 100 / 385.40 scf/lbmol * 44.00 lb CO/lb-mole * 8,760 hours/year / 2,000 lb/ton = 2,695.76 tpy

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table E-4 Detailed Flare MSS Calculations - GHG Emissions Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery 0 1 2 5 6 7 11 12 13 (3) CO2e Factor (ton CO2e / ton) : 1 298 25 FIN EPN Description Annual Firing Emission Factors (2) Annual Emission Rates(1) Rate (4)

CO2 N2O CH4 CO2 N2O CH4 CO2e

(MMBtu/yr) (kg/MMBtu) (kg/MMBtu) (kg/MMBtu) (tpy) (tpy) (tpy) (tpy) (HHV) CCR-MSS CCR-MSS_C Turn Around Clearing - CCR 798.26 60 0.0006 0.003 51.73 0.001 0.16 55.78 (Flare) NS-MSS NS-MSS_C Turn Around Clearing - 796.59 60 0.0006 0.003 51.62 0.001 0.16 55.67 Naphtha Splitter (Flare)

Notes: (1) The emission factors used to estimate emissions for each pollutant from this equipment are not meant to be operational constraints. Concentrations and other operational parameters may vary. Compliance is determined based on emission rates (tpy). (2) Emission factors and equations based on 40 CFR Part 98 Subpart Y (Equations Y-2, Y-4, and Y-5).

(3) CO2 equivalency factors are based on Table A-1 in 40 CFR Part 98 Subpart A. (4) Annual firing rates are based on the values calculated in Tables C-7b and C-8b.

Sample Calculations: CCR-MSS

Proposed Average Annual Emission Rates (CO2, N2O, CH4).

ERCO2 = 798.26 MMBtu/yr * 60 kg CO2/MMBtu *2.204 lb/kg / 2,000 lb/ton * 98% conversion = 51.73 tpy CO2

ERN2O = 51.73 tpy CO2 * (0.0006 kg N2O / MMBtu / 60 kg CO2/MMBtu) = 0.001 tpy N2O

ERCH4 = ( 51.73 tpy CO2 * (0.0030 kg N2O / MMBtu / 60 kg CO2/MMBtu)) + (51.73 tpy CO2 * 0.02 / 0.98 * 16 /44 * 0.4) = 0.16 tpy CH4

Proposed Average Annual Emission Rates (CO2e).

ERa = CO2eCO2*ERCO2 +CO2eN2O*ERN2O + CO2eCH4*ERCH4

ERCO2e = 1 ton CO2e / ton CO2 * 51.73 tpy CO2 + 298 ton CO2e / ton N2O * 0.001 tpy N2O + 25 ton CO2e / ton CH4 * 0.16 tpy CH4 = 55.78 tpy CO2e

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 Table E-5 Detailed Fugitive Emission Calculations - GHG Crude Flexibility and Modernization Project - Phillips 66 Borger Refinery

See Table C-4 in Appendix C for Detailed Fugitive Calculations for Total Emissions (1) (2) Unit Fugitive EPN LDAR Program Total Annual Percent CH4 CH4 Emissions CO2e Emissions Emissions

(tpy) (%) (tpy) (tpy) CCR Unit F-CCR 28VHP / 28PI 51.12 10 5.11 127.79 CCR Unit - F-CCR 28PI 39.14 99 38.75 968.77 Natural Gas Naphtha Splitter F-NS 28VHP / 28PI 7.99 10 0.80 19.98 Unit Naphtha Splitter F-NS 28PI 3.67 99 3.63 90.75 Unit - Natural Gas

Crude Desalter F-32 28VHP / 28PI 5.08 10 0.51 12.71 Unit Crude Unit F-28 28VHP / 28PI 1.11 10 0.11 2.78 SCR Fugitives F-SCR 28AVO 0.40 0 0.00 0.00 Unit 6 Columns F-6 28VHP / 28PI 0.01 10 0.001 0.02 Unit 2 Columns F-2 28VHP / 28PI 0.10 10 0.01 0.25 Tank Farm F-53-1 28VHP / 28PI 1.13 10 0.11 2.81 GOHDS Unit F-42 28VHP / 28PI 2.04 10 0.20 5.09 Total Fugitive Emissions from Crude Flexibility and Modernization Project F-CrudeFlex F-CrudeFlex Various 111.78 -- 49.24 1,230.97

Notes (1) Speciated emissions are based on engineering judgment and should not be considered limits. Natural gas component emissions assume up to 99% by weight methane.

(2) CO2e emissions are calculated by multiplying the CH4 emissions by a global warming potential of 25 tons of CO2e / ton CH4, as per Table A-1 in 40 CFR Part 98 Subpart A. (3) Sample Calculations (CCR Unit) 51.12 tpy total emissions * 10% methane = 5.11 tpy methane 5.11 tpy methane emissions * 25 tpy CO2e / tpy methane = 127.79 tpy CO2e

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Page 1 of 1 TABLE 2F PROJECT EMISSION INCREASE

Pollutant1: GHG Permit: TBD Baseline Period: N/A to N/A A B Affected or Modified Facilities2 Permit No. Actual Emissions3 Baseline Proposed Projected Difference Correction7 Project FIN EPN Emissions4 Emissions5 Actual (B-A)6 Increase8 Emissions 1. See Table E-1 in Appendix E for emissions from new sources associated with the project. See Section 3.2.3 in the permit application for a discussion of project emission increases of GHGs. 2. 3. 4 5. 6. 7. 8. 9. Page Subtotal9 >75,000

1 Individual Table 2F=s should be used to summarize the project emission increase for each criteria pollutant 2 Emission Point Number as designated in NSR Permit or Emissions Inventory 3 All records and calculations for these values must be available upon request 4 Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement 5 If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement 6 Proposed Emissions (column B) minus Baseline Emissions (column A) 7 Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement 8 Obtained by subtracting the correction from the difference. Must be a positive number. 9 Sum all values for this page. TCEQ - 20470(Revised 04/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___1__ of _2____ TABLE 2F PROJECT EMISSION INCREASE

Pollutant: Line Type10 Explanation:

10 Type of note. Generally would be baseline adjustment, basis for projected actual, or basis for correction (what could have been accommodated).

TCEQ - 20470(Revised 03/12) Table 2F These forms are for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5915v2) Page ___2__ of ___2__ TABLE 3F PROJECT CONTEMPORANEOUS CHANGES1

Company: Phillips 66 Company

Permit Application Number: TBD Criteria Pollutant: CO2e A B Project Date2 Facility at Which Permit No. Project Name Baseline Proposed Baseline Difference Creditable Emission Change or Activity Period Emissions Emissions (A-B)6 Decrease or Occurred3 (years) (tons/year)4 (tons/year)5 Increase7 FIN EPN 1. See Table E-1 in Appendix E for emissions from new sources associated with the project. See Section 3.2.3 in the permit application for a discussion of project emission increases of GHGs. 2. 3. Although a facility can demonstrate net emissions increases are below the PSD significance thresholds, Phillips 66 Borger Refinery is electing to not perform a netting analysis and perform a PSD review for all applicable pollutants. 4. 5. 6. 7. 8. 9. 10. Page Subtotal8 >75,000 Summary of Contemporaneous Changes Total >75,000

1 Individual Table 3F=s should be used to summarize the project emission increase and net emission increase for each criteria pollutant. 2 The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed. 3 Emission Point No. as designated in NSR Permit or Emissions Inventory. 4 All records and calculations for these values must be available upon request. 5 All records and calculations for these values must be available upon request. 6 Proposed (column A) - Baseline (column B). 7 If portion of the decrease not creditable, enter creditable amount. 8 Sum all values for this page. TCEQ - 10156(Revised 03/12) Table 3F These forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5913v2) Page __1___ of _1____

APPENDIX F: AIR QUALITY ANALYSIS This appendix includes the TCEQ’s EMEW for non-PSD pollutants.

INITIAL PERMIT APPLICATION – CRUDE FLEXIBILITY AND MODERNIZATION PROJECT Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD General Company Name: Phillips 66 Company EMEW Version No.: Version 2.3 Purpose Statement: This workbook is completed by the applicant and submitted to the Texas Commission on Environmental Quality (TCEQ), specifically, the Air Dispersion Modeling Team (ADMT) for review. This workbook is a tool available for all projects using AERSCREEN, AERMOD, or ISC/ISCPrime for an impacts review and its use is required starting June 1, 2019. Provide the workbook with the permit application submittal for any Minor New Source Review project requiring a modeling impacts demonstration.

This workbook follows the guidance outlined in the Air Quality Modeling Guidelines (APDG 6232) which can be found here: https://www.tceq.texas.gov/assets/public/permitting/air/Modeling/guidance/airquality-mod-guidelines6232.pdf

Workbook Instructions: 1. Save a copy of the workbook to your computer or desktop prior to entering data. 2. Complete all required sections leaving no blanks. You may use the "tab" button or the arrow keys to move to the next available cell. Use "enter" to move down a line. Note: drop-downs are case-sensitive. 3. Fill in the workbook in order, do not skip around as this will cause errors. Use caution if changing a previously entered entry. 4. Not applicable sections of this workbook will be hidden as data is entered. For example, answering "No" to "Is downwash applicable? " will hide these sections of the workbook required only for downwash entry. 5. Email the workbook electronic file (EMEW) and any attachments to the Air Permits Initial Review Team. The subject line should read "Company Name - Permit Number (if known) - NSR Permit Application". Email address: [email protected] 6. If printing the EMEW, follow the directions below to create a workbook header. 7. Printing the EMEW is not required for submitting to the Air Permits Division (APD); however, you may need to print it for sending to the regional offices, local programs, and for public access if notice is required. To print the workbook, follow the instructions below. Please be aware, several sheets contain large amounts of data and caution should be taken if printing, such as the Speciated Emissions sheet. 8. Updates may be necessary throughout the review process. Updated workbooks must be submitted in electronic format to APD. For submittal to regional offices, local programs, or public places you only have to print sheets that had updates. Be sure to change the headers accordingly.

Note: Since this will be part of the permit application, follow the instructions in the Form PI-1 General Application on where to send copies of your EMEW and permit application. The Form PI-1 General Application can be found here: https://www.tceq.texas.gov/permitting/air/guidance/newsourcereview/nsrapp-tools.html Create Headers Before Printing: 1. Right-click one of the workbook’s sheet tabs and "Select All Sheets." 2. Enter the "Page Layout View" by using the navigation ribbon's View > Workbook Views > Page Layout, or by clicking the page layout icon in the lower-right corner of Excel. 3. Add the date, company name, and permit number (if known) to the upper-right header. Note that this may take up to a minute to update your spreadsheet. Select any tab to continue working on the spreadsheet.

Printing Tips: While APD does not need a hard copy of the full workbook, you may need to print it for sending to the regional offices, local programs, and for public access if notice is required. 1. The default printing setup for each sheet in the workbook is set for the TCEQ preferred format. The print areas are set up to not include the instructions on each sheet. 2. You have access to change all printing settings to fit your needs and printed font size. Some common options include: -Change what area you are printing (whole active sheet or a selection); -Change the orientation (portrait or landscape); -Change the margin size; and -Change the scaling (all columns on one sheet, full size, your own custom selection, etc.).

Final Modeling Submittal: Anytime final modeling files are being submitted the applicant should notify the following that modeling files are being sent: permit reviewer assigned, permit reviewer’s supervisor, and the modeler assigned from the initial submittal. The following options are available for an applicant to provide modeling (or any other files): 1. Applicant can mail or hand deliver the files on an external storage device. 2. Applicant can email files smaller than 25mb. 3. Applicant can transfer files through an FTP site: a. Applicant may have their own FTP site and can share the files with TCEQ staff. b. Applicants can use the TCEQ FTP site. Instructions for setting up an account on the TCEQ FTP site are located at: https://ftps.tceq.texas.gov/help/

Page 1 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD General Company Name: Phillips 66 Company Acknowledgement: Select from the drop down: I acknowledge that I am submitting an authorized TCEQ Electronic Modeling Evaluation Workbook and any necessary attachments. Except for inputting the requested data, I have not changed the TCEQ Electronic Modeling Evaluation Workbook in any way, I agree including but not limited to changing formulas, formatting, content, or protections.

Administrative Information: Data Type: Facility Information: Project Number (6 digits): Permit Number: Regulated Entity ID (9 digits): 102495884 Facility Name: Borger Refinery Facility Address: State Spur 119 Facility County (select one): Hutchinson Company Name: Phillips 66 Company Company Contact Name: Russell Hill Company Contact Number: (806) 275-1348 Company Contact Email: [email protected] Modeling Company Name, as applicable: TRICORD Consulting, LLC Modeling Contact Name: Anthony Anders Modeling Contact Number: (832) 714-1418 Modeling Contact Email: [email protected] New/Existing Site (select one): Existing Site Modeling Date (MM/DD/YYYY): 3/31/2020 Datum Used (select one): NAD 83 UTM Zone (select one): 14 Sheet Instructions: Indicate in the Table of Contents which sections are applicable and included for this modeling demonstration. Select "X" from the drop down if the item below is included in the workbook. Note: This workbook is only for the following air dispersion models: AERSCREEN, ISC/ISCPrime, and/or AERMOD. If SCREEN3 is used, please use the separate Electronic Modeling Evaluation Workbook (EMEW) for SCREEN3 workbook. Table of Contents: Section: Sheet Title (Click to jump to specific sheet): Select an X from the dropdown menu if included: 1 General X 2 Model Options X 3 Building Downwash X 4 Flare Source Parameters X 5 Point Source Parameters X 6 Area Source Parameters 7 Volume Source Calculations X 8 Volume Source Parameters X 9 Point and Flare Source Emissions X 10 Area Source Emissions 11 Volume Source Emissions X 12 Speciated Emissions 13 Intermittent Sources 14 Modeling Scenarios X 15 Monitor Calculations 16 Background Justification 17 Secondary Formation of PM2.5 18 NAAQS/State Property Line (SPL) Modeling Results X 19 Unit Impact Multipliers X 20 Health Effects Modeling Results 21 Modeling File Names X 22 Speciated Chemicals

Page 2 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD General Company Name: Phillips 66 Company Included Attachments Select an X from the Instructions: The following are attachments that must be included with any modeling analysis. If dropdown menu if providing the plot plan and area map with the permit application, ensure there is also a copy included: with the EMEW. The copy can be electronic.

Plot Plan: Instructions: Mark all that apply in the attached plot plan. For larger properties or dense source areas, provide multiple zoomed in plot plans that are legible. Property/Fence Lines all visible and marked. X North arrow included. X Clearly marked scale. X All sources and buildings are clearly labeled. X Area Map: Instructions: Mark all that apply in the attached area map. Annotate schools within 3,000ft of source's nearest property line. X All property lines are included. X Non-industrial receptors are identified. Choose an item Additional Attachments (as applicable): Select an X from the Note: These are just a few examples of attachments that may need to be included. There may dropdown menu if be others depending on the scope of the modeling analysis. included: Processed Met Data Information Excel spreadsheet of processed meteorology data. Choose an item Meteorological Files (all input and outputs). Choose an item Source Group Descriptions Description of modeling source groups (could be in a tabulated format). Choose an item Modeling Techniques and Scenarios Provide all justification and discussion on modeling scenarios used for the modeling analyses. The following boxes are examples of approaches that should be provided but is not all inclusive. Discussion on modeling techniques not discussed in workbook. Choose an item Justification for exceedance refinements, as applicable. Choose an item Discussion and images for worst-case determination, as applicable. Choose an item Single Property Line Designation, as applicable Include Agreement, Order, and map defining each petitioner. Choose an item Post Processing using Unit Impact Multipliers (UIMs) Include documentation on any calculations used with the UIMs (i.e., Step 3 of the MERA). X

Tier 3 NO2 analysis If OLM or PVMRM are used, provide all justification and documentation on using this approach. Description of model setup. Choose an item

Description and justification of model options selected (i.e., NO 2 to NOx in-stack ratios). Choose an item

Other Attachments Provide a list in the box below of additional attachments being provided that are not listed above: Attachment 1 - Area Map X Attachment 2a - Plot Plan Overview Attachment 2b - Plot Plan North Attachment 2c - Plot Plan South Attachment 3 - Unit Impact Calculations

Page 3 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Model Options Company Name: Phillips 66 Company I. Project Information A. Project Overview: In the box below, give a brief Project Overview. To type or insert text in box, double click in the box below. Please limit your response to 2000 characters.

Phillips 66 Borger Refinery plans to construct a new Continuous Catalytic Reformer (CCR) Unit and a new Naphtha Splitter Unit, install new and more efficient crude charge heaters to replace the existing crude charge heaters, and make modifications in other selected refinery process units, including shutting down certain older process units. The physical changes will increase overall refinery efficiency and accommodate more crude slate variability.

This line was intentionally left blank. II. Air Dispersion Modeling Preliminary Information Instructions: Fill in the information below based on your modeling setup. The selections chosen in this sheet will carry throughout the sheet and workbook. Based on selections below, only portions of the sheet and workbook will be available. Therefore, it is vital the sheet and workbook are filled out in order, do NOT skip around.

For larger text boxes, double click to type or insert text. A. Type of Model Used: Select "X" in all that apply ISC or ISCPrime AERSCREEN X AERMOD 19191 Enter in all applicable Model Version(s). B. Building Downwash Yes Is downwash applicable? (Select "Yes" or "No") 04274 Enter BPIP version (AERMOD and ISCPrime only). C. Type of Analyses: (Select "X" in all that apply) *PSD projects should submit a protocol and not utilize this form.

Minor NSR NAAQS X State Property Line X Health Effects

Page 4 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Model Options Company Name: Phillips 66 Company D. Constituents Evaluating: (Select "X" in all that apply) NAAQS: List all pollutants that require a modeling review. (Select "X" in all that apply) SO2 PM10

CO PM2.5

Pb NO2

Identify which averaging periods are being evaluated for NO 2.

Identify the 1-hr NO2 tier used for the AERMOD or AERSCREEN analyses.

Identify the annual NO2 tier used for the AERMOD or AERSCREEN analyses.

Provide additional information relied on for the Tier 3 analysis for conversion of NO x to NO2 in the box below. Note the ozone monitor relied on should be documented in the Monitor Calculations and Background Justification Sheets.

Identify the 1-hr NO2 tier used for the ISC/ISCPrime analyses.

Identify the annual NO2 tier used for the ISC/ISCPrime analyses.

State Property Line: List all pollutants that require a modeling review. (Select "X" in all that apply)

XH2SXSO2

H2SO4 Health Effects: Fill in the Speciated Emissions sheet with all applicable pollutants, CAS numbers, and ESLs.

Page 5 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Model Options Company Name: Phillips 66 Company E. Dispersion Options: If "Urban" has been selected and this project is using AERMOD or AERSCREEN, include the population used. Select "X" in the box to select an option.

Urban Population Used X Rural Provide any additional justification on the dispersion option selected above:

F. Determination of Surface Roughness: If AERSCREEN or AERMOD is used, fill out the section below. Select basis for surface roughness: AERSURFACE

If you are using AERSCREEN, please enter the following information: Bowen Ratio Zo Value Albedo Select "X" in one of the three surface roughness categories: Low X Medium High If you are using AERSURFACE, please complete the following section: 13016 AERSURFACE Version Number 285881.2Center UTM Easting (meters) 3952848.1 Center UTM Northing (meters) 1 Study Radius (km) No Airport? (Select Yes or No) No Continuous Snow Cover (Select Yes or No) Average Surface Moisture (Select Wet, Dry, or Average) No Arid Region? (Select Yes or No) Default Month/Season Assignment

Page 6 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Model Options Company Name: Phillips 66 Company G. Meteorological Data: If AERMOD and/or ISC/ISCPrime are selected, please complete the following section: 3024 Surface Station 23047 Upper Air Station 930.9 Meters (m) Profile Base Elevation (AERMOD only) 16216 AERMET Version Number Meters (m) Anemometer Height (ISC/ISCPrime only). Yes Was TCEQ pre-processed data 1 Year Years used used? Please enter the year(s) selected for this meteorological data: 2012 1 Year 5 Years Which analysis(es) relied on 1 year? Which analysis(es) relied on 5 years? For other processed meteorological data, provide a description below. In addition, be sure to include all raw data, AERSURFACE, AERMINUTE and AERMET input and outputs, and AERMOD ready files as an attachment.

For applicants using AERSCREEN, please fill out the boxes below: For AERSCREEN which met selection was used? Select whether Adjust u* was used. (Select "Yes" or "No") Minimum Temperature Maximum Temperature Meters (m) Anemometer Height Provide any other justification for Meteorological Data, as applicable.

Page 7 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Model Options Company Name: Phillips 66 Company H. Receptor Grid: For AERMOD or ISC/ISCPrime, fill in the following information on your modeled receptor grid. Note: Receptor grid resolution (tight, fine, medium, coarse) are based on recommended receptor grid spacing per the AQMG, if something outside of this is used, fully describe it below.

25Meters (m) Tight Receptor Spacing 100 Meters (m) Tight Receptor Distance 100 Meters (m) Fine Receptor Spacing 1000 Meters (m) Fine Receptor Distance 500 Meters (m) Medium Receptor Spacing 5000 Meters (m) Medium Receptor Distance Meters (m) Coarse Receptor Spacing Meters (m) Coarse Receptor Distance Describe any other receptor grid designs (over water, GLCni, SPLD etc.):

Meters (m) If AERSCREEN is selected, enter minimum distance to ambient air. I. Terrain: X Elevated Flat 18081 AERMAP Version. For additional justification on terrain selection, fill in the box below:

Page 8 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Building Downwash Company Name: Phillips 66 Company

Facility:

Downwash Type Modeled Building ID Tank Diameter (m) Number of Tiers Maximum Height (m) Tier 1 Height (m) Tier 2 Height (m) Tier 3 Height (m) Building 1 1 3.05 3.05 Building 2 1 3.05 3.05 Building 3 1 9.141 9.141 Building 4 1 6.099 6.099 Building 10 1 21.339 21.339 Building 16 1 9.141 9.141 Building 20 1 4.569 4.569 Building 21 1 9.141 9.141 Building 22 1 13.719 13.719 Building 104 1 7.62 7.62 Building 111-1 1 3.051 3.051 Building 116 1 9.141 9.141 Building 123 1 4.569 4.569 Building 124 1 4.569 4.569 Building 125 1 6.099 6.099 Building 126 1 3.051 3.051 Building 127 1 6.099 6.099 Building 131 1 12.189 12.189 Building 134 1 3.051 3.051 Building 136 1 3.051 3.051 Building 140 1 6.099 6.099 Building 142 1 6.099 6.099 Building 148 1 6.099 6.099 Building 151 1 9.141 9.141 Building 153 1 7.62 7.62 Building 154 1 4.569 4.569 Building 160 1 3.051 3.051 Building 163 1 9.141 9.141 Building 172 1 10.671 10.671 Building 178 1 4.569 4.569 Building 179 1 3.051 3.051 Building 181 1 10.671 10.671 Building 182 1 4.57 4.57 Building 183 1 7.01 7.01 Building 184 1 3.05 3.05 Building 185 1 7.62 7.62 Building 512 1 4.57 4.57 Building 1011B 1 3.05 3.05 Building 1022 1 12.19 12.19 Building 1024 1 3.05 3.05

Page 9 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Building Downwash Company Name: Phillips 66 Company

Downwash Type Modeled Building ID Tank Diameter (m) Number of Tiers Maximum Height (m) Tier 1 Height (m) Tier 2 Height (m) Tier 3 Height (m) Building 1064B 1 3.05 3.05 Building 1165B 1 6.1 6.1 Building 1201 1 6.1 6.1 Building 1203 1 3.05 3.05 Building 1551 1 4.57 4.57 Building 2510-1 1 10.67 10.67 Building 2511 1 10.67 10.67 Building 2551 1 10.67 10.67 Building 2552-1 1 9.14 9.14 Building 2553-1 1 3.66 3.66 Building 2554 1 4.57 4.57 Building 2571B 1 3.05 3.05 Building 2572B 1 12.19 12.19 Building 2576B 1 4.57 4.57 Building 2577B 1 3.05 3.05 Building 5504 1 3.05 3.05 Building 5001 1 11.58 11.58 Building 111 1 6.71 6.71 Building 202 1 4.88 4.88 Building 401 1 7.24 7.24 Building 1004 1 11.38 11.38 Building 2552 1 11.13 11.13 Building 2671 1 12.19 12.19 Building 1-1 1 6.1 6.1 Building 121-2 1 7.62 7.62 Building 122-2 1 6.099 6.099 Building 127-1 1 4.57 4.57 Building 127-2 1 7.62 7.62 Building 128-2 1 3.051 3.051 Building 128-3 1 3.051 3.051 Building 131-2 1 4.569 4.569 Building 136-4 1 3.051 3.051 Building 140-4 1 10.671 10.671 Building 140-7 1 3.051 3.051 Building 153-2 1 4.569 4.569 Building 159-2 1 3.051 3.051 Building 181-2 1 6.1 6.1 Building 184-2 1 6.1 6.1 Building b1 1 10.67 10.67 Building b10 1 3.05 3.05 Building b3 1 33.53 33.53 Building b4 1 33.53 33.53 Building b5 1 4.57 4.57 Building b7 1 6.1 6.1 Building b8 1 3.66 3.66

Page 10 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Building Downwash Company Name: Phillips 66 Company

Downwash Type Modeled Building ID Tank Diameter (m) Number of Tiers Maximum Height (m) Tier 1 Height (m) Tier 2 Height (m) Tier 3 Height (m) Building b9 1 3.66 3.66 Building BD1 1 6.1 6.1 Building BD2 1 4.57 4.57 Building CT21 1 9.14 9.14 Building kg47 1 14.66 14.66 Building 309 1 7.32 7.32 Building MAINT 1 12.19 12.19 Building n1 1 6.1 6.1 Building n2 1 6.1 6.1 Building n3 1 6.1 6.1 Building 8003 1 8.23 8.23 Building 8004 1 12.22 12.22 Building P_SERV 1 12.22 12.22 Building P_UPS 1 9.14 9.14 Building SS1 1 6.096 6.096 Building SS3 1 6.096 6.096 Building SS7A 1 3.048 3.048 Building SS7B 1 3.6576 3.6576 Building SS7C 1 3.048 3.048 Tank 1002 13.2588 1 11.5824 11.5824 Tank 1003 13.4112 1 11.3791 11.3791 Tank 1006 13.2588 1 12.8016 12.8016 Tank 1007 13.1064 1 12.8016 12.8016 Tank 1008 13.2588 1 11.5824 11.5824 Tank 1011 15.1385 1 8.763 8.763 Tank 1012 13.7922 1 10.795 10.795 Tank 1013 13.7922 1 10.795 10.795 Tank 1064 15.24 1 8.8392 8.8392 Tank 1067 15.24 1 8.8392 8.8392 Tank 109 6.4008 1 6.7056 6.7056 Tank 110 6.4008 1 6.7056 6.7056 Tank 1163 13.1064 1 11.303 11.303 Tank 1164 13.4112 1 11.5824 11.5824 Tank 1165 13.1064 1 11.9126 11.9126 Tank 1522 15.8496 1 12.7254 12.7254 Tank 2072 18.288 1 12.192 12.192 Tank 2510 21.336 1 11.1252 11.1252 Tank 2553 20.4216 1 12.192 12.192 Tank 2571 24.079 1 8.814 8.814 Tank 2572 21.336 1 12.192 12.192 Tank 2575 24.079 1 8.839 8.839 Tank 2576 24.079 1 8.839 8.839 Tank 2577 24.079 1 8.839 8.839 Tank 2578 21.336 1 8.839 8.839 Tank 2579 21.336 1 12.192 12.192 Tank 2580 21.336 1 12.192 12.192 Tank 2670 21.336 1 11.4809 11.4809 Tank 2672 20.1168 1 12.5222 12.5222 Tank 2673 20.4216 1 14.6558 14.6558 Tank 2674 24.0792 1 8.8392 8.8392 Tank 2675 18.288 1 15.24 15.24 Tank 2676 20.4216 1 12.2174 12.2174 Tank 2677 20.4216 1 12.1158 12.1158 Tank 2678 20.4216 1 11.9126 11.9126 Tank 3001 22.098 1 14.351 14.351 Tank 3002 22.3519 1 11.6078 11.6078 Tank 3003 30.48 1 14.63 14.63 Tank 303 8.1534 1 9.144 9.144 Tank 4030 21.336 1 17.0688 17.0688 Tank 511 9.7536 1 10.9728 10.9728 Tank 513 11.5824 1 8.8392 8.8392 Tank 514 9.144 1 12.192 12.192 Tank 5505 34.7472 1 9.144 9.144 Tank 552 11.2776 1 8.3058 8.3058 Tank 5520 34.7472 1 9.144 9.144 Tank 5521 30.48 1 14.9352 14.9352 Tank 5525 34.7472 1 9.2202 9.2202 Tank 5531 29.2608 1 12.9793 12.9793 Tank 5536 34.7472 1 9.2202 9.2202 Tank 5537 34.7472 1 9.2202 9.2202 Tank 5539 35.052 1 9.2202 9.2202 Tank 5540 34.7472 1 9.2202 9.2202 Tank 5541 35.052 1 9.2202 9.2202

Page 11 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Building Downwash Company Name: Phillips 66 Company

Downwash Type Modeled Building ID Tank Diameter (m) Number of Tiers Maximum Height (m) Tier 1 Height (m) Tier 2 Height (m) Tier 3 Height (m) Tank 5542 34.7472 1 9.2202 9.2202 Tank 5543 34.7472 1 9.2202 9.2202 Tank 5544 34.7472 1 9.2202 9.2202 Tank 5545 34.7472 1 9.2202 9.2202 Tank 5550 34.7472 1 9.2202 9.2202 Tank 5551 30.48 1 12.2174 12.2174 Tank 5553 30.48 1 11.9126 11.9126 Tank 5554 30.48 1 12.2429 12.2429 Tank 5555 30.48 1 12.2174 12.2174 Tank 5557 30.48 1 12.192 12.192 Tank 5558 30.48 1 12.192 12.192 Tank 5559 30.48 1 12.192 12.192 Tank 5560 30.48 1 12.192 12.192 Tank 5578 30.48 1 12.2174 12.2174 Tank 5580 30.48 1 12.4206 12.4206 Tank 5583 27.432 1 14.6304 14.6304 Tank 5584 27.432 1 14.6304 14.6304 Tank 5587 25.6032 1 16.7894 16.7894 Tank 5588 25.6032 1 16.9926 16.9926 Tank 5591 30.48 1 12.8016 12.8016 Tank 5592 32.6136 1 10.0584 10.0584 Tank 5593 32.6136 1 10.0838 10.0838 Tank 5596 30.0228 1 12.192 12.192 Tank 5597 25.6032 1 17.0688 17.0688 Tank 5598 30.48 1 12.192 12.192 Tank 5599 25.6032 1 17.0688 17.0688 Tank 562 10.668 1 9.6774 9.6774 Tank 572 9.144 1 12.192 12.192 Tank 573 9.144 1 12.192 12.192 Tank 8001 36.576 1 12.192 12.192 Tank 8002 36.576 1 12.2174 12.2174 Tank 8010 30.48 1 16.7894 16.7894 Tank 8011 35.6616 1 12.4968 12.4968 Tank 8012 35.6616 1 12.5222 12.5222 Tank 8013 35.6616 1 12.5222 12.5222 Tank 8014 35.6616 1 12.5222 12.5222 Tank 8015 30.48 1 16.7894 16.7894 Tank 8031 35.3822 1 14.0208 14.0208 Tank 8032 35.6616 1 14.8337 14.8337 Tank 8033 30.48 1 16.7894 16.7894 Tank 8034 33.528 1 14.4526 14.4526 Tank 8036 60.96 1 4.8768 4.8768 Tank 9200 40.8432 1 14.5542 14.5542 Tank 9201 40.8432 1 14.6304 14.6304 Tank 9202 40.8432 1 14.6304 14.6304 Tank 9400 42.672 1 14.6304 14.6304 Tank 9401 42.672 1 14.6304 14.6304 Tank 9500 45.72 1 14.5289016 14.5289016 Tank 9501 45.72 1 14.6304 14.6304 Tank 9502 45.72 1 14.6304 14.6304 Tank 9503 45.72 1 14.6304 14.6304 Tank 9504 45.72 1 14.7066 14.7066 Tank 9600 60.96 1 9.7536 9.7536 Tank 9601 60.96 1 9.7536 9.7536 Tank 9700 52.7304 1 14.65578984 14.65578984 Tank 9701 52.7304 1 14.65578984 14.65578984 Tank 9702 52.7304 1 14.65578984 14.65578984 Tank SS2 16.46 1 19.81 19.81 Tank SS5 10.36 1 12.19 12.19 Tank SS6 33.22 1 4.88 4.88

Page 12 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Flare Source Parameters Company Name: Phillips 66 Company

Facility: Easting: Northing: Base Exit Gross Heat Net Heat Modeling Elevation Height Temperature Exit Velocity Heat Release Molecular Release or q Release or qn Effective Diameter or EPN Model ID Scenario X [m] Y [m] [m] [m] [K] [m/s] (MMBtu/hr) Weight (cal/s) (cal/s) D (meters) Description CCR-MSS_C 66FL1CR FLARE 286360.00 3953654.00 919.91 42.67 1273.00 20.00 4104.09 65.00 287285976.5 176109644.2 13.27 Turn Around Clearing - CCR Turn Around Clearing - Naphtha NS-MSS_C 66FL1NS FLARE 286360.00 3953654.00 919.91 42.67 1273.00 20.00 599.58 65.00 41970681.93 25728516.06 5.07 Splitter CCR-MSS_C 66FL2CR FLARE 286226.00 3953655.00 914.38 42.67 1273.00 20.00 4104.09 65.00 287285976.5 176109644.2 13.27 Turn Around Clearing - CCR Turn Around Clearing - Naphtha NS-MSS_C 66FL2NS FLARE 286226.00 3953655.00 914.38 42.67 1273.00 20.00 599.58 65.00 41970681.93 25728516.06 5.07 Splitter CCR-MSS_C 66FL3CR FLARE 285577.00 3953312.00 908.11 42.67 1273.00 20.00 4104.09 65.00 287285976.5 176109644.2 13.27 Turn Around Clearing - CCR Turn Around Clearing - Naphtha NS-MSS_C 66FL3NS FLARE 285577.00 3953312.00 908.11 42.67 1273.00 20.00 599.58 65.00 41970681.93 25728516.06 5.07 Splitter CCR-MSS_C 66FL12CR FLARE 285378.00 3953348.00 911.27 60.96 1273.00 20.00 4104.09 65.00 287285976.5 176109644.2 13.27 Turn Around Clearing - CCR Turn Around Clearing - Naphtha NS-MSS_C 66FL12NS FLARE 285378.00 3953348.00 911.27 60.96 1273.00 20.00 599.58 65.00 41970681.93 25728516.06 5.07 Splitter

Page 13 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Point Source Parameters Company Name: Phillips 66 Company

Facility: Base Modeling Point Source Easting: Northing: Elevation Exit Temperature Exit Velocity EPN Model ID Scenario Source Description Type Point Source Justification X [m] Y [m] [m] Height [m] [K] [m/s] Diameter [m] 28-H3 28_H3 FLARE Crude Charge Furnace POINT Vertical stack 286410.00 3953589.00 922.20 29.23 438.710 4.572 2.731 28-H4 28_H4 FLARE Crude Charge Furnace POINT Vertical stack 286410.00 3953578.00 922.20 29.23 438.710 4.572 2.731 CCR Charger and 88-H1 88_H1 FLARE POINT Vertical stack 286496.00 3953440.00 913.03 57.91 516.483 8.839 2.134 Interheaters 88-V1 88_V1 FLARE CCR Vent POINT Vertical stack 286496.00 3953479.00 913.24 36.88 310.930 4.724 0.244 SCR Fugitives Fugitives FSCR_H3 FSCR_H3 FLARE POINT Pseudo-point 286410.00 3953589.00 922.20 3.05 0.000 0.001 0.001 at Crude Heater H3 SCR Fugitives Fugitives FSCR_H4 FSCR_H4 FLARE POINT Pseudo-point 286410.00 3953578.00 922.20 3.05 0.000 0.001 0.001 at Crude Heater H4 SCR Fugitives Fugitives FSCR_CCR FSCR_CCR FLARE POINT Pseudo-point 286496.00 3953440.00 913.03 3.05 0.000 0.001 0.001 at CCR Heaters F_SUMPCCR F_SMPCCR FLARE CCR Sump POINT Pseudo-point 286528.00 3953484.00 927.19 1.00 0.000 0.001 0.001

Page 14 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Volume Source Calculations Company Name: Phillips 66 Company

Facility:

Footprint of Footprint of Type of Volume Source (sigma y) Sigma Y Vertical Span Vertical Span Vertical Type of Volume Source (sigma z) Release Height Building Name Adjacent Building Sigma Z Source Source Length of Side (making Dimension (middle point of (if on/adjacent to a Height, if it a square) Min Release Max Release vertical span) building) applicable EPN Model ID Length (m) Width (m) SQRT(L * W) Pick from drop-down (m) (m) (m) (m) Pick from drop-down (m) Pick from drop-down (m) (m) F-CCR F_CCR_1 90.00 92.00 90.99 Single Volume Source 21.16 0.00 9.14 9.14 Surface-Based Source 4.57 4.25 CCR-MSS_U CCRMSS_1 90.00 92.00 90.99 Single Volume Source 21.16 0.00 15.24 15.24 Surface-Based Source 7.62 7.09 F-NS F_NS_1 27.50 35.00 31.02 Multiple Volumes: Adjacent Volume Sources 14.43 0.00 9.14 9.14 Surface-Based Source 4.57 4.25 F-NS F_NS_2 27.50 35.00 31.02 Multiple Volumes: Adjacent Volume Sources 14.43 0.00 9.14 9.14 Surface-Based Source 4.57 4.25 NS-MSS_U NSMSS_1 27.50 35.00 31.02 Multiple Volumes: Adjacent Volume Sources 14.43 0.00 15.24 15.24 Surface-Based Source 7.62 7.09 NS-MSS_U NSMSS_2 27.50 35.00 31.02 Multiple Volumes: Adjacent Volume Sources 14.43 0.00 15.24 15.24 Surface-Based Source 7.62 7.09 F-32 F_32_1 40.17 50.56 45.07 Single Volume Source 10.48 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-28 F_28_1 60.96 60.96 60.96 Single Volume Source 14.18 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-2 F_2_1 51.82 42.67 47.02 Single Volume Source 10.94 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-6 F_6_1 32.51 32.00 32.26 Multiple Volumes: Adjacent Volume Sources 15.00 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-6 F_6_2 32.51 32.00 32.26 Multiple Volumes: Adjacent Volume Sources 15.00 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-6 F_6_3 32.51 32.00 32.26 Multiple Volumes: Adjacent Volume Sources 15.00 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-42 F_42_1 80.00 85.00 82.46 Single Volume Source 19.18 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-53-1 F_53_1_1 30.00 31.00 30.50 Multiple Volumes: Adjacent Volume Sources 14.18 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-53-1 F_53_1_2 30.00 31.00 30.50 Multiple Volumes: Adjacent Volume Sources 14.18 0.00 6.10 6.10 Surface-Based Source 3.05 2.84 F-53-1 F_53_1_3 30.00 31.00 30.50 Multiple Volumes: Adjacent Volume Sources 14.18 0.00 6.10 6.10 Surface-Based Source 3.05 2.84

Page 15 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Volume Source Parameters Company Name: Phillips 66 Company

Facility: Modeled Modeled Lateral Vertical Base Release Length X Dimension Dimension Modeling Easting: Northing: Elevation EPN Model ID Height [m] [m] SigmaY [m] SigmaZ [m] Scenario X [m] Y [m] [m] Source Description Volume Source Size Justification Fugitives emissions based on average height of F-CCR F_CCR_1 4.57 90.99 21.16 4.25 FLARE 286489.00 3953481.00 926.78 CCR Unit Fugitives release and dimensions of process area Turn Around Clearing - CCR Fugitives emissions based on average height of CCR-MSS_U CCRMSS_1 7.62 90.99 21.16 7.09 FLARE 286489.00 3953481.00 926.78 (Atmosphere) release and dimensions of process area Fugitives emissions based on average height of F-NS F_NS_1 4.57 31.02 14.43 4.25 FLARE 286457.75 3953545.50 925.19 Naphtha Splitter Unit Fugitives release and dimensions of process area Fugitives emissions based on average height of F-NS F_NS_2 4.57 31.02 14.43 4.25 FLARE 286485.25 3953545.50 925.33 Naphtha Splitter Unit Fugitives release and dimensions of process area Turn Around Clearing - Naphtha Fugitives emissions based on average height of NS-MSS_U NSMSS_1 7.62 31.02 14.43 7.09 FLARE 286457.75 3953545.50 925.19 Splitter (Atmosphere) release and dimensions of process area Turn Around Clearing - Naphtha Fugitives emissions based on average height of NS-MSS_U NSMSS_2 7.62 31.02 14.43 7.09 FLARE 286485.25 3953545.50 925.33 Splitter (Atmosphere) release and dimensions of process area Fugitives emissions based on average height of F-32 F_32_1 3.05 45.07 10.48 2.84 FLARE 286261.94 3953596.88 923.22 Crude Desalter Fugitives release and dimensions of process area Fugitives emissions based on average height of F-28 F_28_1 3.05 60.96 14.18 2.84 FLARE 286341.97 3953599.45 923.59 Crude Unit Fugitives release and dimensions of process area Fugitives emissions based on average height of F-2 F_2_1 3.05 47.02 10.94 2.84 FLARE 285358.50 3953045.38 923.36 Unit 2 Columns Fugitives release and dimensions of process area Fugitives emissions based on average height of F-6 F_6_1 3.05 32.26 15.00 2.84 FLARE 285378.13 3952906.49 922.64 Unit 6 Columns Fugitives release and dimensions of process area Fugitives emissions based on average height of F-6 F_6_2 3.05 32.26 15.00 2.84 FLARE 285410.64 3952906.49 922.69 Unit 6 Columns Fugitives release and dimensions of process area Fugitives emissions based on average height of F-6 F_6_3 3.05 32.26 15.00 2.84 FLARE 285443.15 3952906.49 923.21 Unit 6 Columns Fugitives release and dimensions of process area Fugitives emissions based on average height of F-42 F_42_1 3.05 82.46 19.18 2.84 FLARE 286002.53 3952564.04 929.62 GOHDS Unit Fugitives release and dimensions of process area Fugitives emissions based on average height of F-53-1 F_53_1_1 3.05 30.50 14.18 2.84 FLARE 286544.45 3953708.87 926.48 Tank Farm Fugitives release and dimensions of process area Fugitives emissions based on average height of F-53-1 F_53_1_2 3.05 30.50 14.18 2.84 FLARE 286573.79 3953702.64 926.89 Tank Farm Fugitives release and dimensions of process area Fugitives emissions based on average height of F-53-1 F_53_1_3 3.05 30.50 14.18 2.84 FLARE 286603.13 3953696.40 925.58 Tank Farm Fugitives release and dimensions of process area

Page 16 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Point + Flare Emissions Company Name: Phillips 66 Company

Facility:

Modeling Modeled Averaging Intermittent Modeled Emission Scalars or Factors EPN Model ID Scenario Pollutant Time Standard Type Review Context Source? Rate [lb/hr] Basis of Emission Rate Used? Scalar/Factor in Use 28-H3 28_H3 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No 28-H4 28_H4 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No 88-H1 88_H1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No 88-V1 88_V1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No FSCR_H3 FSCR_H3 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No FSCR_H4 FSCR_H4 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No FSCR_CCR FSCR_CCR FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F_SUMPCCR F_SMPCCR FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No CCR-MSS_C 66FL1CR FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No NS-MSS_C 66FL1NS FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No CCR-MSS_C 66FL2CR FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No NS-MSS_C 66FL2NS FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No CCR-MSS_C 66FL3CR FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No NS-MSS_C 66FL3NS FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No CCR-MSS_C 66FL12CR FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No NS-MSS_C 66FL12NS FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No 88-V1 88_V1 FLARE Generic Annual No 0.228 Generic modeling at 1 tpy No 28-H3 28_H3 FLARE SO2 1-hr State Property Line Project Wide No 6.16 Project increases No 28-H4 28_H4 FLARE SO2 1-hr State Property Line Project Wide No 6.16 Project increases No 88-H1 88_H1 FLARE SO2 1-hr State Property Line Project Wide No 13.21 Project increases No 88-V1 88_V1 FLARE SO2 1-hr State Property Line Project Wide No 0.703 Project increases No CCR-MSS_C 66FL1CR FLARE SO2 1-hr State Property Line Project Wide No 0.689 Project increases No NS-MSS_C 66FL1NS FLARE SO2 1-hr State Property Line Project Wide No 0.402 Project increases No CCR-MSS_C 66FL2CR FLARE SO2 1-hr State Property Line Project Wide No 0.689 Project increases No NS-MSS_C 66FL2NS FLARE SO2 1-hr State Property Line Project Wide No 0.402 Project increases No CCR-MSS_C 66FL3CR FLARE SO2 1-hr State Property Line Project Wide No 0.689 Project increases No NS-MSS_C 66FL3NS FLARE SO2 1-hr State Property Line Project Wide No 0.402 Project increases No CCR-MSS_C 66FL12CR FLARE SO2 1-hr State Property Line Project Wide No 0.689 Project increases No NS-MSS_C 66FL12NS FLARE SO2 1-hr State Property Line Project Wide No 0.402 Project increases No

Page 17 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Volume Source Emissions Company Name: Phillips 66 Company

Facility:

Modeling Modeled Averaging Intermittent Modeled Emission Scalars or Factors EPN Model ID Scenario Pollutant Time Standard Type Review Context Source? Rate [lb/hr] Basis of Emission Rate Used? Scalar/Factor in Use F-CCR F_CCR_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No CCR-MSS_U CCRMSS_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-NS F_NS_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-NS F_NS_2 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No NS-MSS_U NSMSS_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hrNo NS-MSS_U NSMSS_2 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hrNo F-32 F_32_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-28 F_28_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-2 F_2_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-6 F_6_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-6 F_6_2 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-6 F_6_3 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-42 F_42_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-53-1 F_53_1_1 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-53-1 F_53_1_2 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-53-1 F_53_1_3 FLARE Generic 1-hr No 1.00 Generic modeling at 1 lb/hr No F-CCR F_CCR_1 FLARE H2S 1-hr State Property Line Project Wide No 0.0584 Project increase No F-NS F_NS_1 FLARE H2S 1-hr State Property Line Project Wide No 0.00456 Project increase No F-NS F_NS_2 FLARE H2S 1-hr State Property Line Project Wide No 0.00456 Project increase No F-32 F_32_1 FLARE H2S 1-hr State Property Line Project Wide No 0.0158 Project increase No F-28 F_28_1 FLARE H2S 1-hr State Property Line Project Wide No 0.00329 Project increase No F-42 F_42_1 FLARE H2S 1-hr State Property Line Project Wide No 0.0181 Project increase No F-53-1 F_53_1_1 FLARE H2S 1-hr State Property Line Project Wide No 3.69E-05 Project increase No F-53-1 F_53_1_2 FLARE H2S 1-hr State Property Line Project Wide No 3.69E-05 Project increase No F-53-1 F_53_1_3 FLARE H2S 1-hr State Property Line Project Wide No 3.69E-05 Project increase No

Page 18 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Combined Emissions Company Name: Phillips 66 Company Modeling Modeled Averaging Source Modeled Emission EPN Model ID Scenario Pollutant Time Standard Type Review Context Intermittent Type Rate [lb/hr] 28-H3 28_H3 FLARE Generic 1-hr No Point 1.00 28-H4 28_H4 FLARE Generic 1-hr No Point 1.00 88-H1 88_H1 FLARE Generic 1-hr No Point 1.00 88-V1 88_V1 FLARE Generic 1-hr No Point 1.00 FSCR_H3 FSCR_H3 FLARE Generic 1-hr No Point 1.00 FSCR_H4 FSCR_H4 FLARE Generic 1-hr No Point 1.00 FSCR_CCR FSCR_CCR FLARE Generic 1-hr No Point 1.00 F_SUMPCCR F_SMPCCR FLARE Generic 1-hr No Point 1.00 CCR-MSS_C 66FL1CR FLARE Generic 1-hr No Flare 1.00 NS-MSS_C 66FL1NS FLARE Generic 1-hr No Flare 1.00 CCR-MSS_C 66FL2CR FLARE Generic 1-hr No Flare 1.00 NS-MSS_C 66FL2NS FLARE Generic 1-hr No Flare 1.00 CCR-MSS_C 66FL3CR FLARE Generic 1-hr No Flare 1.00 NS-MSS_C 66FL3NS FLARE Generic 1-hr No Flare 1.00 CCR-MSS_C 66FL12CR FLARE Generic 1-hr No Flare 1.00 NS-MSS_C 66FL12NS FLARE Generic 1-hr No Flare 1.00 88-V1 88_V1 FLARE Generic Annual No Point 0.23 28-H3 28_H3 FLARE SO2 1-hr State Property Line Project Wide No Point 6.16 28-H4 28_H4 FLARE SO2 1-hr State Property Line Project Wide No Point 6.16 88-H1 88_H1 FLARE SO2 1-hr State Property Line Project Wide No Point 13.21 88-V1 88_V1 FLARE SO2 1-hr State Property Line Project Wide No Point 0.70 CCR-MSS_C 66FL1CR FLARE SO2 1-hr State Property Line Project Wide No Flare 0.69 NS-MSS_C 66FL1NS FLARE SO2 1-hr State Property Line Project Wide No Flare 0.40 CCR-MSS_C 66FL2CR FLARE SO2 1-hr State Property Line Project Wide No Flare 0.69 NS-MSS_C 66FL2NS FLARE SO2 1-hr State Property Line Project Wide No Flare 0.40 CCR-MSS_C 66FL3CR FLARE SO2 1-hr State Property Line Project Wide No Flare 0.69 NS-MSS_C 66FL3NS FLARE SO2 1-hr State Property Line Project Wide No Flare 0.40 CCR-MSS_C 66FL12CR FLARE SO2 1-hr State Property Line Project Wide No Flare 0.69 NS-MSS_C 66FL12NS FLARE SO2 1-hr State Property Line Project Wide No Flare 0.40 F-CCR F_CCR_1 FLARE Generic 1-hr No Volume 1.00 CCR-MSS_U CCRMSS_1 FLARE Generic 1-hr No Volume 1.00 F-NS F_NS_1 FLARE Generic 1-hr No Volume 1.00 F-NS F_NS_2 FLARE Generic 1-hr No Volume 1.00 NS-MSS_U NSMSS_1 FLARE Generic 1-hr No Volume 1.00 NS-MSS_U NSMSS_2 FLARE Generic 1-hr No Volume 1.00 F-32 F_32_1 FLARE Generic 1-hr No Volume 1.00 F-28 F_28_1 FLARE Generic 1-hr No Volume 1.00 F-2 F_2_1 FLARE Generic 1-hr No Volume 1.00 F-6 F_6_1 FLARE Generic 1-hr No Volume 1.00 F-6 F_6_2 FLARE Generic 1-hr No Volume 1.00 F-6 F_6_3 FLARE Generic 1-hr No Volume 1.00 F-42 F_42_1 FLARE Generic 1-hr No Volume 1.00 F-53-1 F_53_1_1 FLARE Generic 1-hr No Volume 1.00 F-53-1 F_53_1_2 FLARE Generic 1-hr No Volume 1.00 F-53-1 F_53_1_3 FLARE Generic 1-hr No Volume 1.00 F-CCR F_CCR_1 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.06 F-NS F_NS_1 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.00 F-NS F_NS_2 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.00 F-32 F_32_1 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.02 F-28 F_28_1 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.00 F-42 F_42_1 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.02 F-53-1 F_53_1_1 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.00 F-53-1 F_53_1_2 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.00 F-53-1 F_53_1_3 FLARE H2S 1-hr State Property Line Project Wide No Volume 0.00

Page 19 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Modeling Scenarios Company Name: Phillips 66 Company Modeling Scenario Scenario Description: There are two flaring activities (CCR flaring and NS flaring) that though unlikely are modeled to occur FLARE simultaneously. There are four flares that could emit these emissions. The source groups in the model are for the separate flares EPNs combined with all other project sources.

Page 20 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD NAAQS-SPL Modeling Results Company Name: Phillips 66 Company

Table 1. Project-Related Modeling Results for State Property Line

Pollutant Averaging Time GLCmax (µg/m3) De Minimis (µg/m3)

SO2 1-hr 7.43531 20.42

H2SO4 1-hr 1

H2SO4 24-hr 0.3 2.16 (If property is residential, H S 1-hr 0.481 2 recreational, business, or commercial) 3.24 (If property is not residential, H S 1-hr 0.481 2 recreational, business, or commercial)

Page 21 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Unit Impact Multipliers Company Name: Phillips 66 Company

Facility: GLCmax GLCmax EPN Model ID Modeling Scenario Averaging Time (µg/m3 per lb/hr) (µg/m3 per tpy) 28-H3 28_H3 FLARE 1-hr 0.345 28-H4 28_H4 FLARE 1-hr 0.343 88-H1 88_H1 FLARE 1-hr 0.184 88-V1 88_V1 FLARE 1-hr 2.66 FSCR_H3 FSCR_H3 FLARE 1-hr 5.23 FSCR_H4 FSCR_H4 FLARE 1-hr 5.28 FSCR_CCR FSCR_CCR FLARE 1-hr 6.64 F_SUMPCCR F_SMPCCR FLARE 1-hr 9.46 CCR-MSS_C 66FL1CR FLARE 1-hr 0.0202 NS-MSS_C 66FL1NS FLARE 1-hr 0.0599 CCR-MSS_C 66FL2CR FLARE 1-hr 0.0167 NS-MSS_C 66FL2NS FLARE 1-hr 0.0532 CCR-MSS_C 66FL3CR FLARE 1-hr 0.0164 NS-MSS_C 66FL3NS FLARE 1-hr 0.0501 CCR-MSS_C 66FL12CR FLARE 1-hr 0.0154 NS-MSS_C 66FL12NS FLARE 1-hr 0.0442 88-V1 88_V1 FLARE Annual 0.00719 F-CCR F_CCR_1 FLARE 1-hr 5.82 CCR-MSS_U CCRMSS_1 FLARE 1-hr 5.06 F-NS F_NS_1 FLARE 1-hr 5.41 F-NS F_NS_2 FLARE 1-hr 5.43 NS-MSS_U NSMSS_1 FLARE 1-hr 4.77 NS-MSS_U NSMSS_2 FLARE 1-hr 4.80 F-32 F_32_1 FLARE 1-hr 4.94 F-28 F_28_1 FLARE 1-hr 4.99 F-2 F_2_1 FLARE 1-hr 8.55 F-6 F_6_1 FLARE 1-hr 9.76 F-6 F_6_2 FLARE 1-hr 9.35 F-6 F_6_3 FLARE 1-hr 8.81 F-42 F_42_1 FLARE 1-hr 6.39 F-53-1 F_53_1_1 FLARE 1-hr 4.80 F-53-1 F_53_1_2 FLARE 1-hr 4.86 F-53-1 F_53_1_3 FLARE 1-hr 4.96

Page 22 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Health Effect Modeling Results Company Name: Phillips 66 Company

Facility: Modeled Health Effect Results (MERA Guidance): Step 3

10% ESL Step 3 Modeled GLCmax Chemical Species CAS Number Averaging Time ESL [µg/m3] [µg/m3] Light Petroleum Distillates N/A 1-hr Provide Documentation 326.82 Heavy Petroleum Distillates N/A 1-hr Provide Documentation 4.24 crude oil, < 1% benzene N/A 1-hr 3500 5.73 ammonia 7664-41-7 1-hr 180 1.42 chlorine 7782-50-5 1-hr 43 2.59 chlorine 7782-50-5 Annual 2.6 0.03 hydrogen chloride 7647-01-0 1-hr 190 0.05 hydrogen chloride 7647-01-0 Annual 7.9 0.00

Page 23 Texas Commission on Environmental Quality Date: March 2020 Electronic Modeling Evaluation Workbook (EMEW) Permit #: TBD Modeling File Names Company Name: Phillips 66 Company

Facility:

Model File Base Name Pollutant Averaging Time File Extensions Additional File Description *.MAP, *.Mot, *.rcf, *.Rmp, P66 HER Step 3 Unit 1-hr and Annual aermap files *.srf *.PIP, *.PRW, *.SO, *.SUM, P66 HER Step 3 Unit 1-hr and Annual downwash files *.TAB *.BND, *.dta, *.GRF, *.LST, P66 HER Step 3_2012_UNITHR Unit 1-hr project-wide unit impact *.SUM *.BND, *.dta, *.GRF, *.LST, P66 HER Step 3_2012_UNITANN Unit Annual project-wide unit impact *.SUM *.MAP, *.Mot, *.rcf, *.Rmp, P66 SPL PID SO2 and H2S 1-hr aermap files *.srf *.PIP, *.PRW, *.SO, *.SUM, P66 SPL PID SO2 and H2S 1-hr Downwash files *.TAB *.BND, *.dta, *.GRF, *.LST, P66 SPL PID_2012_SO2 SO2 1-hr project-wide *.SUM *.BND, *.dta, *.GRF, *.LST, P66 SPL PID_2012_H2S H2S 1-hr project-wide *.SUM Hutchinson_BGDAMA12M All 1-hr and Annual *.PFL, *.SFC surface and upper air met files terrain.tif All 1-hr and Annual *.tif terrain files aersurface All 1-hr and Annual *.DAT, *.inp aersurface files aersurfaceremote All 1-hr and Annual *.log, *.lst aersurface files albedo_bowen_domain All 1-hr and Annual *.txt aersurface files ASR All 1-hr and Annual *.lst aersurface files roughness_domain All 1-hr and Annual *.txt aersurface files tiff_debug All 1-hr and Annual *.txt aersurface files EMEW P66 Borger Refinery Plot Plan All 1-hr and Annual *.kmz Google Earth plot plan

Page 24 Attachment 1 Area Map

Note: There are no schools within 3,000 feet of the site. Attachment 2a Plot Plan Overview Attachment 2b Plot Plan North Attachment 2c Plot Plan South Attachment 3 Post Processing Using Unit Impact Multipliers (UIMs)

EPN Source ID PollutantCAS No. Averaging Emission Rate 1‐Hour Unit Predicted Total Short‐Term Percent of Next Step Period Increase Model Conc. Conc. Conc. ESL(1) Threshold Required? (lb/hr) (μg/m3/lb/hr) (μg/m3)(μg/m3)(μg/m3) (%) 88‐V1 88_V1 0.1056 2.66 0.28 F‐CCR F_CCR_1 12.1175 5.82 70.58 F_NS_1 0.9331 5.41 5.05 F‐NS F_NS_2 0.9331 5.43 5.06 F_6_1 0.0007 9.76 0.01 F‐6 F_6_2 0.0007 9.35 0.01 F_6_3 0.0007 8.81 0.01 F‐2 F_2_1 0.0231 8.55 0.20 F_53_1_1 0.0857 4.80 0.41 F‐53‐1 F_53_1_2 0.0857 4.86 0.42 F_53_1_3 0.0857 4.96 0.43 F‐SUMPCCR F_SMPCCR LPD(2) NA 1‐hour0.4000 9.46 3.79 326.82 3,500 9.34 No 66FL1CR 1064.5572 0.02 21.50 66FL2CR 1064.5572 0.02 17.82 CCR‐MSS_C 66FL3CR 1064.5572 0.02 17.47 66FL12CR 1064.5572 0.02 16.39 CCR‐MSS_U CCRMSS_1 31.1990 5.06 157.84 66FL1NS 621.8200 0.06 37.25 66FL2NS 621.8200 0.05 33.07 NS‐MSS_C 66FL3NS 621.8200 0.05 31.17 66FL12NS 621.8200 0.04 27.46 NSMSS_1 2.2780 4.77 10.86 NS‐MSS_U NSMSS_2 2.2780 5.77 13.14 F‐42 F_42_1 0.4649 6.39 2.97 HPD(3) NA 1‐hour4.24 1,000 0.42 No F‐28 F_28_1 0.2540 4.99 1.27 F‐32 F_32_1 Crude Oil(4) NA 1‐hour 1.1609 4.94 5.73 5.73 3,500 0.16 No

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS 1‐2 Attachment 3 Post Processing Using Unit Impact Multipliers (UIMs)

EPN Source ID Pollutant CAS No. Averaging Emission Rate 1‐Hour Unit Predicted Total Short‐Term Percent of Next Step Period Increase Model Conc. Conc. Conc. ESL(1) Threshold Required? (lb/hr) (μg/m3/lb/hr) (μg/m3)(μg/m3)(μg/m3) (%) 28‐H3 28_H3 0.8334 0.35 0.29 28‐H4 28_H4 0.8334 0.34 0.29 88‐H1 88_H1 1.7876 0.18 0.33 Ammonia7664‐41‐7 1‐hour 1.42 192 0.74 No FSCR_H3 0.0301 5.23 0.16 F‐SCR FSCR_H4 0.0301 5.28 0.16 FSCR_CCR 0.0301 6.64 0.20 1‐hour 0.9724 2.66 2.59 2.59 43 6.02 No 88‐V1 88_V1 Chlorine 7782‐50‐5 Annual 4.2590 0.01 0.03 0.03 2.6 1.18 No Hydrogen 1‐hour 0.0189 2.66 0.05 0.05 190 0.03 No 88‐V1 88_V1 7647‐01‐0 Chloride Annual 0.0828 0.01 5.95E‐04 5.95E‐04 7.9 0.01 No

Notes: 1. The long‐term ESLs for light petroleum distillates (LPD), heavy petroleum distillates, crude oil, and ammonia are greater than or equal to 10% of their respective short‐ term ESL; therefore, a long‐term analysis is not provided. 2. Light Petroleum Distillate includes but is not limited to gasoline (specialty fuel blendstocks) and naphtha. These light petroleum distillates have common toxicity effects and share the same short‐term (ST) and long‐term) (LT ESL as indicated below with their corresponding CAS Nos.: • Gasoline – 8006‐61‐9 (3,500 μg/m3 ST ESL, 350 μg/m3 LT ESL) • Naphtha – 92045‐53‐9 (3,500 μg/m3 ST ESL, 350 μg/m3 LT ESL) 3. Heavy Petroleum Distillate includes but is not limited to diesel and kerosene. These heavy petroleum distillates have common toxicity effects and share the same short‐ term (ST) and long‐term (LT) ESL as indicated below with their corresponding CAS Nos.: • Diesel – 68476‐34‐6 (1,000 μg/m3 ST ESL, 100 μg/m3 LT ESL) • Kerosene – 8008‐20‐6 (1,000 μg/m3 ST ESL, 100 μg/m3 LT ESL) 4. Crude Oil containing <1% benzene does not contain a CAS No.; however, in the speciated chemicals list provided by the TCEQ, it has short‐term ESL of 3,500 μg/m3 and a long‐term ESL of 350 μg/m3 under the substance name ʺcrude oil, <1% benzeneʺ.

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS 2‐2 Crude Flexibility and Modernization Project – PSD Air Quality Analysis Protocol

Prepared For Texas Commission on Environmental Quality

On behalf of Phillips 66 Borger Refinery

April 2020 Proj ec t No. P2060

TRICORD Consulting, LLC4760 Preston Rd., Ste 244-193, Frisco, TX 75034 888.900.0746

TABLE OF CONTENTS

1 Introduction ...... 1-1 1.1 Emission Sources Affected by the Project ...... 1-2 1.2 Scope of Modeling Analyses ...... 1-2 1.3 Area Map and Plot Plan ...... 1-3

2 Modeling Summary and Pollutants Evaluated ...... 2-1 2.1 Federal Prevention of Significant Deterioration Analyses ...... 2-1

3 Modeling Methodology ...... 3-1 3.1 Dispersion Model Selection ...... 3-1 3.2 Meteorological Data ...... 3-1 3.3 Building Downwash Analysis ...... 3-2 3.4 Good Engineering Practice (GEP) Stack Height Analysis ...... 3-2 3.5 Receptor Grids ...... 3-2 3.6 Dispersion Option (Urban vs. Rural) ...... 3-3 3.7 Terrain ...... 3-3 3.8 Project Source Types and Characterization ...... 3-3 3.9 Emission Rates and Source Grouping ...... 3-4 3.10 Background Monitoring ...... 3-5

4 TCEQ Submittals ...... 4-1

LIST OF FIGURES

Figure 1-1 Area Map ...... 1-10 Figure 1-2 Refinery Plot Plan - Overview ...... 1-11 Figure 1-3 Refinery Plot Plan - North ...... 1-12 Figure 1-4 Refinery Plot Plan - South ...... 1-13

LIST OF APPENDICES

Appendix A: Modeling Support Documentation Appendix B: PSD NAAQS Analysis Documentation

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1 INTRODUCTION

WRB (Wood River Borger) Refining, LP is a 50/50 partnership between the Phillips 66 Company (Phillips 66) and Cenovus Energy. WBR Refining, LP owns the Borger Refinery, which is operated by Phillips 66. Phillips 66 Borger Refinery is requesting an initial New Source Review (NSR) Permit to authorize the construction of new emission sources and the modification of existing emission sources associated with a planned project to modernize the refinery and allow for more variability in refinery crude slates. Phillips 66 Borger Refinery is applying for an initial NSR permit under the requirements of Title 30 of the Texas Administrative Code (30 TAC), Chapter 116, Subchapter B.

Phillips 66 Borger Refinery plans to construct a new Continuous Catalytic Reformer (CCR) Unit and a new Naphtha Splitter Unit, install new and more efficient crude charge heaters to replace the existing crude charge heaters, and make modifications in other selected refinery process units, including shutting down certain older process units. The physical changes will increase overall refinery efficiency and accommodate more crude slate variability. For example, the new CCR Unit will replace existing semi-regenerative reforming units, which operate with older and less efficient technology. Annual site-wide emissions for most pollutants will decrease a result of the changes.

This project is herein referred to as the “Crude Flexibility and Modernization Project.”

This Prevention of Significant Deterioration (PSD) modeling protocol is being submitted to the Texas Commission on Environmental Quality (TCEQ) concurrent with the NSR permit application, in accordance with current TCEQ policy and procedures and addresses all PSD pollutants that have National Ambient Air Quality Standard (NAAQS). The purpose of the PSD modeling protocol is to expedite the model setup while the application is being reviewed as well as to discuss the procedures of the modeling analysis for approval by the TCEQ.

Pertinent information identifying this site and project are provided in Table 1-1 below.

Table 1-1 General Information

Applicant: Phillips 66 Company Facility: Borger Refinery TCEQ Regulated Entity No.: RN102495884 TCEQ Customer No.: CN604065912 TCEQ Account No.: HW-0018-P Nearest City: Borger, TX County: Hutchinson County NSR Permit No. TBD PSD Permit No. TBD Applicant’s Modeler: TRICORD Consulting, LLC (TRICORD)

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1.1 Emission Sources Affected by the Project The Phillips 66 Borger Refinery is currently able to process up to 165 thousand barrels per day (MBPD) of crude oil. The refinery currently processes primarily heavy crude oils, which are routed to the refinery via pipeline. Phillips 66 Borger Refinery is planning to replace older refinery process equipment with new process equipment, which will allow the refinery to run more efficiently and to process a more variable crude slate.

Phillips 66 Borger Refinery plans to make the following physical changes in support of this project:

1. Install a new crude desalter train that will run in parallel with the existing crude desalters; 2. Replace three (3) existing, older crude unit heaters with two (2) new, lower-emitting crude unit heaters; 3. Construct a new, more efficient 32 MBPD CCR Unit to replace two (2) existing and less efficient semi-regenerative catalytic reforming units; 4. Construct a new Naphtha Splitter unit; 5. Construct a new Methanator in the CCR Unit battery limits to convert carbon monoxide (CO) into methane, using produced hydrogen gas; 6. Modify existing refinery process units to upgrade pumps and safety/relief valves, increase or decrease line sizes, change or replace fugitive piping components (including valves/flanges, control valve, and compressors), change/replace/add heat exchange systems, and make other ancillary changes to process unit configurations.

The emission sources associated with the Crude Flexibility and Modernization Project are mostly new; therefore, Phillips 66 Borger Refinery is requesting a new case-by-case Subchapter B NSR permit to authorize the project.

1.2 Scope of Modeling Analyses Hutchinson County is currently designated as an attainment or unclassified area for all criteria air pollutants; therefore, Phillips 66 Borger Refinery projects are not subject to nonattainment new source review (NNSR) permitting requirements.

The proposed project triggers federal PSD review for carbon monoxide (CO), nitrogen dioxide (NO2), sulfur dioxide (SO2), volatile organic compounds (VOC), Inhalable Particulates (PM10), Fine Particulates (PM2.5), and hydrogen sulfide (H2S). Modeling will be conducted for all PSD pollutants except VOC and H2S, which do not have any NAAQS to evaluate against.

In addition to PSD requirements, the project requires review for State Property Line and Health Effects standards. State Property Line and Health Effects Review evaluations are addressed in the TCEQ’s Electronic Modeling Evaluation Workbook (EMEW) and are not discussed further in this PSD modeling protocol.

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Table 1-2 lists the pollutants and averaging periods that are evaluated for the proposed project.

Table 1-2 Summary of Pollutants Evaluated

Pollutant Averaging Period Federal PSD Review? 1-hour Nitrogen Dioxides (NO2) Yes Annual 1-hour Carbon Monoxide (CO) Yes 8-hour 1-hour 3-hour Sulfur Dioxide (SO2) Yes 24-hour Annual 24-hour Coarse Particulates (PM10) Yes Annual 24-hour Fine Particulates (PM2.5) Yes Annual

Ozone (O3) 8-hour Yes

1.3 Area Map and Plot Plan The Phillips 66 Borger Refinery is located on State Spur 119 in Borger, Hutchinson County, Texas. Figure 1-1 is an area map showing the refinery location relative to nearby topographic features. This map is based on Google Earth imagery, and it indicates the ambient air boundary, and a 3,000‐foot radius and 1-mile radius from the permitted facility. There are no schools within 3,000 feet of the permitted facility. Additional information regarding how the ambient air boundary is defined is provided in Section 3.8 below.

The facility plot plan, Figures 1-2, 1-3 and 1-4, includes the north direction, and indicates the equipment associated with the facility. The area map and plot plan are included at the end of this section.

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 1-3

Figure 1-1 Area Map

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 1-10

Figure 1-2 Refinery Plot Plan - Overview

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Figure 1-3 Refinery Plot Plan - North

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Figure 1-4 Refinery Plot Plan - South

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2 MODELING SUMMARY AND POLLUTANTS EVALUATED

2.1 Federal Prevention of Significant Deterioration Analyses The purpose of PSD NAAQS analyses is to demonstrate that proposed emissions of criteria pollutants from a new source or from a modification of an existing source will not cause nor contribute to an exceedance of the NAAQS or Class II PSD Increment. Table 2-1 lists the pollutants that will be evaluated as part of the federal PSD analyses and the associated averaging periods and standards.

Table 2-1 Summary of Pollutants Evaluated

Compound Averaging Class II Significant National Class II Period SIL Monitoring Ambient Air PSD Concentrations Standards Increments (µg/m3) (µg/m3) (µg/m3) (µg/m3) 1-hour 7.5 -- 188 -- NO2 Annual 1 14 100 25 1-hour 7.8 -- 196 -- 3-hour 25 -- 1,300 512 SO2 24-hour 5 13 365 91 Annual 1 -- 80 20 24-Hour 5 10 150 30 PM10 Annual 1 -- -- 17 24-Hour 1.2 -- 35 9 PM2.5 Annual 0.3* -- 12 4 1-Hour 2,000 -- 40,000 -- CO 8-Hour 500 575 10,000 --

O3 8-hour 1.96 -- 137 -- *Note: Recent U.S. EPA guidance suggests that the SIL values to support a case-by-case permitting decision must be justified to ensure that emissions of a proposed source that have a projected impact below the SIL values are not the cause of a NAAQS violation.

The nearest Federal PSD Class I area to the Phillips 66 Borger Refinery is Wichita Mountains Wilderness in southwestern Oklahoma, located approximately 275 kilometers east-southeast of the project site. The nearest PSD Class I area is located greater than 100 kilometers from the project site; therefore, a Class I area impact analysis or any additional Air Quality Related Values (AQRVs) are not expected to be required. Preliminary Q/d value is approximately 5.

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2.1.1 Class II NAAQS Analyses The significant impact levels (SILs), also called de minimis impact levels, are values set by United States Environmental Protection Agency (U.S. EPA) and/or promulgated by state agencies with State Implementation Plans (SIP)-approved PSD programs. If an air quality impact is less than de minimis, it requires no further evaluation as it is considered an insignificant air quality impact. The terms “de minimis” and SIL may be used interchangeably throughout this document.

PSD NAAQS Step 1 is a project level model; therefore, the analysis includes project-related and contemporaneous emission sources only. Changes in emissions from all new, modified, affected and contemporaneous sources associated with the permitting action are modeled for each pollutant and averaging time, as applicable. Then, the modeled concentrations are compared to the appropriate SIL. When using five-years of meteorological data, the maximum modeled concentration (“highest first-high”) at or near the ambient air boundary is compared to the SIL.

If the sources do not make a significant impact for a pollutant of concern, the demonstration is complete. If there is a significant impact, then the significant receptors define an area of impact (AOI), and a full NAAQS analysis is required. A full NAAQS analysis is performed with all on-site sources as well as all nearby off-site sources in the AOI including up to an additional 50 kilometers (kms) plus a representative background concentration.

2.1.1.1 Class II Full NAAQS Analyses The modeled design concentrations using five -years of meteorological data for the full NAAQS analyses are described below:

• For NO2, the annual NAAQS design concentration is the highest concentration from the annual averages calculated from each of the individual years. The 1-hour NO2 NAAQS design concentration is the highest 98th percentile of the annual distribution of daily maximum 1-hour concentrations (or H8H), averaged on a receptor-by-receptor basis across the number of years modeled. • For CO NAAQS, the 1-hour and 8-hour design concentration is the highest, second high (H2H) concentration from each of the individual years that are modeled.

• For SO2, the annual NAAQS design concentration is the highest concentration from the annual averages calculated from each of the individual years. The 1-hour SO2 NAAQS design concentration is the highest 99th percentile of the annual distribution of daily maximum 1-hour concentrations (or H4H), averaged on a receptor-by-receptor basis across the number of years modeled. The 3-hour and 24-hour SO2 NAAQS design concentrations are the H2H concentrations from each of the individual years that are modeled.

• For PM10, the 24-hour NAAQS design concentration is the “n+1” highest concentration over the “n” year modeling period (high 6th highest for the five-year meteorological data set).

• For PM2.5, the 24-hour and annual design concentrations will be based on the latest U.S. EPA guidance memorandum titled “Guidance on Significant Impact Levels for Ozone and Fine Particles in the Prevention of Significant Deterioration Permitting Program”, U.S. EPA

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OAQPS, April 17, 2018 “Draft Guidance for PM2.5 Permit Modeling.” For the 24-hour NAAQS design concentration, the 98th percentile or 8th highest 24-hour average PM2.5 concentration will be determined for each of the 5 years modeled, the five values will be averaged on a receptor-by-receptor basis, and the highest 5-year average will be selected as the design concentration. For the annual average NAAQS design concentration, the annual PM2.5 concentration will be determined for each year modeled, the values will be averaged on a receptor-by-receptor basis, and the highest 5-year average value will be selected as the annual design concentration. The Modeled Emission Rates for Precursors (MERPs) will be incorporated when comparing concentrations to the NAAQS and are further discussed in Section 2.1.4.

2.1.2 PSD Pre-application Analyses The purpose of the PSD pre-application analysis is to provide an analysis of the existing ambient air quality in the area that the major source or major modification would affect. For criteria pollutants, the predicted highest concentration from the NAAQS preliminary impacts determination (PID) modeling demonstration is compared to the significant monitoring concentrations (SMCs) to determine if preconstruction monitoring is required for pollutants whose impacts are above their respective SMCs.

2.1.3 Class II PSD Increment Analyses The purpose of the PSD increment analysis is to demonstrate that emissions of applicable criteria pollutants from a new major source or major modification of an existing source will not cause or contribute to an exceedance of an increment. The PSD increment is the maximum allowable increase in concentration that is allowed to occur above a baseline concentration for a pollutant. The Class II PSD Increments are maximum allowable increases in concentrations that may be exceeded once per year at each site, except for the annual increment which may not be exceeded at all. Therefore, for short-term averages the H2H short-term average concentration for any year is the design concentration, and for annual averages the design concentration is the highest modeled annual average.

2.1.4 Modeled Emission Rates for Precursors (MERPs) Pursuant to the U.S. EPA guidance document “Guidance on the Development of MERPs as a Tier 1 Demonstration Tool for Ozone and PM2.5 under the PSD Permitting Program” dated April 30, 2019, MERPs will be utilized as a Tier 1 demonstration tool for ozone and PM2.5 if the emission rates of those constituents are above the applicable significant emission rates. If the required ozone and PM2.5 demonstrations are satisfied with the worst-case default MERP values listed in Table Q-1 of Appendix Q and Table R-1 of Appendix R, respectively of the TCEQ Air Quality Modeling Guidelines (AQMG) MERPs guidance (and copied below in Table 2-2), the default values will be utilized. Otherwise, further refinements will be evaluated and discussed with TCEQ.

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 2-3

Table 2-2 Worst-case MERP Values for Texas PSD Applications

Precursor 8-Hour Ozone 24-hour PM2.5 Annual PM2.5 (tpy) (tpy) (tpy)

NOX 250 2,649 10,397 SO2 -- 359 1,820 VOC 2,604 -- --

For the evaluation of the project with respect to ozone, the sum of the project’s proposed NOX emissions increase in tons per year (tpy) divided by the NOX MERP (tpy) for ozone and the project’s proposed VOC emissions increase (tpy) divided by the VOC MERP (tpy) is compared to the 8-hour ozone SIL of 1 ppb. If the sum, as shown in the equation below, is less than one, the project is deemed to not have a significant impact on ambient 8-hour ozone levels, and there is no need to conduct a cumulative analysis for ozone.

Table 2-3 Ozone MERPs Demonstration

Averaging NOX Project NOX MERP VOC Project VOC MERP Total Is Total < Period Emissions Emissions 1? (tpy) (tpy) (tpy) (tpy) 8-hour 52.72 250 92.93 2,604 0.25 Yes Ozone

+ < 1

𝑁𝑁𝑁𝑁𝑋𝑋 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑉𝑉𝑉𝑉𝑉𝑉 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑁𝑁𝑁𝑁𝑋𝑋 𝑀𝑀𝑀𝑀𝑀𝑀52𝑀𝑀.72 92.93𝑉𝑉𝑉𝑉𝑉𝑉 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 + = 0.25 250 2604

The NOX and VOC project emissions are the proposed emissions for the new sources part of this permitting action. The affected and contemporaneous sources project emissions are not included in the Ozone MERPs demonstration since these sources are existing and would already be included as part of the background. Since the sum from the above equation is less than one, the project is deemed to not have a significant impact on ambient 8-hour ozone levels.

For the evaluation of the project with respect to PM2.5, the sum of the maximum primary PM2.5 modeled concentration (µg/m3) as described below divided by the applicable PM2.5 SIL (discussed in previous section, µg/m3), the SO2 emissions increase (tpy) divided by the SO2 MERP (tpy), and the NOX emissions increase (tpy) divided by the NOX MERP (tpy) for PM2.5 are compared to 1. The applicable equation is shown below, and the max PM2.5 Modeled Concentration is the highest value (annual or H1H 24-hour concentration averaged over five years) of direct PM2.5 emission increases modeled using AERMOD. If the sums of the equation for both the 24-hour and annual PM2.5 averaging periods are less than 1, the project will be deemed to not have a significant impact on ambient PM2.5 concentrations, and there is no need to conduct a cumulative analysis for PM2.5.

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Table 2-4 PM2.5 24-hour and Annual MERPs Demonstration

Averaging Max PM2.5 PM2.5 NOX Project NOX SO2 Project SO2 Total Is Period Modeled Conc. SIL Emissions MERP Emissions MERP Total (µg/m3) (µg/m3) (tpy) (tpy) (tpy) (tpy) < 1? 24-Hour TBD 1.2 52.72 2,649 45.01 359 TBD TBD PM2.5 Annual TBD 0.3 52.72 10,397 45.01 1,820 TBD TBD PM2.5

. + + < 1 . 𝑀𝑀𝑀𝑀𝑀𝑀 𝑃𝑃𝑃𝑃2 5 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 𝑆𝑆𝑆𝑆2 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑁𝑁𝑁𝑁𝑋𝑋 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑃𝑃𝑃𝑃2 5 𝑆𝑆𝑆𝑆𝑆𝑆 𝑆𝑆𝑆𝑆2 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 𝑁𝑁𝑁𝑁𝑋𝑋 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 The modeling analysis for PM2.5 is still in the preliminary stages of evaluation; however, if the project indicates the concentrations are below the SILs, the secondary formation of PM2.5 will be evaluated as described above to determine if the project is deemed to have a significant impact on ambient PM2.5 levels. If the project indicates an exceedance of a PM2.5 SIL, a cumulative analysis is required. The cumulative analysis for a NAAQS demonstration includes contributions from background concentrations, modeling of direct PM2.5 emissions and impacts associated with secondary PM2.5 precursor emissions. The following equation is used to determine if the concentration meets PM2.5 NAAQS.

. = . + + +

𝑆𝑆𝑆𝑆2 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑁𝑁𝑁𝑁𝑋𝑋 𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸𝐸 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶𝐶 𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵𝐵 𝑐𝑐𝑐𝑐𝑐𝑐𝑐𝑐 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑉 � � ∗ 𝑆𝑆𝑆𝑆𝑆𝑆 𝑆𝑆𝑆𝑆2 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 𝑁𝑁𝑁𝑁𝑋𝑋 𝑀𝑀𝑀𝑀𝑀𝑀𝑀𝑀 The NOX and SO2 project emissions are the proposed emissions for the new sources part of this permitting action. The affected and contemporaneous sources project emissions are not included in the PM2.5 MERPs demonstration since these sources are existing and would already be included as part of the background. As the PM2.5 modeling is completed, the modeled value and representative background will be included in the MERPs demonstration prior to submittal to the TCEQ. In addition, if less conservative MERPs values are used, justification for these values will also be included in the final modeling report.

2.1.5 Additional Impacts Analyses The proposed facility impacts on growth, soils, vegetation, and visibility will be discussed in the final modeling report. The modeling results will be used to make a judgment on the soils and vegetation impacts. The NAAQS secondary standards were set by the U.S EPA to provide protection to most soils and vegetation from the adverse effects of air pollution. If the model results demonstrate that the impacts from all constituents are less than the NAAQS secondary standards, it will be concluded that the project will not have an adverse effect on soils and vegetation.

The facility is greater than 100 km from the nearest Class I area; therefore, no PSD Class I visibility impairment analysis should be required.

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3 MODELING METHODOLOGY

3.1 Dispersion Model Selection This analysis uses the American Meteorological Society / Environmental Protection Agency Regulatory Model (AERMOD) Version 19191. The AERMOD model calculates off-property, ground-level concentrations for both short-term (1-Hour, 3-Hour, 8-Hour, and 24-Hour) and annual averaging periods. A commercial version of the AERMOD model (BEEST for Windows) is used in these analyses.

3.2 Meteorological Data The Phillips 66 Borger Refinery is located in Hutchinson County. For Hutchinson County, TCEQ recommends surface observations from the Borger Hutchinson County Airport (Station ID No. 3024) and upper air station data from the Amarillo National Weather Service (NWS) Station (NWS Station ID 23047). Based upon TCEQ information, the profile base elevation for the Borger Hutchinson Co. Airport is 930.9 meters above sea level.

TCEQ provides pre-processed meteorological data to the public. Pollutants and averaging periods subject to Major NAAQS use five year (2011-2015) of TCEQ pre-processed meteorological data.

TCEQ developed three separate AERMOD-ready meteorological data sets for each county in the state. The different data sets correspond to three categories of surface roughness length: • Category 1 – LOW

o Appropriate for areas with surface roughness lengths of 0.001 m - 0.1 m • Category 2 – MEDIUM

o Appropriate for areas with surface roughness lengths of 0.1 m – 0.7 m • Category 3 – HIGH

o Appropriate for areas with surface roughness lengths of 0.7 m - 1.5 m The U.S. EPA’s AERSURFACE (Version 13016) preprocessor was used to determine which land use category is appropriate. The AERSURFACE results are summarized as follows:

** Generated by AERSURFACE, dated 13016 ** Generated from "C:\aersurface\data\texas_north.tif" ** Center UTM Easting (meters): 285881.2 ** Center UTM Northing (meters): 3952848.1 ** UTM Zone: 14 Datum: NAD83 ** Study radius (km) for surface roughness: 1.0 ** Airport? N, Continuous snow cover? N ** Surface moisture? Average, Arid region? N ** Month/Season assignments? Default ** Late autumn after frost and harvest, or winter with no snow: 12 1 2

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** Winter with continuous snow on the ground: 0 ** Transitional spring (partial green coverage, short annuals): 3 4 5 ** Midsummer with lush vegetation: 6 7 8 ** Autumn with unharvested cropland: 9 10 11

FREQ_SECT ANNUAL 1 SECTOR 1 0 360 ** Sect Alb Bo Zo SITE_CHAR 1 1 0.18 1.03 0.326

The resulting surface roughness length is 0.326; therefore, Category 2 - Medium meteorological data will be used in these analyses.

3.3 Building Downwash Analysis The analysis includes PRIME building downwash effects. For AERMOD, the analysis uses Building Profile Input Program for Prime (BPIP PRIME) (Version 04274) to assess wind direction-specific downwash dimensions from downwash structures.

3.4 Good Engineering Practice (GEP) Stack Height Analysis The good engineering practice (GEP) regulations require emission sources to be included at the lesser of physical stack height or GEP formula stack height. The GEP formula stack height is expressed as the greater of 65 meters or a “site-specific” value based upon surrounding downwash structures. The analysis will not include any stack heights greater than 65 meters.

3.5 Receptor Grids The analysis uses a Cartesian receptor grid that extends at least 5 kilometers in all directions from the ambient air boundary. The spacing for the initial receptor grid varies with distance from the facility as follows: • Tight receptors, spaced 25 meters apart, along the ambient air boundary line and extending out to a distance of up to 300 meters or until concentrations are steadily decreasing. • Fine receptors, spaced 100 meters apart, extending from the tight receptors out to a distance of at least 1,000 meters. • Medium receptors, spaced 500 meters apart, extending from the fine receptors out to a distance of at least 5,000 meters. • Coarse receptors, spaced 1,000 meters apart, extend from the medium receptors out to a distance of at least 10 km or a distance that covers the entire area of de minimis impact. • For more refined PSD analyses (i.e. Full Impacts modeling), the modeled receptors will be reduced to the locations where the predicted concentrations are greater than the SIL in the preliminary impacts analyses.

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3.6 Dispersion Option (Urban vs. Rural) A land-use analysis was performed using aerial imagery and general knowledge of the terrain. The result of the analysis clearly indicates rural land type and absence of large “heat islands.” Therefore, “No Urban Area” is selected for the modeling analysis. A map depicting the location of the facility and surrounding area is presented in Figure 1-1.

3.7 Terrain The refinery is located in western Texas. The surrounding terrain may be described as generally flat with minor elevation changes. The analysis will use the “elevated terrain” option. For emission sources, downwash structures, and receptors the elevations above sea level were obtained from the National Elevation Dataset (NED) files. To extract heights from the NED files, the analysis used the AERMAP program (Version 18081) and the North American Datum (NAD) 83 coordinate system.

3.8 Ambient Air Boundary The ambient air boundary is provided in Figure 1-1 and is the basis for developing the receptor grid in Section 3.5. The ambient air boundary is developed based on fencing and surveillance either by video monitoring, routine security patrols or other measures to deter public access, in accordance with the U.S. EPA guidance memo “Revised Policy On Exclusions from ‘Ambient Air’”, November 2018. The entire Phillips 66 Borger Refinery property is fenced. Phillips 66 Borger Refinery also owns part of the road that leads up to the refinery security gate and since this part of the road is unlikely to be fenced, no trespassing and other posted signage will be considered in order to deter public access to refinery property, if necessary.

The refinery also leases land to several other companies. Phillips 66 Borger Refinery controls and maintains all access in and out of their property. According to the U.S. EPA guidance memo from “Interpretation of “Ambient Air” In Situations Involving Leased Land Under the Regulations for Prevention of Significant Deterioration (PSD)”, June 2007, when two or more companies operate separate sources on property owned by one company and leased in part to the other, and the lessor retains control over public access to the entire property, the air over the entire property (including the leased portion) is not ambient air to the lessor. Therefore, since Phillips 66 Borger Refinery maintains control over access to their property and implements measures to deter public access, the land that is leased is not considered to be ambient air.

3.9 Project Source Types and Characterization Sections 1.1 describes the emission sources to be affected as a part of this project. Sections 3.9.1 through 3.9.4 below describe the source characterization for the proposed project. The emission sources in this analysis are modeled as stack (“true point”) sources, pseudo-point sources, special point sources (flares), loading, and cooling towers.

3.9.1 Point and Pseudo-point Sources The stack parameters for point sources were developed from operational data, vendor information, emissions factors and/or process knowledge. Pseudo-point sources were modeled with the default

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 3-3

parameters for worst-case source impacts. The source locations were determined from the facility plot plans or imported from Google Earth.

3.9.2 Special Point Sources (Flares) The actual stack heights of the flare tip and the effective flare diameters are calculated using the formula in Appendix K of the AQMG are used in the modeling. Flare effective diameters are separately evaluated for normal production and planned maintenance, startup, and shutdown (MSS), as applicable. Calculations for the effective flare diameters are provided in Appendix A.

3.9.3 Sulfur Loading The Sulfur Loading source, which reflects activities associated with the loading railcars, is defined within the boundaries of the railcars. The sulfur loading is modeled as an area source and is rectangular in shape. The analysis conservatively assumes the emissions disperse in two dimensions with little to no plume rise at an average release height of the loading activities.

3.9.4 Cooling Towers The cooling towers were modeled as point sources, using the following methodology: • Each cooling tower has multiple cells. All tower cells are identical in size and volumetric flow and are lined up. Each of the cooling towers was represented as a single point source located at the center of the line of cells. For each pollutant, the entire emission rate for all cells was assigned to the representative “stack.” This approach is expected to result in higher predicted impacts than an approach representing each cell as a separate point source, as the emissions are collocated. The center point of each tower is considered a representative location, as the theoretical “worst-case” location greatly depends on the wind direction and overlay of the tower cell plume with plumes from other sources of each of the modeled pollutants within the plant. • Each stack was modeled with the temperature and gas exit velocity appropriate for the cooling tower it represents.

3.10 Emission Rates and Source Grouping For the preliminary impact assessment of project and contemporaneous sources increases and decreases, the modeled annual emission rates will equal the proposed PTE minus current actual emissions, which will be calculated based on current U.S. EPA guidance. The modeled lb/hr emission rates for the existing modified and affected sources will equal the proposed PTE minus the highest lb/hr actual emission rate over the appropriate averaging period that has occurred in the period two years prior to the start of the modeling (January 2017 – December 2018) based on the historical records. For any full impacts analyses, maximum allowable emission rates will be modeled.

The MSS emissions from flaring part of this project can occur from any of the four (4) onsite flares. Source Groups may be utilized for determining the worst-case flare assuming all requested emissions are releasing from only a single flare.

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 3-4

3.11 Background Monitoring

To determine the background concentrations of CO, NO2, SO2, PM10, PM2.5, and ozone that would be representative of the area surrounding the facility, air quality data from multiple air monitors will be collected to estimate the background concentrations. For nearby air monitors, the TCEQ database will be accessed to get short-term and annual air quality data. For air monitors outside of the state of Texas, the U.S. EPA AirData database will be used to collect daily and annual air quality data. The background concentrations will be calculated based on the NAAQS design value criteria with some conservative assumptions. The air quality data will be acquired for the most recent available three-year consecutive period. The proposed air monitors in Table 3-1 were selected based on their proximity to the facility and their availability of the most recent air quality data.

The NAAQS design values for 1-hour and 8-hour CO concentrations are not to be exceeded more than once per year. For both averaging periods, the maximum concentration will be determined for each year. From both sets, the second highest concentration will be selected as the representative background value for 1-hour and 8-hour CO.

The NAAQS design value for 1-hour NO2 concentration is based on the three-year average of the 98th percentile of the maximum 1-hour concentrations. The NAAQS design value for annual NO2 concentration is never to be exceeded. For the 1-hour averaging period, the 98th percentile concentration will be calculated from the daily maximum 1-hour concentrations for each year. The calculated concentrations will then be averaged to get the representative background value for 1-hour NO2. For the annual averaging period, the 1-hour concentrations will be averaged for each year. The highest average value will be selected as the representative background value for annual NO2.

The NAAQS design value for 1-hour SO2 concentration is based on the three-year average of the 99th percentile of the maximum 1-hour concentrations. The NAAQS design value for the 3-hour SO2 concentration is not to be exceeded more than once per year. For the 1-hour averaging period, the 99th percentile concentration will be calculated from the daily maximum 1-hour concentrations for each year. The calculated concentrations will then be averaged to get the representative background value for 1-hour SO2. For the 3-hour and 24-hour averaging periods, the maximum concentration will be determined for the most recent complete year. The second highest concentration will then be selected as the representative background value for 3-hour and 24-hour SO2. For the annual averaging period, the 1-hour concentrations will be averaged for the most recent complete year.

The NAAQS design value for 24-hour PM10 concentration is not to be exceeded more than once per year. For the 24-hour averaging period, the maximum concentration will be determined for each year. The second highest concentration from the three-year set will be selected as the representative background value for 24-hour PM10.

The NAAQS design value for the annual PM2.5 concentration is based on the three-year average of the annual weighted mean concentrations. For the 24-hour averaging period, the 98th percentile concentration will be calculated from the daily concentrations for each year. The calculated concentrations will then be averaged to get the representative background value for 24-hour PM2.5.

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 3-5

For the annual averaging period, the 1-hour concentrations will be averaged for each year. These values will then be averaged to get the representative background value for annual PM2.5.

Table 3-1 lists the proposed ambient monitors to represent the ambient air surrounding the Phillips 66 Borger Refinery for use in comparison to the NAAQS if cumulative impact modeling is required.

Table 3-1 Background Monitoring Stations

Distance from Compounds Monitor Number Location County Site (km) CO 40-109-0097 Oklahoma City, OK Oklahoma 345 NO2 40-109-0097 Oklahoma City, OK Oklahoma 345 SO2 48-375-1025 Amarillo, TX Potter 64 PM2.5 40-109-1037 Oklahoma City, OK Oklahoma 352 PM10 40-109-0035 Oklahoma City, OK Oklahoma 348 Ozone TBD

These monitors were selected based primarily upon data availability, distance, surrounding land use, and monitor location type. These data were identified/obtained from TCEQ’s GeoTAM System and US EPA’s AirData System. A refined PSD NAAQS analysis will include calculated background concentration values and a data completion analysis. Phillips 66 Borger Refinery will work with the TCEQ Air Dispersion Modeling Team (ADMT) to determine an appropriate monitor selection for the ozone background concentration, if necessary.

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 3-6

4 TCEQ SUBMITTALS

Supplemental general modeling information (e.g., summary tables for point and volume source locations, parameters, and emission rates; and summary tables for downwash structures) will be included as appendices to the Air Quality Analysis (AQA).

Electronic copies of all modeling, downwash, etc. input and output files were submitted with the AQA electronically. The files are organized in subdirectories. The subdirectories structure is self- explanatory for ease of locating the files. Also included is an electronic copy of the AQA in Adobe Acrobat (PDF) format, the meteorological data files, NED (terrain) file, and aerial photos.

The following table describes the file extensions applicable for the files that will be included on the TCEQ FTP.

Table 4-1 Modeling File Extensions

File Extension Contents

BST Beeline BEEST Files

DTA BEESTWIN actual input files

RUN BEESTWIN run log files

SUM BEESTWIN summary of the results files

LST BEESTWIN output files

PRW BEESTWIN GEP/BPIP-PRIME input file

PIP BEESTWIN BPIP-PRIME actual input files

BAK BEESTWIN GEP/BPIP-PRIME code file

TAB BEESTWIN BPIP-PRIME summary of input files

SUM BEESTWIN BPIP-PRIME output detailed summary files

SO BEESTWIN BPIP-PRIME output files (for insertion in the model)

BND BEESTWIN boundary files

GRF BEESTWIN output plot files

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 4-1

APPENDIX A: MODELING SUPPORT DOCUMENTATION

The following tables are included in this appendix: • Table A-1: Rectangular and Polygonal Structure Locations and Parameters; • Table A-2: Circular Downwash Structure Locations and Parameters; • Table A-3: Flare Effective Diameter Calculations; and • Figure A-1: Receptor Plot for Preliminary Impacts Determination.

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Table A‐1 Rectangular and Polygonal Structure Locations and Parameters Phillips 66 Borgery Refinery PSD Permit Air Quality Analysis

Building Number Tier Base Tier HeightNumber of Corner 1 Corner 1 Corner 2 Corner 2 Corner 3 Corner 3 Corner 4 Corner 4 Corner 5 Corner 5 Corner 6 Corner 6 Corner 7 Corner 7 Corner 8 Corner 8 Name of Tiers Number Elevation Corners East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) 1 1 1 928.05 3.05 6 285,914.42 3,953,156.28 285,918.69 3,953,156.23 285,918.74 3,953,154.28 285,924.40 3,953,154.28 285,924.51 3,953,146.77 285,914.42 3,953,146.70 2 1 1 928.15 3.05 4 285,931.66 3,953,157.21 285,940.61 3,953,157.16 285,940.71 3,953,150.16 285,931.66 3,953,150.21 3 1 1 927.59 9.141 4 285,964.69 3,953,173.00 285,993.29 3,953,172.95 285,993.45 3,953,154.95 285,964.69 3,953,154.99 4 1 1 927.9 6.099 4 285,951.11 3,953,134.11 286,002.14 3,953,134.06 286,002.25 3,953,122.38 285,951.11 3,953,122.48 10 1 1 929.44 21.339 4 285,974.24 3,952,785.30 285,993.76 3,952,785.30 285,994.06 3,952,777.61 285,974.24 3,952,777.61 16 1 1 934.91 9.141 4 285,711.92 3,952,631.62 285,749.31 3,952,631.62 285,749.31 3,952,597.15 285,711.65 3,952,597.15 20 1 1 926.53 4.569 4 286,163.78 3,952,948.42 286,174.78 3,952,948.42 286,174.78 3,952,924.42 286,163.78 3,952,924.42 21 1 1 921.78 9.141 4 286,176.77 3,953,083.36 286,195.46 3,953,083.23 286,195.46 3,953,027.42 286,176.77 3,953,027.36 22 1 1 929.54 13.719 4 285,984.12 3,952,764.49 286,002.12 3,952,764.49 286,002.12 3,952,732.49 285,984.12 3,952,732.49 104 1 1 923.58 7.62 4 285,399.68 3,953,066.44 285,399.68 3,953,078.82 285,438.95 3,953,078.82 285,438.95 3,953,066.44 111‐1 1 1 917.3 3.051 8 286,356.72 3,953,703.36 286,356.36 3,953,715.17 286,373.76 3,953,715.10 286,373.76 3,953,712.32 286,381.96 3,953,712.42 286,381.96 3,953,708.17 286,387.17 3,953,708.17 286,387.17 3,953,703.17 116 1 1 925.79 9.141 5 286,368.44 3,953,448.80 286,368.71 3,953,454.64 286,389.32 3,953,454.37 286,389.05 3,953,447.96 286,368.94 3,953,448.30 123 1 1 929.9 4.569 4 286,513.75 3,953,240.28 286,551.84 3,953,309.28 286,568.25 3,953,301.53 286,530.81 3,953,232.53 124 1 1 929.6 4.569 10 286,490.46 3,953,331.65 286,502.74 3,953,354.40 286,507.86 3,953,351.65 286,514.33 3,953,363.90 286,528.74 3,953,356.90 286,512.33 3,953,326.90 286,507.02 3,953,330.40 286,501.89 3,953,321.90 125 1 1 929.41 6.099 4 286,475.61 3,953,288.40 286,490.18 3,953,313.65 286,500.75 3,953,308.28 286,486.87 3,953,282.02 126 1 1 929.46 3.051 4 286,434.66 3,953,206.24 286,461.60 3,953,256.93 286,474.44 3,953,250.75 286,446.62 3,953,199.62 127 1 1 929.72 6.099 4 286,469.98 3,953,196.00 286,495.64 3,953,243.00 286,523.45 3,953,228.50 286,499.11 3,953,181.50 131 1 1 920.4 12.189 4 286,264.95 3,953,347.38 286,272.62 3,953,347.38 286,272.54 3,953,340.53 286,265.03 3,953,340.53 134 1 1 924.14 3.051 4 286,287.62 3,953,233.91 286,287.62 3,953,221.15 286,277.04 3,953,221.37 286,276.91 3,953,234.01 136 1 1 923.11 3.051 4 286,263.34 3,953,233.40 286,276.28 3,953,233.40 286,276.18 3,953,214.14 286,263.34 3,953,214.14 140 1 1 920.16 6.099 4 286,193.04 3,953,201.97 286,201.25 3,953,201.89 286,201.36 3,953,186.28 286,192.99 3,953,186.50 142 1 1 922.92 6.099 4 286,168.55 3,953,021.19 286,184.49 3,953,021.19 286,184.25 3,953,000.26 286,169.03 3,953,000.26 148 1 1 924.49 6.099 4 286,098.83 3,952,977.85 286,098.83 3,952,989.03 286,107.15 3,952,989.03 286,107.15 3,952,977.85 151 1 1 929.25 9.141 4 286,218.32 3,952,785.60 286,234.51 3,952,785.60 286,234.82 3,952,763.59 286,218.53 3,952,763.80 153 1 1 929.56 7.62 4 286,145.79 3,952,704.86 286,145.79 3,952,677.65 286,134.55 3,952,678.24 286,133.96 3,952,704.86 154 1 1 929.53 4.569 4 286,062.69 3,952,708.04 286,082.19 3,952,708.29 286,081.63 3,952,663.79 286,062.69 3,952,664.54 160 1 1 928.13 3.051 4 285,919.52 3,952,835.48 285,945.27 3,952,834.73 285,944.95 3,952,824.35 285,919.81 3,952,824.35 163 1 1 926.25 9.141 4 285,935.06 3,952,970.39 285,946.62 3,952,970.39 285,945.47 3,952,943.64 285,933.94 3,952,943.89 172 1 1 926.64 10.671 5 285,904.03 3,952,943.28 285,904.03 3,952,980.28 285,921.25 3,952,980.28 285,920.68 3,952,944.03 285,903.65 3,952,943.78 178 1 1 929.85 4.569 4 285,964.64 3,952,499.51 286,035.11 3,952,497.51 286,034.36 3,952,468.51 285,964.26 3,952,469.76 179 1 1 933.49 3.051 16 285,959.84 3,952,312.88 285,939.19 3,952,313.60 285,940.03 3,952,392.60 285,917.28 3,952,392.55 285,917.04 3,952,411.10 285,907.76 3,952,411.58 285,907.76 3,952,456.05 285,984.10 3,952,454.38 181 1 1 929.82 10.671 4 285,933.96 3,952,695.24 285,944.77 3,952,695.24 285,944.89 3,952,678.90 285,933.86 3,952,678.90 182 1 1 931.37 4.57 4 285,815.27 3,952,778.14 285,835.70 3,952,777.89 285,835.70 3,952,766.64 285,814.95 3,952,767.64 183 1 1 932.54 7.01 4 285,862.26 3,952,656.63 285,909.94 3,952,656.63 285,909.94 3,952,645.63 285,862.26 3,952,645.63 184 1 1 933.64 3.05 4 285,859.05 3,952,570.74 285,874.21 3,952,570.98 285,874.21 3,952,557.78 285,859.05 3,952,557.78 185 1 1 935.62 7.62 4 285,779.80 3,952,516.14 285,792.90 3,952,516.14 285,792.78 3,952,507.12 285,779.80 3,952,507.12 512 1 1 934.84 4.57 4 285,819.93 3,952,430.06 285,838.34 3,952,430.06 285,834.87 3,952,312.31 285,817.96 3,952,313.81 1011B 1 1 932.32 3.05 4 285,771.72 3,952,759.64 285,790.00 3,952,760.14 285,790.00 3,952,744.64 285,771.72 3,952,744.89 1022 1 1 931.08 12.19 4 285,590.96 3,952,710.94 285,590.96 3,952,729.21 285,556.55 3,952,729.21 285,556.55 3,952,711.53 1024 1 1 926.75 3.05 4 285,570.36 3,952,794.53 285,582.15 3,952,794.53 285,582.15 3,952,781.45 285,570.48 3,952,781.45 1064B 1 1 931.73 3.05 4 285,684.38 3,952,786.57 285,709.60 3,952,786.57 285,709.67 3,952,774.67 285,684.88 3,952,774.67 1165B 1 1 924.37 6.1 4 285,487.00 3,952,836.67 285,499.27 3,952,836.67 285,499.27 3,952,819.44 285,487.00 3,952,819.44 1201 1 1 922.31 6.1 4 285,380.47 3,952,781.18 285,368.28 3,952,780.93 285,368.28 3,952,786.68 285,380.46 3,952,787.07 1203 1 1 922.01 3.05 4 285,429.87 3,952,821.92 285,405.70 3,952,821.92 285,405.61 3,952,814.52 285,429.87 3,952,814.52 1551 1 1 922.18 4.57 4 285,293.21 3,952,983.45 285,311.13 3,952,983.45 285,311.13 3,952,966.70 285,293.21 3,952,966.55 2510‐1 1 1 925.23 10.67 4 285,514.04 3,952,961.73 285,528.34 3,952,961.73 285,528.34 3,952,976.17 285,513.91 3,952,976.17 2511 1 1 932.48 10.67 32 285,713.18 3,952,808.34 285,712.89 3,952,811.30 285,712.03 3,952,814.14 285,710.62 3,952,816.77 285,708.74 3,952,819.06 285,706.44 3,952,820.95 285,703.82 3,952,822.35 285,700.97 3,952,823.22 2551 1 1 925.25 10.67 4 285,597.50 3,952,962.71 285,597.50 3,952,972.96 285,609.10 3,952,973.02 285,609.10 3,952,962.71 2552‐1 1 1 925.02 9.14 4 285,610.56 3,952,991.46 285,598.18 3,952,991.46 285,598.18 3,952,979.99 285,610.61 3,952,979.80 2553‐1 1 1 924.98 3.66 4 285,767.65 3,953,060.94 285,761.96 3,953,060.94 285,761.97 3,953,065.14 285,767.65 3,953,065.14 2554 1 1 926.35 4.57 4 285,917.59 3,952,931.52 285,932.43 3,952,931.52 285,932.43 3,952,917.59 285,917.59 3,952,917.59 2571B 1 1 926.68 3.05 4 285,888.03 3,952,954.71 285,894.55 3,952,954.71 285,894.77 3,952,944.60 285,888.03 3,952,944.60

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 1 of 8 Table A‐1 Rectangular and Polygonal Structure Locations and Parameters Phillips 66 Borgery Refinery PSD Permit Air Quality Analysis

Building Number Tier Base Tier Height Number of Corner 9 Corner 9 Corner 10 Corner 10 Corner 11 Corner 11 Corner 12 Corner 12 Corner 13 Corner 13 Corner 14 Corner 14 Corner 15 Corner 15 Corner 16 Corner 16 Name of Tiers Number Elevation Corners East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) 1 1 1 928.05 3.05 6 2 1 1 928.15 3.05 4 3 1 1 927.59 9.141 4 4 1 1 927.9 6.099 4 10 1 1 929.44 21.339 4 16 1 1 934.91 9.141 4 20 1 1 926.53 4.569 4 21 1 1 921.78 9.141 4 22 1 1 929.54 13.719 4 104 1 1 923.58 7.62 4 111‐1 1 1 917.3 3.051 8 116 1 1 925.79 9.141 5 123 1 1 929.9 4.569 4 124 1 1 929.6 4.569 10 286,495.77 3,953,325.15 286,497.77 3,953,328.90 125 1 1 929.41 6.099 4 126 1 1 929.46 3.051 4 127 1 1 929.72 6.099 4 131 1 1 920.4 12.189 4 134 1 1 924.14 3.051 4 136 1 1 923.11 3.051 4 140 1 1 920.16 6.099 4 142 1 1 922.92 6.099 4 148 1 1 924.49 6.099 4 151 1 1 929.25 9.141 4 153 1 1 929.56 7.62 4 154 1 1 929.53 4.569 4 160 1 1 928.13 3.051 4 163 1 1 926.25 9.141 4 172 1 1 926.64 10.671 5 178 1 1 929.85 4.569 4 179 1 1 933.49 3.051 16 285,984.34 3,952,410.39 285,970.78 3,952,410.62 285,970.78 3,952,389.70 285,962.22 3,952,389.70 285,961.98 3,952,350.70 285,981.48 3,952,351.17 285,981.01 3,952,341.18 285,960.08 3,952,341.18 181 1 1 929.82 10.671 4 182 1 1 931.37 4.57 4 183 1 1 932.54 7.01 4 184 1 1 933.64 3.05 4 185 1 1 935.62 7.62 4 512 1 1 934.84 4.57 4 1011B 1 1 932.32 3.05 4 1022 1 1 931.08 12.19 4 1024 1 1 926.75 3.05 4 1064B 1 1 931.73 3.05 4 1165B 1 1 924.37 6.1 4 1201 1 1 922.31 6.1 4 1203 1 1 922.01 3.05 4 1551 1 1 922.18 4.57 4 2510‐1 1 1 925.23 10.67 4 2511 1 1 932.48 10.67 32 285,698.01 3,952,823.51 285,695.05 3,952,823.22 285,692.20 3,952,822.35 285,689.58 3,952,820.95 285,687.28 3,952,819.06 285,685.40 3,952,816.77 285,683.99 3,952,814.14 285,683.13 3,952,811.30 2551 1 1 925.25 10.67 4 2552‐1 1 1 925.02 9.14 4 2553‐1 1 1 924.98 3.66 4 2554 1 1 926.35 4.57 4 2571B 1 1 926.68 3.05 4

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 2 of 8 Table A‐1 Rectangular and Polygonal Structure Locations and Parameters Phillips 66 Borgery Refinery PSD Permit Air Quality Analysis

Building Number Tier Base Tier Height Number of Corner 17 Corner 17 Corner 18 Corner 18 Corner 19 Corner 19 Corner 20 Corner 20 Corner 21 Corner 21 Corner 22 Corner 22 Corner 23 Corner 23 Corner 24 Corner 24 Name of Tiers Number Elevation Corners East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) 1 1 1 928.05 3.05 6 2 1 1 928.15 3.05 4 3 1 1 927.59 9.141 4 4 1 1 927.9 6.099 4 10 1 1 929.44 21.339 4 16 1 1 934.91 9.141 4 20 1 1 926.53 4.569 4 21 1 1 921.78 9.141 4 22 1 1 929.54 13.719 4 104 1 1 923.58 7.62 4 111‐1 1 1 917.3 3.051 8 116 1 1 925.79 9.141 5 123 1 1 929.9 4.569 4 124 1 1 929.6 4.569 10 125 1 1 929.41 6.099 4 126 1 1 929.46 3.051 4 127 1 1 929.72 6.099 4 131 1 1 920.4 12.189 4 134 1 1 924.14 3.051 4 136 1 1 923.11 3.051 4 140 1 1 920.16 6.099 4 142 1 1 922.92 6.099 4 148 1 1 924.49 6.099 4 151 1 1 929.25 9.141 4 153 1 1 929.56 7.62 4 154 1 1 929.53 4.569 4 160 1 1 928.13 3.051 4 163 1 1 926.25 9.141 4 172 1 1 926.64 10.671 5 178 1 1 929.85 4.569 4 179 1 1 933.49 3.051 16 181 1 1 929.82 10.671 4 182 1 1 931.37 4.57 4 183 1 1 932.54 7.01 4 184 1 1 933.64 3.05 4 185 1 1 935.62 7.62 4 512 1 1 934.84 4.57 4 1011B 1 1 932.32 3.05 4 1022 1 1 931.08 12.19 4 1024 1 1 926.75 3.05 4 1064B 1 1 931.73 3.05 4 1165B 1 1 924.37 6.1 4 1201 1 1 922.31 6.1 4 1203 1 1 922.01 3.05 4 1551 1 1 922.18 4.57 4 2510‐1 1 1 925.23 10.67 4 2511 1 1 932.48 10.67 32 285,682.84 3,952,808.34 285,683.13 3,952,805.38 285,683.99 3,952,802.53 285,685.40 3,952,799.91 285,687.28 3,952,797.61 285,689.58 3,952,795.72 285,692.20 3,952,794.32 285,695.05 3,952,793.46 2551 1 1 925.25 10.67 4 2552‐1 1 1 925.02 9.14 4 2553‐1 1 1 924.98 3.66 4 2554 1 1 926.35 4.57 4 2571B 1 1 926.68 3.05 4

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 3 of 8 Table A‐1 Rectangular and Polygonal Structure Locations and Parameters Phillips 66 Borgery Refinery PSD Permit Air Quality Analysis

Building Number Tier Base Tier Height Number of Corner 25 Corner 25 Corner 26 Corner 26 Corner 27 Corner 27 Corner 28 Corner 28 Corner 29 Corner 29 Corner 30 Corner 30 Corner 31 Corner 31 Corner 32 Corner 32 Name of Tiers Number Elevation Corners East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) 1 1 1 928.05 3.05 6 2 1 1 928.15 3.05 4 3 1 1 927.59 9.141 4 4 1 1 927.9 6.099 4 10 1 1 929.44 21.339 4 16 1 1 934.91 9.141 4 20 1 1 926.53 4.569 4 21 1 1 921.78 9.141 4 22 1 1 929.54 13.719 4 104 1 1 923.58 7.62 4 111‐1 1 1 917.3 3.051 8 116 1 1 925.79 9.141 5 123 1 1 929.9 4.569 4 124 1 1 929.6 4.569 10 125 1 1 929.41 6.099 4 126 1 1 929.46 3.051 4 127 1 1 929.72 6.099 4 131 1 1 920.4 12.189 4 134 1 1 924.14 3.051 4 136 1 1 923.11 3.051 4 140 1 1 920.16 6.099 4 142 1 1 922.92 6.099 4 148 1 1 924.49 6.099 4 151 1 1 929.25 9.141 4 153 1 1 929.56 7.62 4 154 1 1 929.53 4.569 4 160 1 1 928.13 3.051 4 163 1 1 926.25 9.141 4 172 1 1 926.64 10.671 5 178 1 1 929.85 4.569 4 179 1 1 933.49 3.051 16 181 1 1 929.82 10.671 4 182 1 1 931.37 4.57 4 183 1 1 932.54 7.01 4 184 1 1 933.64 3.05 4 185 1 1 935.62 7.62 4 512 1 1 934.84 4.57 4 1011B 1 1 932.32 3.05 4 1022 1 1 931.08 12.19 4 1024 1 1 926.75 3.05 4 1064B 1 1 931.73 3.05 4 1165B 1 1 924.37 6.1 4 1201 1 1 922.31 6.1 4 1203 1 1 922.01 3.05 4 1551 1 1 922.18 4.57 4 2510‐1 1 1 925.23 10.67 4 2511 1 1 932.48 10.67 32 285,698.01 3,952,793.17 285,700.97 3,952,793.46 285,703.82 3,952,794.32 285,706.44 3,952,795.72 285,708.74 3,952,797.61 285,710.62 3,952,799.91 285,712.03 3,952,802.53 285,712.89 3,952,805.38 2551 1 1 925.25 10.67 4 2552‐1 1 1 925.02 9.14 4 2553‐1 1 1 924.98 3.66 4 2554 1 1 926.35 4.57 4 2571B 1 1 926.68 3.05 4

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 4 of 8 Table A‐1 Rectangular and Polygonal Structure Locations and Parameters Phillips 66 Borgery Refinery PSD Permit Air Quality Analysis

Building Number Tier Base Tier HeightNumber of Corner 1 Corner 1 Corner 2 Corner 2 Corner 3 Corner 3 Corner 4 Corner 4 Corner 5 Corner 5 Corner 6 Corner 6 Corner 7 Corner 7 Corner 8 Corner 8 Name of Tiers Number Elevation Corners East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) 2572B 1 1 925.15 12.19 4 285,680.46 3,952,977.57 285,691.87 3,952,977.57 285,691.87 3,952,957.85 285,680.46 3,952,957.85 2576B 1 1 927.98 4.57 4 286,127.92 3,952,590.80 286,165.14 3,952,589.55 286,164.89 3,952,573.55 286,127.92 3,952,574.80 2577B 1 1 928.37 3.05 4 286,135.90 3,952,620.97 286,157.34 3,952,620.47 286,157.09 3,952,605.97 286,135.90 3,952,606.47 5504 1 1 926.26 3.05 4 285,972.61 3,953,203.26 285,972.61 3,953,222.98 285,989.11 3,953,222.76 285,989.11 3,953,203.51 5001 1 1 927.6 11.58 32 286,324.65 3,953,103.31 286,324.41 3,953,105.68 286,323.72 3,953,107.97 286,322.59 3,953,110.08 286,321.08 3,953,111.92 286,319.23 3,953,113.44 286,317.12 3,953,114.57 286,314.83 3,953,115.26 111 1 1 915.82 6.71 32 286,354.51 3,953,774.37 286,354.45 3,953,774.96 286,354.28 3,953,775.54 286,354.00 3,953,776.06 286,353.62 3,953,776.52 286,353.16 3,953,776.90 286,352.63 3,953,777.19 286,352.06 3,953,777.36 202 1 1 917.91 4.88 32 285,969.67 3,953,633.71 285,969.60 3,953,634.45 285,969.38 3,953,635.17 285,969.03 3,953,635.83 285,968.56 3,953,636.41 285,967.98 3,953,636.88 285,967.32 3,953,637.23 285,966.61 3,953,637.45 401 1 1 918.35 7.24 32 285,960.67 3,953,626.04 285,960.58 3,953,626.96 285,960.31 3,953,627.85 285,959.88 3,953,628.66 285,959.29 3,953,629.38 285,958.57 3,953,629.96 285,957.76 3,953,630.40 285,956.87 3,953,630.67 1004 1 1 929.97 11.38 32 285,327.82 3,952,665.23 285,327.69 3,952,666.54 285,327.31 3,952,667.80 285,326.69 3,952,668.96 285,325.86 3,952,669.97 285,324.84 3,952,670.81 285,323.68 3,952,671.43 285,322.42 3,952,671.81 2552 1 1 920.15 11.13 32 285,585.32 3,953,054.23 285,585.13 3,953,056.22 285,584.55 3,953,058.14 285,583.60 3,953,059.90 285,582.33 3,953,061.45 285,580.79 3,953,062.72 285,579.02 3,953,063.66 285,577.10 3,953,064.24 2671 1 1 922.6 12.19 32 286,630.70 3,953,743.16 286,630.51 3,953,745.12 286,629.94 3,953,747.01 286,629.01 3,953,748.75 286,627.76 3,953,750.27 286,626.23 3,953,751.52 286,624.49 3,953,752.45 286,622.61 3,953,753.02 1‐1 1 1 930.09 6.1 4 285,868.94 3,953,082.15 285,883.23 3,953,082.15 285,883.30 3,953,055.79 285,868.98 3,953,055.92 121‐2 1 1 923.17 7.62 4 286,244.72 3,953,509.09 286,244.88 3,953,528.59 286,257.32 3,953,528.84 286,256.82 3,953,509.84 122‐2 1 1 928.95 6.099 4 286,564.67 3,953,422.41 286,578.01 3,953,422.41 286,578.01 3,953,402.92 286,564.67 3,953,403.07 127‐1 1 1 928.34 4.57 6 286,385.82 3,953,392.77 286,463.90 3,953,391.84 286,463.77 3,953,367.23 286,451.53 3,953,367.37 286,451.00 3,953,354.06 286,384.76 3,953,354.86 127‐2 1 1 928.87 7.62 4 286,381.90 3,953,354.26 286,422.60 3,953,353.99 286,422.02 3,953,299.80 286,380.64 3,953,300.28 128‐2 1 1 928.02 3.051 4 286,408.82 3,953,416.75 286,408.94 3,953,407.83 286,426.30 3,953,407.83 286,426.30 3,953,416.63 128‐3 1 1 926.18 3.051 4 286,365.75 3,953,425.40 286,366.03 3,953,436.26 286,395.72 3,953,436.17 286,395.83 3,953,425.40 131‐2 1 1 926.48 4.569 4 286,371.70 3,953,216.48 286,368.37 3,953,209.05 286,332.16 3,953,228.31 286,336.38 3,953,235.93 136‐4 1 1 922.46 3.051 4 286,236.00 3,953,211.56 286,232.32 3,953,211.56 286,232.22 3,953,227.99 286,236.00 3,953,227.99 140‐4 1 1 914.06 10.671 4 286,163.55 3,953,418.77 286,163.83 3,953,440.77 286,182.49 3,953,440.77 286,182.77 3,953,418.77 140‐7 1 1 927.18 3.051 10 286,183.53 3,952,927.74 286,183.58 3,952,940.15 286,181.44 3,952,939.91 286,181.20 3,952,951.80 286,185.24 3,952,951.80 286,185.24 3,952,960.12 286,193.09 3,952,960.12 286,193.09 3,952,965.59 153‐2 1 1 929.62 4.569 4 286,088.49 3,952,681.19 286,088.49 3,952,689.18 286,124.72 3,952,689.32 286,125.05 3,952,681.19 159‐2 1 1 928.43 3.051 4 285,923.47 3,952,805.60 285,940.93 3,952,805.30 285,940.93 3,952,799.68 285,923.77 3,952,800.27 181‐2 1 1 931.35 6.1 4 285,869.23 3,952,697.43 285,901.05 3,952,697.43 285,901.05 3,952,685.77 285,869.50 3,952,685.77 184‐2 1 1 932.92 6.1 4 285,892.19 3,952,558.55 285,892.68 3,952,567.60 285,900.50 3,952,567.60 285,900.26 3,952,558.79 b1 1 1 913.46 10.67 4 286,033.77 3,953,704.99 286,043.07 3,953,695.17 286,024.47 3,953,677.95 286,015.00 3,953,687.94 b10 1 1 928.58 3.05 4 285,809.33 3,953,029.67 285,828.16 3,953,029.54 285,828.16 3,953,040.81 285,809.47 3,953,040.68 b3 1 1 925.59 33.53 4 285,774.58 3,952,928.34 285,775.26 3,952,922.26 285,792.82 3,952,922.26 285,793.16 3,952,928.00 b4 1 1 925.51 33.53 4 285,783.70 3,952,938.47 285,783.70 3,952,932.05 285,797.89 3,952,931.71 285,797.89 3,952,938.47 b5 1 1 925.87 4.57 10 286,340.84 3,953,313.13 286,350.46 3,953,308.08 286,353.74 3,953,314.06 286,354.67 3,953,313.66 286,363.16 3,953,327.13 286,367.44 3,953,344.91 286,358.53 3,953,345.31 286,355.34 3,953,331.61 b7 1 1 934.85 6.1 4 285,768.61 3,952,625.31 285,780.89 3,952,625.21 285,780.85 3,952,609.88 285,768.76 3,952,610.14 b8 1 1 936.1 3.66 4 285,710.84 3,952,588.25 285,717.68 3,952,588.25 285,717.68 3,952,573.26 285,710.84 3,952,573.00 b9 1 1 936.65 3.66 4 285,710.14 3,952,567.88 285,722.33 3,952,567.88 285,722.33 3,952,552.64 285,710.14 3,952,552.63 BD1 1 1 922.29 6.1 13 286,104.79 3,953,044.79 286,104.79 3,953,068.76 286,121.33 3,953,068.76 286,121.33 3,953,074.82 286,116.09 3,953,074.82 286,115.93 3,953,084.95 286,143.90 3,953,084.95 286,144.16 3,953,051.81 BD2 1 1 922.37 4.57 4 286,104.93 3,953,040.28 286,104.93 3,953,024.50 286,115.66 3,953,024.37 286,115.67 3,953,040.28 CT21 1 1 924.85 9.14 5 286,234.43 3,953,038.69 286,234.43 3,953,030.87 286,264.34 3,953,030.86 286,264.34 3,953,039.57 286,234.43 3,953,039.61 kg47 1 1 929.54 14.66 32 286,175.18 3,952,697.63 286,175.02 3,952,699.23 286,174.56 3,952,700.78 286,173.80 3,952,702.20 286,172.77 3,952,703.45 286,171.53 3,952,704.47 286,170.10 3,952,705.23 286,168.56 3,952,705.70 309 1 1 935.9 7.32 32 285,670.67 3,952,434.35 285,670.59 3,952,435.24 285,670.32 3,952,436.10 285,669.90 3,952,436.89 285,669.33 3,952,437.58 285,668.64 3,952,438.15 285,667.85 3,952,438.57 285,666.99 3,952,438.84 MAINT 1 1 905.41 12.19 32 286,938.46 3,953,790.83 286,938.33 3,953,792.17 286,937.94 3,953,793.45 286,937.31 3,953,794.64 286,936.45 3,953,795.68 286,935.41 3,953,796.53 286,934.23 3,953,797.17 286,932.94 3,953,797.56 n1 1 1 904.17 6.1 32 286,147.75 3,953,725.07 286,147.63 3,953,726.26 286,147.29 3,953,727.40 286,146.72 3,953,728.45 286,145.97 3,953,729.38 286,145.04 3,953,730.14 286,143.99 3,953,730.70 286,142.84 3,953,731.05 n2 1 1 903.18 6.1 32 286,133.79 3,953,725.34 286,133.68 3,953,726.53 286,133.33 3,953,727.67 286,132.77 3,953,728.73 286,132.01 3,953,729.65 286,131.09 3,953,730.41 286,130.03 3,953,730.97 286,128.89 3,953,731.32 n3 1 1 902.57 6.1 32 286,113.91 3,953,725.78 286,113.72 3,953,727.71 286,113.16 3,953,729.57 286,112.24 3,953,731.29 286,111.01 3,953,732.79 286,109.51 3,953,734.02 286,107.79 3,953,734.93 286,105.94 3,953,735.50 8003 1 1 925.73 8.23 32 285,220.36 3,952,624.46 285,220.01 3,952,628.03 285,218.97 3,952,631.46 285,217.28 3,952,634.63 285,215.01 3,952,637.40 285,212.23 3,952,639.67 285,209.07 3,952,641.36 285,205.64 3,952,642.40 8004 1 1 924.64 12.22 32 285,106.50 3,952,679.67 285,106.15 3,952,683.24 285,105.10 3,952,686.67 285,103.41 3,952,689.83 285,101.14 3,952,692.60 285,098.37 3,952,694.88 285,095.21 3,952,696.57 285,091.77 3,952,697.61 P_SERV 1 1 924.42 12.22 32 286,202.62 3,953,007.27 286,202.48 3,953,008.71 286,202.06 3,953,010.09 286,201.37 3,953,011.37 286,200.46 3,953,012.49 286,199.34 3,953,013.40 286,198.06 3,953,014.09 286,196.68 3,953,014.51 P_UPS 1 1 935.28 9.14 32 285,778.03 3,952,579.93 285,777.69 3,952,583.41 285,776.67 3,952,586.76 285,775.02 3,952,589.85 285,772.80 3,952,592.55 285,770.10 3,952,594.78 285,767.01 3,952,596.43 285,763.66 3,952,597.44 SS1 1 1 914.86 6.096 4 286,090.81 3,953,454.85 286,090.19 3,953,436.43 286,101.10 3,953,436.00 286,101.62 3,953,454.76 SS3 1 1 921.19 6.096 4 286,157.54 3,953,166.31 286,157.54 3,953,158.00 286,173.56 3,953,158.00 286,173.56 3,953,166.31 SS7A 1 1 921.32 3.048 4 285,383.27 3,952,819.97 285,383.27 3,952,810.83 285,367.16 3,952,810.83 285,367.16 3,952,819.97 SS7B 1 1 922.24 3.6576 4 285,353.48 3,952,789.74 285,343.17 3,952,789.74 285,343.17 3,952,784.24 285,353.48 3,952,784.24 SS7C 1 1 922.1 3.048 4 285,305.35 3,952,787.32 285,297.57 3,952,787.32 285,297.57 3,952,781.99 285,305.35 3,952,781.99 CT_5 1 1 929.32 7.62 4 286,056.00 3,952,562.00 286,071.00 3,952,562.00 286,071.00 3,952,545.00 286,056.00 3,952,545.00

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 5 of 8 Table A‐1 Rectangular and Polygonal Structure Locations and Parameters Phillips 66 Borgery Refinery PSD Permit Air Quality Analysis

Building Number Tier Base Tier Height Number of Corner 9 Corner 9 Corner 10 Corner 10 Corner 11 Corner 11 Corner 12 Corner 12 Corner 13 Corner 13 Corner 14 Corner 14 Corner 15 Corner 15 Corner 16 Corner 16 Name of Tiers Number Elevation Corners East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) 2572B 1 1 925.15 12.19 4 2576B 1 1 927.98 4.57 4 2577B 1 1 928.37 3.05 4 5504 1 1 926.26 3.05 4 5001 1 1 927.6 11.58 32 286,312.46 3,953,115.50 286,310.08 3,953,115.26 286,307.79 3,953,114.57 286,305.68 3,953,113.44 286,303.84 3,953,111.92 286,302.32 3,953,110.08 286,301.19 3,953,107.97 286,300.50 3,953,105.68 111 1 1 915.82 6.71 32 286,351.46 3,953,777.42 286,350.87 3,953,777.36 286,350.30 3,953,777.19 286,349.77 3,953,776.90 286,349.31 3,953,776.52 286,348.93 3,953,776.06 286,348.65 3,953,775.54 286,348.47 3,953,774.96 202 1 1 917.91 4.88 32 285,965.86 3,953,637.52 285,965.12 3,953,637.45 285,964.41 3,953,637.23 285,963.75 3,953,636.88 285,963.17 3,953,636.41 285,962.70 3,953,635.83 285,962.34 3,953,635.17 285,962.13 3,953,634.45 401 1 1 918.35 7.24 32 285,955.95 3,953,630.76 285,955.03 3,953,630.67 285,954.15 3,953,630.40 285,953.33 3,953,629.96 285,952.61 3,953,629.38 285,952.03 3,953,628.66 285,951.59 3,953,627.85 285,951.32 3,953,626.96 1004 1 1 929.97 11.38 32 285,321.11 3,952,671.94 285,319.80 3,952,671.81 285,318.55 3,952,671.43 285,317.39 3,952,670.81 285,316.37 3,952,669.97 285,315.53 3,952,668.96 285,314.91 3,952,667.80 285,314.53 3,952,666.54 2552 1 1 920.15 11.13 32 285,575.11 3,953,064.44 285,573.12 3,953,064.24 285,571.21 3,953,063.66 285,569.44 3,953,062.72 285,567.89 3,953,061.45 285,566.62 3,953,059.90 285,565.68 3,953,058.14 285,565.10 3,953,056.22 2671 1 1 922.6 12.19 32 286,620.64 3,953,753.22 286,618.68 3,953,753.02 286,616.79 3,953,752.45 286,615.05 3,953,751.52 286,613.53 3,953,750.27 286,612.28 3,953,748.75 286,611.35 3,953,747.01 286,610.78 3,953,745.12 1‐1 1 1 930.09 6.1 4 121‐2 1 1 923.17 7.62 4 122‐2 1 1 928.95 6.099 4 127‐1 1 1 928.34 4.57 6 127‐2 1 1 928.87 7.62 4 128‐2 1 1 928.02 3.051 4 128‐3 1 1 926.18 3.051 4 131‐2 1 1 926.48 4.569 4 136‐4 1 1 922.46 3.051 4 140‐4 1 1 914.06 10.671 4 140‐7 1 1 927.18 3.051 10 286,208.78 3,952,965.59 286,208.45 3,952,927.87 153‐2 1 1 929.62 4.569 4 159‐2 1 1 928.43 3.051 4 181‐2 1 1 931.35 6.1 4 184‐2 1 1 932.92 6.1 4 b1 1 1 913.46 10.67 4 b10 1 1 928.58 3.05 4 b3 1 1 925.59 33.53 4 b4 1 1 925.51 33.53 4 b5 1 1 925.87 4.57 10 286,347.49 3,953,318.45 286,344.56 3,953,319.64 b7 1 1 934.85 6.1 4 b8 1 1 936.1 3.66 4 b9 1 1 936.65 3.66 4 BD1 1 1 922.29 6.1 13 286,127.99 3,953,051.94 286,127.86 3,953,055.66 286,119.40 3,953,055.53 286,119.40 3,953,043.96 286,105.62 3,953,044.24 BD2 1 1 922.37 4.57 4 CT21 1 1 924.85 9.14 5 kg47 1 1 929.54 14.66 32 286,166.95 3,952,705.86 286,165.35 3,952,705.70 286,163.80 3,952,705.23 286,162.38 3,952,704.47 286,161.13 3,952,703.45 286,160.11 3,952,702.20 286,159.35 3,952,700.78 286,158.88 3,952,699.23 309 1 1 935.9 7.32 32 285,666.10 3,952,438.92 285,665.21 3,952,438.84 285,664.35 3,952,438.57 285,663.56 3,952,438.15 285,662.86 3,952,437.58 285,662.29 3,952,436.89 285,661.87 3,952,436.10 285,661.61 3,952,435.24 MAINT 1 1 905.41 12.19 32 286,931.60 3,953,797.69 286,930.26 3,953,797.56 286,928.98 3,953,797.17 286,927.79 3,953,796.53 286,926.75 3,953,795.68 286,925.90 3,953,794.64 286,925.27 3,953,793.45 286,924.87 3,953,792.17 n1 1 1 904.17 6.1 32 286,141.66 3,953,731.16 286,140.47 3,953,731.05 286,139.32 3,953,730.70 286,138.27 3,953,730.14 286,137.35 3,953,729.38 286,136.59 3,953,728.45 286,136.02 3,953,727.40 286,135.68 3,953,726.26 n2 1 1 903.18 6.1 32 286,127.70 3,953,731.43 286,126.51 3,953,731.32 286,125.37 3,953,730.97 286,124.31 3,953,730.41 286,123.39 3,953,729.65 286,122.63 3,953,728.73 286,122.07 3,953,727.67 286,121.72 3,953,726.53 n3 1 1 902.57 6.1 32 286,104.00 3,953,735.69 286,102.07 3,953,735.50 286,100.21 3,953,734.93 286,098.50 3,953,734.02 286,097.00 3,953,732.79 286,095.77 3,953,731.29 286,094.85 3,953,729.57 286,094.29 3,953,727.71 8003 1 1 925.73 8.23 32 285,202.07 3,952,642.75 285,198.50 3,952,642.40 285,195.07 3,952,641.36 285,191.91 3,952,639.67 285,189.14 3,952,637.40 285,186.87 3,952,634.63 285,185.18 3,952,631.46 285,184.13 3,952,628.03 8004 1 1 924.64 12.22 32 285,088.21 3,952,697.96 285,084.64 3,952,697.61 285,081.21 3,952,696.57 285,078.05 3,952,694.88 285,075.27 3,952,692.60 285,073.00 3,952,689.83 285,071.31 3,952,686.67 285,070.27 3,952,683.24 P_SERV 1 1 924.42 12.22 32 286,195.24 3,953,014.65 286,193.80 3,953,014.51 286,192.41 3,953,014.09 286,191.14 3,953,013.40 286,190.02 3,953,012.49 286,189.10 3,953,011.37 286,188.42 3,953,010.09 286,188.00 3,953,008.71 P_UPS 1 1 935.28 9.14 32 285,760.17 3,952,597.79 285,756.69 3,952,597.44 285,753.34 3,952,596.43 285,750.25 3,952,594.78 285,747.54 3,952,592.55 285,745.32 3,952,589.85 285,743.67 3,952,586.76 285,742.66 3,952,583.41 SS1 1 1 914.86 6.096 4 SS3 1 1 921.19 6.096 4 SS7A 1 1 921.32 3.048 4 SS7B 1 1 922.24 3.6576 4 SS7C 1 1 922.1 3.048 4 CT_5 1 1 929.32 7.62 4

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 6 of 8 Table A‐1 Rectangular and Polygonal Structure Locations and Parameters Phillips 66 Borgery Refinery PSD Permit Air Quality Analysis

Building Number Tier Base Tier Height Number of Corner 17 Corner 17 Corner 18 Corner 18 Corner 19 Corner 19 Corner 20 Corner 20 Corner 21 Corner 21 Corner 22 Corner 22 Corner 23 Corner 23 Corner 24 Corner 24 Name of Tiers Number Elevation Corners East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) 2572B 1 1 925.15 12.19 4 2576B 1 1 927.98 4.57 4 2577B 1 1 928.37 3.05 4 5504 1 1 926.26 3.05 4 5001 1 1 927.6 11.58 32 286,300.27 3,953,103.31 286,300.50 3,953,100.93 286,301.19 3,953,098.64 286,302.32 3,953,096.53 286,303.84 3,953,094.69 286,305.68 3,953,093.17 286,307.79 3,953,092.04 286,310.08 3,953,091.35 111 1 1 915.82 6.71 32 286,348.41 3,953,774.37 286,348.47 3,953,773.77 286,348.65 3,953,773.20 286,348.93 3,953,772.67 286,349.31 3,953,772.21 286,349.77 3,953,771.83 286,350.30 3,953,771.55 286,350.87 3,953,771.38 202 1 1 917.91 4.88 32 285,962.05 3,953,633.71 285,962.13 3,953,632.97 285,962.34 3,953,632.25 285,962.70 3,953,631.59 285,963.17 3,953,631.02 285,963.75 3,953,630.54 285,964.41 3,953,630.19 285,965.12 3,953,629.97 401 1 1 918.35 7.24 32 285,951.23 3,953,626.04 285,951.32 3,953,625.12 285,951.59 3,953,624.23 285,952.03 3,953,623.42 285,952.61 3,953,622.70 285,953.33 3,953,622.12 285,954.15 3,953,621.68 285,955.03 3,953,621.41 1004 1 1 929.97 11.38 32 285,314.40 3,952,665.23 285,314.53 3,952,663.92 285,314.91 3,952,662.66 285,315.53 3,952,661.50 285,316.37 3,952,660.48 285,317.39 3,952,659.65 285,318.55 3,952,659.03 285,319.80 3,952,658.65 2552 1 1 920.15 11.13 32 285,564.90 3,953,054.23 285,565.10 3,953,052.24 285,565.68 3,953,050.32 285,566.62 3,953,048.56 285,567.89 3,953,047.01 285,569.44 3,953,045.74 285,571.21 3,953,044.80 285,573.12 3,953,044.21 2671 1 1 922.6 12.19 32 286,610.58 3,953,743.16 286,610.78 3,953,741.20 286,611.35 3,953,739.31 286,612.28 3,953,737.57 286,613.53 3,953,736.04 286,615.05 3,953,734.79 286,616.79 3,953,733.86 286,618.68 3,953,733.29 1‐1 1 1 930.09 6.1 4 121‐2 1 1 923.17 7.62 4 122‐2 1 1 928.95 6.099 4 127‐1 1 1 928.34 4.57 6 127‐2 1 1 928.87 7.62 4 128‐2 1 1 928.02 3.051 4 128‐3 1 1 926.18 3.051 4 131‐2 1 1 926.48 4.569 4 136‐4 1 1 922.46 3.051 4 140‐4 1 1 914.06 10.671 4 140‐7 1 1 927.18 3.051 10 153‐2 1 1 929.62 4.569 4 159‐2 1 1 928.43 3.051 4 181‐2 1 1 931.35 6.1 4 184‐2 1 1 932.92 6.1 4 b1 1 1 913.46 10.67 4 b10 1 1 928.58 3.05 4 b3 1 1 925.59 33.53 4 b4 1 1 925.51 33.53 4 b5 1 1 925.87 4.57 10 b7 1 1 934.85 6.1 4 b8 1 1 936.1 3.66 4 b9 1 1 936.65 3.66 4 BD1 1 1 922.29 6.1 13 BD2 1 1 922.37 4.57 4 CT21 1 1 924.85 9.14 5 kg47 1 1 929.54 14.66 32 286,158.72 3,952,697.63 286,158.88 3,952,696.02 286,159.35 3,952,694.48 286,160.11 3,952,693.06 286,161.13 3,952,691.81 286,162.38 3,952,690.79 286,163.80 3,952,690.02 286,165.35 3,952,689.56 309 1 1 935.9 7.32 32 285,661.52 3,952,434.35 285,661.61 3,952,433.46 285,661.87 3,952,432.60 285,662.29 3,952,431.81 285,662.86 3,952,431.11 285,663.56 3,952,430.54 285,664.35 3,952,430.12 285,665.21 3,952,429.86 MAINT 1 1 905.41 12.19 32 286,924.74 3,953,790.83 286,924.87 3,953,789.49 286,925.27 3,953,788.20 286,925.90 3,953,787.02 286,926.75 3,953,785.98 286,927.79 3,953,785.12 286,928.98 3,953,784.49 286,930.26 3,953,784.10 n1 1 1 904.17 6.1 32 286,135.56 3,953,725.07 286,135.68 3,953,723.88 286,136.02 3,953,722.73 286,136.59 3,953,721.68 286,137.35 3,953,720.76 286,138.27 3,953,720.00 286,139.32 3,953,719.44 286,140.47 3,953,719.09 n2 1 1 903.18 6.1 32 286,121.60 3,953,725.34 286,121.72 3,953,724.15 286,122.07 3,953,723.01 286,122.63 3,953,721.95 286,123.39 3,953,721.03 286,124.31 3,953,720.27 286,125.37 3,953,719.71 286,126.51 3,953,719.36 n3 1 1 902.57 6.1 32 286,094.10 3,953,725.78 286,094.29 3,953,723.85 286,094.85 3,953,721.99 286,095.77 3,953,720.28 286,097.00 3,953,718.78 286,098.50 3,953,717.55 286,100.21 3,953,716.63 286,102.07 3,953,716.07 8003 1 1 925.73 8.23 32 285,183.78 3,952,624.46 285,184.13 3,952,620.90 285,185.18 3,952,617.46 285,186.87 3,952,614.30 285,189.14 3,952,611.53 285,191.91 3,952,609.26 285,195.07 3,952,607.57 285,198.50 3,952,606.53 8004 1 1 924.64 12.22 32 285,069.92 3,952,679.67 285,070.27 3,952,676.10 285,071.31 3,952,672.67 285,073.00 3,952,669.51 285,075.27 3,952,666.74 285,078.05 3,952,664.46 285,081.21 3,952,662.77 285,084.64 3,952,661.73 P_SERV 1 1 924.42 12.22 32 286,187.86 3,953,007.27 286,188.00 3,953,005.83 286,188.42 3,953,004.44 286,189.10 3,953,003.17 286,190.02 3,953,002.05 286,191.14 3,953,001.13 286,192.41 3,953,000.45 286,193.80 3,953,000.03 P_UPS 1 1 935.28 9.14 32 285,742.31 3,952,579.93 285,742.66 3,952,576.44 285,743.67 3,952,573.09 285,745.32 3,952,570.00 285,747.54 3,952,567.30 285,750.25 3,952,565.08 285,753.34 3,952,563.43 285,756.69 3,952,562.41 SS1 1 1 914.86 6.096 4 SS3 1 1 921.19 6.096 4 SS7A 1 1 921.32 3.048 4 SS7B 1 1 922.24 3.6576 4 SS7C 1 1 922.1 3.048 4 CT_5 1 1 929.32 7.62 4

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 7 of 8 Table A‐1 Rectangular and Polygonal Structure Locations and Parameters Phillips 66 Borgery Refinery PSD Permit Air Quality Analysis

Building Number Tier Base Tier Height Number of Corner 25 Corner 25 Corner 26 Corner 26 Corner 27 Corner 27 Corner 28 Corner 28 Corner 29 Corner 29 Corner 30 Corner 30 Corner 31 Corner 31 Corner 32 Corner 32 Name of Tiers Number Elevation Corners East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) East (X) North (Y) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) (m) 2572B 1 1 925.15 12.19 4 2576B 1 1 927.98 4.57 4 2577B 1 1 928.37 3.05 4 5504 1 1 926.26 3.05 4 5001 1 1 927.6 11.58 32 286,312.46 3,953,091.12 286,314.83 3,953,091.35 286,317.12 3,953,092.04 286,319.23 3,953,093.17 286,321.08 3,953,094.69 286,322.59 3,953,096.53 286,323.72 3,953,098.64 286,324.41 3,953,100.93 111 1 1 915.82 6.71 32 286,351.46 3,953,771.32 286,352.06 3,953,771.38 286,352.63 3,953,771.55 286,353.16 3,953,771.83 286,353.62 3,953,772.21 286,354.00 3,953,772.67 286,354.28 3,953,773.20 286,354.45 3,953,773.77 202 1 1 917.91 4.88 32 285,965.86 3,953,629.90 285,966.61 3,953,629.97 285,967.32 3,953,630.19 285,967.98 3,953,630.54 285,968.56 3,953,631.02 285,969.03 3,953,631.59 285,969.38 3,953,632.25 285,969.60 3,953,632.97 401 1 1 918.35 7.24 32 285,955.95 3,953,621.32 285,956.87 3,953,621.41 285,957.76 3,953,621.68 285,958.57 3,953,622.12 285,959.29 3,953,622.70 285,959.88 3,953,623.42 285,960.31 3,953,624.23 285,960.58 3,953,625.12 1004 1 1 929.97 11.38 32 285,321.11 3,952,658.52 285,322.42 3,952,658.65 285,323.68 3,952,659.03 285,324.84 3,952,659.65 285,325.86 3,952,660.48 285,326.69 3,952,661.50 285,327.31 3,952,662.66 285,327.69 3,952,663.92 2552 1 1 920.15 11.13 32 285,575.11 3,953,044.02 285,577.10 3,953,044.21 285,579.02 3,953,044.80 285,580.79 3,953,045.74 285,582.33 3,953,047.01 285,583.60 3,953,048.56 285,584.55 3,953,050.32 285,585.13 3,953,052.24 2671 1 1 922.6 12.19 32 286,620.64 3,953,733.10 286,622.61 3,953,733.29 286,624.49 3,953,733.86 286,626.23 3,953,734.79 286,627.76 3,953,736.04 286,629.01 3,953,737.57 286,629.94 3,953,739.31 286,630.51 3,953,741.20 1‐1 1 1 930.09 6.1 4 121‐2 1 1 923.17 7.62 4 122‐2 1 1 928.95 6.099 4 127‐1 1 1 928.34 4.57 6 127‐2 1 1 928.87 7.62 4 128‐2 1 1 928.02 3.051 4 128‐3 1 1 926.18 3.051 4 131‐2 1 1 926.48 4.569 4 136‐4 1 1 922.46 3.051 4 140‐4 1 1 914.06 10.671 4 140‐7 1 1 927.18 3.051 10 153‐2 1 1 929.62 4.569 4 159‐2 1 1 928.43 3.051 4 181‐2 1 1 931.35 6.1 4 184‐2 1 1 932.92 6.1 4 b1 1 1 913.46 10.67 4 b10 1 1 928.58 3.05 4 b3 1 1 925.59 33.53 4 b4 1 1 925.51 33.53 4 b5 1 1 925.87 4.57 10 b7 1 1 934.85 6.1 4 b8 1 1 936.1 3.66 4 b9 1 1 936.65 3.66 4 BD1 1 1 922.29 6.1 13 BD2 1 1 922.37 4.57 4 CT21 1 1 924.85 9.14 5 kg47 1 1 929.54 14.66 32 286,166.95 3,952,689.40 286,168.56 3,952,689.56 286,170.10 3,952,690.02 286,171.53 3,952,690.79 286,172.77 3,952,691.81 286,173.80 3,952,693.06 286,174.56 3,952,694.48 286,175.02 3,952,696.02 309 1 1 935.9 7.32 32 285,666.10 3,952,429.77 285,666.99 3,952,429.86 285,667.85 3,952,430.12 285,668.64 3,952,430.54 285,669.33 3,952,431.11 285,669.90 3,952,431.81 285,670.32 3,952,432.60 285,670.59 3,952,433.46 MAINT 1 1 905.41 12.19 32 286,931.60 3,953,783.97 286,932.94 3,953,784.10 286,934.23 3,953,784.49 286,935.41 3,953,785.12 286,936.45 3,953,785.98 286,937.31 3,953,787.02 286,937.94 3,953,788.20 286,938.33 3,953,789.49 n1 1 1 904.17 6.1 32 286,141.66 3,953,718.97 286,142.84 3,953,719.09 286,143.99 3,953,719.44 286,145.04 3,953,720.00 286,145.97 3,953,720.76 286,146.72 3,953,721.68 286,147.29 3,953,722.73 286,147.63 3,953,723.88 n2 1 1 903.18 6.1 32 286,127.70 3,953,719.24 286,128.89 3,953,719.36 286,130.03 3,953,719.71 286,131.09 3,953,720.27 286,132.01 3,953,721.03 286,132.77 3,953,721.95 286,133.33 3,953,723.01 286,133.68 3,953,724.15 n3 1 1 902.57 6.1 32 286,104.00 3,953,715.88 286,105.94 3,953,716.07 286,107.79 3,953,716.63 286,109.51 3,953,717.55 286,111.01 3,953,718.78 286,112.24 3,953,720.28 286,113.16 3,953,721.99 286,113.72 3,953,723.85 8003 1 1 925.73 8.23 32 285,202.07 3,952,606.17 285,205.64 3,952,606.53 285,209.07 3,952,607.57 285,212.23 3,952,609.26 285,215.01 3,952,611.53 285,217.28 3,952,614.30 285,218.97 3,952,617.46 285,220.01 3,952,620.90 8004 1 1 924.64 12.22 32 285,088.21 3,952,661.38 285,091.77 3,952,661.73 285,095.21 3,952,662.77 285,098.37 3,952,664.46 285,101.14 3,952,666.74 285,103.41 3,952,669.51 285,105.10 3,952,672.67 285,106.15 3,952,676.10 P_SERV 1 1 924.42 12.22 32 286,195.24 3,952,999.89 286,196.68 3,953,000.03 286,198.06 3,953,000.45 286,199.34 3,953,001.13 286,200.46 3,953,002.05 286,201.37 3,953,003.17 286,202.06 3,953,004.44 286,202.48 3,953,005.83 P_UPS 1 1 935.28 9.14 32 285,760.17 3,952,562.07 285,763.66 3,952,562.41 285,767.01 3,952,563.43 285,770.10 3,952,565.08 285,772.80 3,952,567.30 285,775.02 3,952,570.00 285,776.67 3,952,573.09 285,777.69 3,952,576.44 SS1 1 1 914.86 6.096 4 SS3 1 1 921.19 6.096 4 SS7A 1 1 921.32 3.048 4 SS7B 1 1 922.24 3.6576 4 SS7C 1 1 922.1 3.048 4 CT_5 1 1 929.32 7.62 4

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 8 of 8 Table A‐2 Circular Downwash Structure Locations and Parameters Phillips 66 Borger Refinery PSD Permit Air Quality Analysis

Tank Name Description Base Elevation Center Center Tank Height Tank Diameter Easting (X) Northing (Y) (m) (m) (m) (m) (m) 1002 Tank 1002 929.82 285398.66 3952662.88 11.58 13.26 1003 Tank 1003 929.92 285361.90 3952663.64 11.38 13.41 1006 Tank 1006 935.07 285658.63 3952262.19 12.80 13.26 1007 Tank 1007 934.49 285658.63 3952219.61 12.80 13.11 1008 Tank 1008 934.26 285655.64 3952181.51 11.58 13.26 1011 Tank 1011 930.63 285382.97 3952528.07 8.76 15.14 1012 Tank 1012 934.82 285714.65 3952217.36 10.80 13.79 1013 Tank 1013 934.49 285710.92 3952143.41 10.80 13.79 1064 Tank 1064 927.35 286658.51 3953495.64 8.84 15.24 1067 Tank 1067 925.64 286518.50 3953592.40 8.84 15.24 109 Tank 109 929.18 286602.86 3953434.97 6.71 6.40 110 Tank 110 929.12 286593.74 3953435.43 6.71 6.40 1163 Tank 1163 928.54 286649.84 3953454.13 11.30 13.11 1164 Tank 1164 919.65 286132.28 3953208.68 11.58 13.41 1165 Tank 1165 926.01 285914.42 3953234.09 11.91 13.11 1522 Tank 1522 934.01 285648.91 3952066.46 12.73 15.85 2072 Tank 2072 924.73 286499.08 3953592.90 12.19 18.29 2510 Tank 2510 934.49 285714.65 3952177.77 11.13 21.34 2553 Tank 2553 934.22 285657.13 3952102.32 12.19 20.42 2571 Tank 2571 922.16 286476.66 3953644.20 8.81 24.08 2572 Tank 2572 924.56 286674.93 3953566.91 12.19 21.34 2575 Tank 2575 925.49 286604.16 3953699.48 8.84 24.08 2576 Tank 2576 921.77 286605.00 3953858.00 8.84 24.08 2577 Tank 2577 919.69 286620.10 3953916.88 8.84 24.08 2578 Tank 2578 918.10 286639.00 3953974.00 8.84 21.34 2579 Tank 2579 925.70 286541.41 3953757.25 12.19 21.34 2580 Tank 2580 925.50 286571.29 3953756.75 12.19 21.34 2670 Tank 2670 928.49 286340.58 3953103.31 11.48 21.34 2672 Tank 2672 918.76 286540.91 3953856.62 12.52 20.12 2673 Tank 2673 925.92 286007.05 3953203.21 14.66 20.42 2674 Tank 2674 916.83 286119.96 3953293.52 8.84 24.08 2675 Tank 2675 919.79 286061.34 3953295.35 15.24 18.29 2676 Tank 2676 925.81 286537.42 3953643.70 12.22 20.42 2677 Tank 2677 927.95 286656.23 3953473.75 12.12 20.42 2678 Tank 2678 927.59 286584.62 3953556.42 11.91 20.42 3001 Tank 3001 935.14 285663.86 3952296.55 14.35 22.10 3002 Tank 3002 934.22 285659.37 3952147.14 11.61 22.35 3003 Tank 3003 897.81 286008.47 3953847.64 14.63 30.48 303 Tank 303 933.89 285612.31 3952253.22 9.14 8.15 310 Tank 0310 936.22 285686.00 3952431.00 7.32 8.00 4030 Tank 4030 922.61 286484.63 3953714.42 17.07 21.34

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 1 of 3 Table A‐2 Circular Downwash Structure Locations and Parameters Phillips 66 Borger Refinery PSD Permit Air Quality Analysis

Tank Name Description Base Elevation Center Center Tank Height Tank Diameter Easting (X) Northing (Y) (m) (m) (m) (m) (m) 511 Tank 511 930.76 285406.94 3952546.20 10.97 9.75 513 Tank 513 921.85 285524.00 3953036.00 8.84 11.58 514 Tank 514 932.34 285590.65 3952219.61 12.19 9.14 5505 Tank 5505 933.69 285870.04 3952093.36 9.14 34.75 552 Tank 552 926.77 286577.76 3953640.21 8.31 11.28 5520 Tank 5520 922.00 285946.14 3951675.44 9.14 34.75 5521 Tank 5521 934.51 285633.23 3951893.81 14.94 30.48 5525 Tank 5525 850.33 281266.09 3955117.55 9.22 34.75 5531 Tank 5531 902.70 287139.78 3955176.80 12.98 29.26 5536 Tank 5536 852.93 281259.25 3954944.08 9.22 34.75 5537 Tank 5537 854.53 281254.90 3954713.41 9.22 34.75 5539 Tank 5539 845.98 281078.95 3955764.61 9.22 35.05 5540 Tank 5540 846.44 280981.33 3955650.83 9.22 34.75 5541 Tank 5541 846.81 280786.72 3955653.94 9.22 35.05 5542 Tank 5542 848.27 280685.38 3955538.92 9.22 34.75 5543 Tank 5543 847.37 280689.73 3955768.97 9.22 34.75 5544 Tank 5544 849.26 280593.98 3955655.18 9.22 34.75 5545 Tank 5545 852.20 280483.31 3955540.78 9.22 34.75 5550 Tank 5550 915.31 285193.00 3952349.00 9.22 34.75 5551 Tank 5551 937.45 285165.58 3951757.11 12.22 30.48 5553 Tank 5553 928.26 285125.99 3951928.92 11.91 30.48 5554 Tank 5554 936.23 285349.35 3951899.79 12.24 30.48 5555 Tank 5555 931.39 285197.71 3952082.81 12.22 30.48 5557 Tank 5557 919.40 285327.00 3952365.00 12.19 30.48 5558 Tank 5558 915.89 285265.00 3952348.00 12.19 30.48 5559 Tank 5559 916.96 285195.00 3952543.00 12.19 30.48 5560 Tank 5560 922.56 285083.00 3952608.00 12.19 30.48 5578 Tank 5578 930.50 285430.06 3951076.95 12.22 30.48 5580 Tank 5580 919.72 285547.54 3951144.38 12.42 30.48 5583 Tank 5583 928.23 286820.80 3953476.73 14.63 27.43 5584 Tank 5584 928.12 286782.95 3953481.21 14.63 27.43 5587 Tank 5587 913.10 286437.32 3953841.18 16.79 25.60 5588 Tank 5588 914.32 286436.82 3953807.31 16.99 25.60 5591 Tank 5591 917.38 285959.66 3953561.02 12.80 30.48 5592 Tank 5592 918.12 286731.00 3953692.00 10.06 32.61 5593 Tank 5593 918.73 286722.00 3953645.00 10.08 32.61 5596 Tank 5596 920.60 286674.00 3953711.00 12.19 30.02 5597 Tank 5597 928.35 286857.65 3953475.24 17.07 25.60 5598 Tank 5598 920.50 286507.00 3953801.00 12.19 30.48 5599 Tank 5599 926.52 286550.37 3953707.95 17.07 25.60 562 Tank 562 928.81 286583.70 3953451.85 9.68 10.67

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 2 of 3 Table A‐2 Circular Downwash Structure Locations and Parameters Phillips 66 Borger Refinery PSD Permit Air Quality Analysis

Tank Name Description Base Elevation Center Center Tank Height Tank Diameter Easting (X) Northing (Y) (m) (m) (m) (m) (m) 572 Tank 572 918.82 285948.00 3953614.00 12.19 9.14 573 Tank 573 919.24 285937.00 3953604.00 12.19 9.14 8001 Tank 8001 915.04 285193.00 3952412.00 12.19 36.58 8002 Tank 8002 912.18 285083.00 3952513.00 12.22 36.58 8010 Tank 8010 920.02 285944.80 3953373.04 16.79 30.48 8011 Tank 8011 920.81 286007.56 3953374.01 12.50 35.66 8012 Tank 8012 917.08 285927.37 3953493.46 12.52 35.66 8013 Tank 8013 915.74 286039.03 3953453.98 12.52 35.66 8014 Tank 8014 912.68 286023.06 3953631.27 12.52 35.66 8015 Tank 8015 926.99 286801.87 3953518.86 16.79 30.48 8031 Tank 8031 904.00 286859.39 3955222.61 14.02 35.38 8032 Tank 8032 902.32 287094.96 3955284.87 14.83 35.66 8033 Tank 8033 905.95 287024.24 3955136.96 16.79 30.48 8034 Tank 8034 909.80 286744.60 3954180.62 14.45 33.53 8036 Tank 8036 851.31 288093.00 3954075.00 4.88 60.96 9200 Tank 9200 923.92 285979.17 3953296.84 14.55 40.84 9201 Tank 9201 926.05 286948.79 3953567.37 14.63 40.84 9202 Tank 9202 902.37 287087.49 3955031.87 14.63 40.84 9400 Tank 9400 865.06 287673.00 3953255.00 14.63 42.67 9401 Tank 9401 865.02 287727.00 3953261.00 14.63 42.67 9500 Tank 9500 904.76 286909.20 3955097.11 14.53 45.72 9501 Tank 9501 916.28 287125.59 3953669.10 14.63 45.72 9502 Tank 9502 919.19 287140.53 3953583.94 14.63 45.72 9503 Tank 9503 920.53 287056.86 3953584.44 14.63 45.72 9504 Tank 9504 925.91 286944.80 3953473.54 14.71 45.72 9600 Tank 9600 894.16 285865.00 3953985.00 9.75 60.96 9601 Tank 9601 894.21 285857.00 3953912.00 9.75 60.96 9700 Tank 9700 908.19 286705.75 3954293.18 14.66 52.73 9701 Tank 9701 907.98 286713.22 3954398.26 14.66 52.73 9702 Tank 9702 907.86 286821.79 3954396.77 14.66 52.73 SS2 Tank SS2 926.51 285958.14 3953201.38 19.81 16.46 SS5 Tank SS5 932.72 285563.75 3952034.34 12.19 10.36 SS6 Tank SS6 851.66 288084.14 3954160.55 4.88 33.22

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Page 3 of 3 Table A‐3 Flare Effective Diameter Calculations Phillips 66 Borger Refinery PSD Permit Air Quality Analysis

EPN Source ID Source Description Flare Fuel Heat Flare Gas Gross Heat Net Heat Actual Stack Effective Stack Operation Input Mol. Release Release Height Diameter Type Weight (MMBtu/hr) (lb/lb‐mol) (cal/sec) (cal/sec) (meters) (feet) (meters) (feet) CCR‐MSS_C 66FL1CR Turn Around Clearing ‐ CCR MSS 4,104.09 65.00 287,285,976.53 176,109,644.20 42.67 140.00 13.27 43.54 Turn Around Clearing ‐ NS‐MSS_C 66FL1NS MSS 599.58 65.00 41,969,982.42 25,728,087.25 42.67 140.00 5.07 16.64 Naphtha Splitter CCR‐MSS_C 66FL2CR Turn Around Clearing ‐ CCR MSS 4,104.09 65.00 287,281,188.43 176,106,709.04 42.67 140.00 13.27 43.54 Turn Around Clearing ‐ NS‐MSS_C 66FL2NS MSS 599.58 65.00 41,969,982.42 25,728,087.25 42.67 140.00 5.07 16.64 Naphtha Splitter CCR‐MSS_C 66FL3CR Turn Around Clearing ‐ CCR MSS 4,104.09 65.00 287,281,188.43 176,106,709.04 42.67 140.00 13.27 43.54 Turn Around Clearing ‐ NS‐MSS_C 66FL3NS MSS 599.58 65.00 41,969,982.42 25,728,087.25 42.67 140.00 5.07 16.64 Naphtha Splitter CCR‐MSS_C 66FL12CR Turn Around Clearing ‐ CCR MSS 4,104.09 65.00 287,281,188.43 176,106,709.04 60.96 200.00 13.27 43.54 Turn Around Clearing ‐ NS‐MSS_C 66FL12NS MSS 599.58 65.00 41,969,982.42 25,728,087.25 60.96 200.00 5.07 16.64 Naphtha Splitter

Notes: 1. The equations to calculate the effective flare diameter were obtained from the TCEQʹs Air Quality Modeling Guidelines, APDG 6232, Revised November 2019:

Example Calculations for CCR‐MSS_C: Gross Heat Release (cal/sec) = Fuel Heat Input (MMBtu/hr) * 10^6 * 252 (cal/Btu) / 3600 (sec/hr) Gross Heat Release = 4,104.09 (MMbtu/hr) * 10^6 * 252 (cal/Btu) / 3600 (sec/hr) = 287,285,976.53 (cal/sec)

qn = q * ( 1 ‐ 0.048 * SQRT ( MW )) Net Heat Release (cal/sec) = 287,285,976.53 (cal/sec) * (1 ‐ 0.048 * (65.00^0.5 (lb/lb‐mol))) = 176,109,644.20 (cal/sec)

Diameter = SQRT ( qn * 10‐6 ) Diameter (m) = (176,109,644.20 (cal/sec) * 10^‐6)^0.5 = 13.27 (m)

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 1‐1

Figure A-1 Receptor Plot for Preliminary Impacts Determination

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL

APPENDIX B: PSD NAAQS ANALYSIS DOCUMENTATION

• Table B-1: PSD NAAQS Preliminary Impacts Determination Point Source Parameters; and • Table B-2: PSD NAAQS Preliminary Impacts Determination Area Source Parameters.

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL Table B‐1 PSD NAAQS Preliminary Impacts Determination Point Source Parameters Phillips 66 Borger Refinery PSD Permit Air Quality Analysis

EPN Source ID Source Description Stack Release Easting Northing Base Modeled Release Temperature Exit Velocity Stack Diameter Type NAD83 (X) NAD83 (Y) Elevation Height (m) (m) (m) (m) (ft) (°F) (K) (m/s) (fps) (m) (ft) CCR‐MSS_C 66FL1CR Turn Around Clearing ‐ CCR (Flare) DEFAULT 286,360.00 3,953,654.00 919.91 42.67 139.99 1831.73 1273.00 20.00 65.62 13.27 43.54 NS‐MSS_C 66FL1NS Turn Around Clearing ‐ Naphtha Splitter (Flare) DEFAULT 286,360.00 3,953,654.00 919.91 42.67 139.99 1831.73 1273.00 20.00 65.62 5.07 16.64 CCR‐MSS_C 66FL2CR Turn Around Clearing ‐ CCR (Flare) DEFAULT 286,226.00 3,953,655.00 914.38 42.67 139.99 1831.73 1273.00 20.00 65.62 13.27 43.54 NS‐MSS_C 66FL2NS Turn Around Clearing ‐ Naphtha Splitter (Flare) DEFAULT 286,226.00 3,953,655.00 914.38 42.67 139.99 1831.73 1273.00 20.00 65.62 5.07 16.64 CCR‐MSS_C 66FL3CR Turn Around Clearing ‐ CCR (Flare) DEFAULT 285,577.00 3,953,312.00 908.11 42.67 139.99 1831.73 1273.00 20.00 65.62 13.27 43.54 NS‐MSS_C 66FL3NS Turn Around Clearing ‐ Naphtha Splitter (Flare) DEFAULT 285,577.00 3,953,312.00 908.11 42.67 139.99 1831.73 1273.00 20.00 65.62 5.07 16.64 CCR‐MSS_C 66FL12CR Turn Around Clearing ‐ CCR (Flare) DEFAULT 285,378.00 3,953,348.00 911.27 60.96 200.00 1831.73 1273.00 20.00 65.62 13.27 43.54 NS‐MSS_C 66FL12NS Turn Around Clearing ‐ Naphtha Splitter (Flare) DEFAULT 285,378.00 3,953,348.00 911.27 60.96 200.00 1831.73 1273.00 20.00 65.62 5.07 16.64 28‐H3 28_H3 Crude Charge Furnace DEFAULT 286,410.00 3,953,589.00 923.10 29.23 95.90 330.01 438.71 4.57 15.00 2.73 8.96 28‐H3 MSS 28_H3MSS Crude Charge Furnace MSS DEFAULT 286,410.00 3,953,589.00 923.10 29.23 95.90 330.01 438.71 4.57 15.00 2.73 8.96 28‐H4 28_H4 Crude Charge Furnace DEFAULT 286,410.00 3,953,578.00 923.44 29.23 95.90 330.01 438.71 4.57 15.00 2.73 8.96 28‐H4 MSS 28_H4MSS Crude Charge Furnace MSS DEFAULT 286,410.00 3,953,578.00 923.44 29.23 95.90 330.01 438.71 4.57 15.00 2.73 8.96 88‐H1 88_H1 CCR Charger and Interheaters DEFAULT 286,496.00 3,953,440.00 928.18 57.91 189.99 469.99 516.48 8.84 29.00 2.13 6.99 88‐H1 MSS 88_H1MSS CCR Charger and Interheaters MSS DEFAULT 286,496.00 3,953,440.00 928.18 57.91 189.99 469.99 516.48 8.84 29.00 2.13 6.99 88‐V1 88_V1 CCR Vent DEFAULT 286,496.00 3,953,479.00 926.86 36.88 121.00 100.00 310.93 4.72 15.49 0.24 0.79 50CDV1 50CDV1 Coker Drum Vent 1 DEFAULT 286,302.00 3,952,947.00 929.09 17.05 55.93 212.00 373.15 55.93 183.50 0.20 0.67 50CDV2 50CDV2 Coker Drum Vent 2 DEFAULT 286,298.00 3,952,938.00 929.04 17.05 55.93 212.00 373.15 55.93 183.50 0.20 0.67 40H3 40H3 Unit 40 Superheater DEFAULT 285,950.00 3,953,027.00 926.65 24.72 81.10 744.00 668.71 9.33 30.60 1.28 4.20 NHT‐3 NHT_3 Pump Engine DEFAULT 285,863.00 3,953,956.00 894.03 1.13 3.70 980.00 799.82 89.61 294.00 0.10 0.33 40H4 40H4 Unit 40 Preheater Furnace DEFAULT 286,035.00 3,953,137.00 924.13 39.62 130.00 530.00 549.82 7.62 25.00 2.29 7.50 40H4 ‐ MSS 40H4_MSS Unit 40 Preheater Furnace DEFAULT 286,035.00 3,953,137.00 924.13 39.62 130.00 530.00 549.82 7.62 25.00 2.29 7.50 ENGSD‐6 ENGSD_6 Diesel Pump Engine DEFAULT 286,168.00 3,953,759.00 903.10 1.13 3.70 730.00 660.93 69.19 227.00 0.10 0.33 ENGSD‐7 ENGSD_7 Diesel Pump Engine DEFAULT 286,168.00 3,953,759.00 903.10 1.13 3.70 730.00 660.93 69.19 227.00 0.10 0.33 ENGSD‐8 ENGSD_8 Diesel Pump Engine DEFAULT 286,168.00 3,953,759.00 903.10 1.34 4.40 1076.00 853.15 46.63 153.00 0.10 0.33 MSS‐U41 MSS_U41 Unit 41 Hydrogen Plant and PSA Startup Venting DEFAULT 286,011.00 3,952,826.00 929.29 36.58 120.00 110.00 316.48 65.65 215.40 0.46 1.50 CT5 CT5 Cooling Tower DEFAULT 286,065.12 3,952,552.72 929.20 30.00 98.43 ‐459.67 0.00 4.25 13.94 6.00 19.69 81B17 81B17 Boiler 2.4 DEFAULT 286,164.00 3,952,984.00 924.45 19.81 65.00 320.00 433.15 55.78 183.00 1.22 4.00 9H1 9H1 19.2 Platformer Charge Heater DEFAULT 286,304.18 3,953,540.19 923.83 25.79 84.60 330.01 438.71 5.37 17.60 2.03 6.66 10H1 10H1 Crude Unit Charge Heater DEFAULT 286,404.18 3,953,539.19 924.10 28.47 93.40 344.75 446.90 3.41 11.20 2.36 7.75 28H1 28H1 Crude Unit Heater 2‐B DEFAULT 286,337.18 3,953,570.19 923.91 29.23 95.90 330.01 438.71 4.57 15.00 2.73 8.96 19B1/19H1 19B1_H1 Charge Furnace DEFAULT 286,240.00 3,953,442.00 919.71 30.48 100.00 330.01 438.71 21.64 71.00 1.41 4.63 19B1/19H2 19B1_H2 #2/#3 Reheater DEFAULT 286,239.00 3,953,453.00 919.89 30.48 100.00 330.01 438.71 21.64 71.00 1.41 4.63 19H5 19H5 No. 1 Reboiler/No. 2 Reboiler DEFAULT 286,249.17 3,953,336.19 919.80 15.00 49.20 649.99 616.48 6.25 20.50 0.82 2.69 19H6 19H6 #1 Reheater DEFAULT 286,238.00 3,953,460.00 920.13 33.53 110.00 500.00 533.15 4.27 14.00 3.03 9.93 7H1‐4 7H1_4 Charge Furnace/Reheaters DEFAULT 285,395.16 3,953,042.19 923.47 44.84 147.10 330.01 438.71 4.51 14.80 2.06 6.75 7E1 7E1 Charge Furnace/Reheaters DEFAULT 285,429.16 3,953,082.19 921.89 16.30 53.48 500.00 533.15 4.02 13.18 0.30 1.00 7E2 7E2 Charge Furnace/Reheaters DEFAULT 285,425.16 3,953,082.19 922.05 16.30 53.48 500.00 533.15 4.02 13.18 0.30 1.00 7E3 7E3 Charge Furnace/Reheaters DEFAULT 285,420.16 3,953,082.19 922.22 16.30 53.48 500.00 533.15 4.02 13.18 0.30 1.00 7E4 7E4 Charge Furnace/Reheaters DEFAULT 285,416.16 3,953,082.19 922.37 16.30 53.48 500.00 533.15 4.02 13.18 0.30 1.00 7E5 7E5 Charge Furnace/Reheaters DEFAULT 285,411.16 3,953,082.19 922.54 16.30 53.48 500.00 533.15 4.02 13.18 0.30 1.00 7E6 7E6 Charge Furnace/Reheaters DEFAULT 285,407.16 3,953,082.19 922.68 16.30 53.48 500.00 533.15 4.02 13.18 0.30 1.00 50H1 50H1 Unit 50 Charge Heater DEFAULT 286,268.00 3,952,967.00 929.19 57.91 190.00 469.99 516.48 8.84 29.00 2.13 7.00 42H1 42H1 Unit 42 Reactor Chg Heater DEFAULT 286,043.16 3,952,536.18 929.42 46.02 151.00 325.00 435.93 20.12 66.00 0.82 2.70 42H2 42H2 Unit 42 Reactor Chg Heater DEFAULT 285,972.16 3,952,554.18 929.50 46.02 151.00 325.00 435.93 20.12 66.00 0.82 2.70

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 1‐3 Table B‐1 PSD NAAQS Preliminary Impacts Determination Point Source Parameters Phillips 66 Borger Refinery PSD Permit Air Quality Analysis

EPN Source ID Source Description Stack Release Easting Northing Base Modeled Release Temperature Exit Velocity Stack Diameter Type NAD83 (X) NAD83 (Y) Elevation Height (m) (m) (m) (m) (ft) (°F) (K) (m/s) (fps) (m) (ft) 42H3 42H3 Unit 42 Fract Feed Heater DEFAULT 285,972.16 3,952,575.18 929.52 52.24 171.40 325.00 435.93 5.97 19.60 0.66 2.17 19H3 19H3 19.1 Naphtha HDS Chg Htr DEFAULT 286,238.00 3,953,414.00 919.53 30.50 100.07 500.00 533.15 4.94 16.20 2.26 7.40 29H4 29H4 Unit 29 DeC4 Reboiler DEFAULT 285,971.17 3,952,912.19 926.08 41.15 135.00 403.00 479.26 6.10 20.00 1.60 5.25 2H1 2H1 HDS Unit Charge Heater DEFAULT 285,373.16 3,953,033.19 923.44 30.48 100.00 500.00 533.15 4.72 15.50 1.44 4.71 2H2 2H2 DeOiler Charge Heater DEFAULT 285,783.16 3,952,891.19 927.55 20.88 68.50 450.00 505.37 3.75 12.30 1.52 5.00 4H1 4H1 Butamer Furnace DEFAULT 285,772.17 3,953,012.19 925.29 13.36 43.83 500.00 533.15 5.09 16.70 1.07 3.50 4H2 4H2 Butamer Regen Furnace DEFAULT 285,779.17 3,953,016.19 925.51 10.82 35.50 500.00 533.15 2.26 7.40 0.61 2.00 5H1 5H1 SRI Feed Heater A DEFAULT 285,758.17 3,953,012.19 924.98 13.36 43.83 500.00 533.15 3.57 11.70 1.07 3.50 5H3 5H3 SRI Feed Heater B DEFAULT 285,763.17 3,953,012.19 925.09 13.70 44.95 680.81 633.60 1.90 6.23 1.10 3.61 5H4 5H4 SRI Feed Heater C DEFAULT 285,767.17 3,953,012.19 925.18 13.70 44.95 688.73 638.00 2.00 6.56 1.10 3.61 6H1 6H1 ULACH Heater DEFAULT 285,375.16 3,953,004.19 923.27 15.24 50.00 500.00 533.15 3.90 12.80 0.69 2.25 6H3 6H3 C6 Dryer Regen Furnace DEFAULT 285,381.16 3,953,005.19 923.29 9.40 30.83 500.00 533.15 2.04 6.70 0.99 3.25 12H1 12H1 Regen Gas Furnace DEFAULT 285,813.16 3,952,672.18 933.62 13.11 43.00 500.00 533.15 2.20 7.20 0.53 1.75 26H1 26H1 DeC4 Reboiler DEFAULT 286,345.17 3,953,292.19 925.35 21.34 70.00 385.00 469.26 8.32 27.30 1.29 4.22 41H1 41H1 Unit 41 Reformer Furnace DEFAULT 286,005.00 3,952,800.00 929.54 45.72 150.00 325.00 435.93 55.78 183.00 2.43 7.96 50HT1 50HT1 Coker Heater Tank 1 DEFAULT 286,760.82 3,954,349.94 908.19 9.14 30.00 150.01 338.71 0.32 1.06 0.46 1.50 50HT2 50HT2 Coker Heater Tank 1 DEFAULT 286,764.75 3,954,349.69 908.19 9.14 30.00 150.01 338.71 0.32 1.06 0.46 1.50 50HT3 50HT3 Coker Heater Tank 1 DEFAULT 286,768.41 3,954,349.44 908.20 9.14 30.00 150.01 338.71 0.32 1.06 0.46 1.50 51H1 51H1 Charge Heater ‐ Vacuum Unit DEFAULT 286,416.00 3,953,058.00 929.20 57.91 190.00 390.00 472.04 8.57 28.10 2.29 7.50 98H1 98H1 SMR Charge Heater DEFAULT 285,933.00 3,952,599.00 930.12 39.62 130.00 375.01 463.71 15.85 52.00 1.98 6.50 19B2/19H4 19B2/19H4 Fractionator Feed Furnace DEFAULT 286,235.00 3,953,320.00 919.40 19.66 64.50 330.00 438.71 20.57 67.50 1.22 4.00 29P1 29P1 Unit 29 FCCU Stack DEFAULT 285,958.00 3,952,884.00 926.54 53.64 176.00 559.99 566.48 12.53 41.10 2.44 8.00 40P1 40P1 Unit 40 FCCU Stack DEFAULT 285,926.00 3,953,098.00 928.11 53.64 176.00 460.00 510.93 14.05 46.10 2.74 9.00 40H1 40H1 Unit 40 Heater DEFAULT 285,963.17 3,953,024.19 926.47 33.80 110.89 833.00 718.15 11.28 37.00 1.05 3.46 36H1 36H1 HDS Unit Charge Heater DEFAULT 286,367.18 3,953,569.19 923.80 27.43 90.00 500.00 533.15 5.24 17.20 1.52 5.00 22H1 22H1 Alky Reboiler Furnace DEFAULT 286,233.17 3,953,165.19 923.14 9.14 30.00 500.00 533.15 4.42 14.50 1.07 3.50 12E1 12E1 Gas Engine #41 DEFAULT 285,865.16 3,952,665.18 932.32 16.31 53.50 500.00 533.15 11.53 37.81 0.30 1.00 12E2 12E2 Gas Engine #42 DEFAULT 285,871.16 3,952,665.18 932.22 16.31 53.50 500.00 533.15 11.53 37.81 0.30 1.00 12E3 12E3 Gas Engine #43 DEFAULT 285,878.16 3,952,665.18 932.05 16.31 53.50 500.00 533.15 11.53 37.81 0.30 1.00 12E4 12E4 Gas Engine #44 DEFAULT 285,884.16 3,952,664.18 931.94 16.31 53.50 500.00 533.15 11.53 37.81 0.30 1.00 12E5 12E5 Gas Engine #45 DEFAULT 285,890.16 3,952,664.18 931.80 16.31 53.50 500.00 533.15 11.53 37.81 0.30 1.00 12E6 12E6 Gas Engine #46 DEFAULT 285,892.16 3,952,658.18 931.93 16.31 53.50 500.00 533.15 9.61 31.51 0.30 1.00 12E7 12E7 Gas Engine #47 DEFAULT 285,898.16 3,952,658.18 931.75 16.31 53.50 500.00 533.15 9.61 31.51 0.30 1.00 93E1 93E1 Gas Engine #37 DEFAULT 285,882.16 3,952,503.18 933.55 14.00 45.93 500.00 533.15 0.49 1.60 0.61 2.00 93E2 93E2 Gas Engine #38 DEFAULT 285,882.16 3,952,512.18 933.52 14.00 45.93 500.00 533.15 0.49 1.60 0.61 2.00 F‐50A F_50A Coke Handling DEFAULT 286,072.48 3,952,730.68 929.54 1.00 3.28 ‐459.67 0.00 0.001 0.003 0.001 0.003 KG47 KG47 Tank‐Sulfur Storage Tank DEFAULT 286,168.36 3,952,686.93 929.53 10.67 35.00 ‐459.67 0.00 0.001 0.003 0.001 0.003 34I1 34I1 SRU DEFAULT 285,740.16 3,952,696.19 933.91 60.96 200.00 847.99 726.48 4.94 16.20 1.22 4.00 43I1 43I1 SRU DEFAULT 286,145.17 3,952,814.18 929.43 45.72 150.00 350.01 449.82 18.29 60.00 1.07 3.50 VF‐1030 VF_1030 PAC Silo DEFAULT 287,947.21 3,953,556.54 860.11 13.29 43.60 ‐459.67 0.00 0.001 0.003 0.001 0.003 VF‐2030 VF_2030 PAC Silo DEFAULT 287,964.00 3,953,557.00 860.13 13.29 43.60 ‐459.67 0.00 0.001 0.003 0.001 0.003 85B2 85B2 Unit 40 Boiler DEFAULT 285,930.17 3,953,146.19 928.28 65.00 213.25 390.00 472.04 10.59 34.74 3.58 11.75 0310 0310 T‐310 Sulfur Loading Tank Final Rates DEFAULT 285,686.09 3,952,431.71 936.23 7.32 24.00 ‐459.67 0.00 0.0010 0.0033 0.001 0.003 0309 0309 T‐309 Sulfur Loading Tank Final Rates DEFAULT 285,666.73 3,952,433.31 935.81 7.32 24.00 ‐459.67 0.00 0.0010 0.0033 0.001 0.003

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 2‐3 Table B‐1 PSD NAAQS Preliminary Impacts Determination Point Source Parameters Phillips 66 Borger Refinery PSD Permit Air Quality Analysis

EPN Source ID Source Description Stack Release Easting Northing Base Modeled Release Temperature Exit Velocity Stack Diameter Type NAD83 (X) NAD83 (Y) Elevation Height (m) (m) (m) (m) (ft) (°F) (K) (m/s) (fps) (m) (ft) BLR12 BLR12 Boiler 12 DEFAULT 285,927.00 3,952,878.00 926.81 39.62 130.00 300.00 422.04 18.29 60.00 2.44 8.00 SKDBLR SKDBLR Skid Boiler DEFAULT 285,891.61 3,952,883.70 927.40 23.65 77.60 291.99 417.59 14.02 46.00 2.74 9.00 53FL1 53FL1 Loading Thermal Oxidizer DEFAULT 285,788.00 3,952,184.00 935.91 57.91 190.00 1400.00 1033.15 7.62 25.00 2.44 8.00

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 3‐3 Table B‐2 PSD NAAQS Preliminary Impacts Determination Area Source Parameters Phillips 66 Borger Refinery PSD Permit Air Quality Analysis

EPN Source ID Source DescriptionSW Corner Easting SW Corner Northing Base Modeled Release Easterly Northerly Angle NAD83 (X) NAD83 (Y) Elevation Height Length Length from (m) (m) (m) (m) (ft) (m) (ft) (m) (ft) North 53R4 53R4 Sulfur Loading 285,628.00 3,952,411.00 934.08 2.29 7.50 60.00 196.85 17.00 55.77 50.00

PHILLIPS 66 BORGER REFINERY PSD AIR QUALITY ANALYSIS PROTOCOL 1‐1