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Permit 4682B Amendment 1501 McKinzie Road Corpus Christi, Texas 78410 Air Permit Amendment Application, the Executive Director’s Preliminary Decision, the Executive Director’s Preliminary Determination Summary and the Executive Director’s Air quality Analysis
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Page 1: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Permit 4682B Amendment

1501 McKinzie Road Corpus Christi, Texas 78410

Air Permit Amendment Application, the Executive Director’s Preliminary Decision, the Executive Director’s Preliminary Determination Summary and the Executive

Director’s Air quality Analysis

Page 2: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

rpsgroup.com

PERMIT 4682B AMENDMENT EQUISTAR CHEMICALS, LP RN100221662 CN600124705

Document Contains Confidential Information

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.

Equistar Chemicals, LP RN100221662 CN600124705

December 2019

Page 3: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

PERMIT 4682B AMENDMENT

Equistar Chemicals, LP | RN100221662 | CN600124705 | December 2019

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Contents 1 INTRODUCTION .................................................................................................................................. 2

1.1 Purpose of This Application ........................................................................................................ 2 1.2 How This Application is Organized ............................................................................................. 2

2 ADMINISTRATIVE FORMS ................................................................................................................. 5

3 AREA MAP AND PLOT PLAN ............................................................................................................. 6

4 PROCESS DESCRIPTION ................................................................................................................... 9

5 EMISSION CALCULATIONS ............................................................................................................. 10 5.1 Criteria Pollutants ..................................................................................................................... 10 5.2 Greenhouse Gases ................................................................................................................... 10

6 BEST AVAILABLE CONTROL TECHNOLOGY ................................................................................ 11 6.1 Criteria Pollutants ..................................................................................................................... 11 6.2 Greenhouse Gases ................................................................................................................... 12

7 FEDERAL PERMITTING REVIEW ..................................................................................................... 14

8 PERMIT BY RULE INCORPORATION .............................................................................................. 15

9 GENERAL APPLICATION REQUIREMENTS ................................................................................... 17

Tables

Table 1-1 Project Emission Summary ......................................................................................................... 4 Table 7-1 PSD Applicability Analysis Summary ........................................................................................ 14 Table 8-1 Permit by Rule Incorporation Summary .................................................................................... 15

Figures

Figure 3-1 Area Map .................................................................................................................................... 7 Figure 3-2 Plot Plan ..................................................................................................................................... 8

Appendices

APPENDIX A Emission Calculations (Confidential) APPENDIX B Federal Permitting Tables APPENDIX C RBLC Search Results

Page 4: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

PERMIT 4682B AMENDMENT

Equistar Chemicals, LP | RN100221662 | CN600124705 | December 2019

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1 INTRODUCTION

Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical manufacturing facility consists of the Olefins and Aromatics Unit. There is also a cogeneration facility that supplies electricity and steam at the site authorized under Permit No. 18358. The Olefins and Aromatics Unit is commonly referred to as the Olefins Plant. The facility is authorized under Permit No. 4682B/PSDTX761M3, Title V Permit No. O1486, and various Standard Permit and Permit by Rule (PBR) authorizations. The maintenance, startup, and shutdown (MSS) activities associated with the Olefins Plant are authorized under Permit No. 83864. Greenhouse gas (GHG) emissions that were part of a 2015 expansion project are authorized under EPA-issued Permit No. PSD-TX-761-GHG (TCEQ GHG Permit No. GHGPSDTX32).

1.1 Purpose of This Application The purpose of this application is to authorize flare emission increases needed to meet the net heating value in the combustion zone (NHVcz) targets. On September 5, 2019, EPA Administrator Andrew Wheeler signed a notice1 that addressed proposed changes to the 40 CFR 63 Subpart YY—National Emission Standards for Hazardous Air Pollutants for Source Categories: Generic Maximum Achievable Control Technology Standards for Ethylene Production. The EPA is proposing several rule changes as a result of its risk and technology review (RTR) for the Ethylene Production source category. The Agency is under a court-ordered deadline2 to finalize the RTR by March 13, 2020. The proposed new Ethylene Production MACT rules for flare performance are expected to mirror the flare rules found in the Refinery MACT subpart CC. The rules will require ethylene production units to maintain a minimum of 270 British thermal unit per standard cubic foot (BTU/scf) NHVcz to ensure proper combustion efficiency. Per information from the EPA, the rules will be the same as the flare rules found in 40 CFR 63.670, “Requirements for flare control devices”. Additionally, the flares in this permit amendment are part of an EPA flare enforcement initiative involving the site. EPA has requested that the flares meet NHVcz expeditiously. This project only seeks to authorize additional supplemental BTU content in the form of plant fuel gas that will need to be added to the flare vent gas to keep the heating value in the combustion zone above the EPA mandated 270 BTU/scf and does not add additional production capacity or modify the operating facility. This project does not impact MSS emissions currently authorized under Permit No. 83864; no additional MSS emissions are associated with this project.

As part of this project Equistar is also proposing to consolidate PBR and Standard Permit authorizations into Permit 4682B as required. Section 8 of this application addresses the requirements associated with PBR and Standard Permit incorporations.

Table 1-1 at the end of this Section presents the currently authorized and proposed emissions for EPNs 10 and 11.

1.2 How This Application is Organized This application is organized into the following sections:

Section 1 presents the application objectives and organization;

Section 2 contains TCEQ administrative information including Form PI-1, Form APD-EXP, and Form APD-APS;

Section 3 contains an Area Map and a Plot Plan for the Facility;

1 https://www.epa.gov/sites/production/files/2019-09/documents/frn_ethylene_production_rtr_nprm_signature_pkg.pdf [accessed

11/20/2019]

2 https://www.courthousenews.com/wp-content/uploads/2017/03/EPA-ruling.pdf [accessed 11/20/2019]

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PERMIT 4682B AMENDMENT

Equistar Chemicals, LP | RN100221662 | CN600124705 | December 2019

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Section 4 contains a process description for the project sources;

Section 5 describes the emission calculation methods used to estimate the emissions rates for the facilities included in this application;

Section 6 presents the BACT analysis for the facilities included in this application;

Section 7 addresses the applicability of federal NNSR and PSD permitting requirements;

Section 8 addresses the requirements associated with incorporating PBR and Standard Permit authorizations into Permit 4682B;

Section 9 presents the General Application Requirements that address the applicability for state and federal air regulations for the facilities included in this application;

Appendix A contains detailed emissions calculations for project sources;

Appendix B contains Federal NSR Tables; and

Appendix C contains RBLC Search Results.

Page 6: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Currently Authorized Permit 4682B

CO2e

lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy metric tpy

10 209.76 8.21 1092.65 37.00 369.22 6.94 64.68 2.51

11 19.39 2.92 100.84 13.84 76.88 2.61 0.08 0.13

Currently Authorized PBR 131202

CO2e

lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy metric tpy

10 0 0 0 0 0 0 0 0

11 0 0 0 0 0 3.00 0 0

Currently Authorized Standard Permit 136589

CO2e

lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy metric tpy

10 0.68 2.97 4.90 21.46 0 0 0 0

11 0.97 4.23 6.97 30.55 0 0 0 0

Total Currently Authorized by 4682B / 131202 / 136589CO2e

lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy metric tpy

10 210.44 11.18 1097.55 58.46 369.22 6.94 64.68 2.51

11 20.36 7.15 107.81 44.39 76.88 5.61 0.08 0.13

Proposed Emission Increase for this Permit Amendment CO2e

lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy metric tpy

10 0.00 12.99 0.00 93.78 0.00 9.08 0.00 0.15 48,958

11 0.00 11.66 0.00 84.21 0.00 9.04 0.00 0.15 48,752

Proposed Post-Project Permit 4682B LimitsCO2e*

lb/hr tpy lb/hr tpy lb/hr tpy lb/hr tpy metric tpy

10 210.44 24.17 1097.55 152.24 369.22 16.02 64.68 2.66 48,958

11 20.36 18.81 107.81 128.60 76.88 14.65 0.08 0.28 48,752

* consistent with previous GHG permit updates issued by TCEQ, the proposed emissions reflect the project increase only existing GHG emissions are not currently quantified in a GHG authorziation.

Table 1-1Project Emission Summary

EPNNOx CO VOC SO2

EPNNOx CO VOC SO2

EPNNOx CO VOC SO2

Note that the issuance letter for Standard Permit 136589 dated June 6, 2019 reflects the 4682B emissions plus the Standard Permit changes summarized in this table.

EPNNOx CO VOC SO2

EPNNOx CO VOC SO2

EPNNOx CO VOC SO2

Page 7: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

PERMIT 4682B AMENDMENT

Equistar Chemicals, LP | RN100221662 | CN600124705 | December 2019

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2 ADMINISTRATIVE FORMS

This section contains the following TCEQ forms:

Form PI-1, General Application for Air Preconstruction Permits and Amendments;

Form APD-EXP, Expedited Permitting Request Form; and

Form APD-APS, Air Permitting Surcharge Payment Form.

In accordance with 30 TAC §116.141, the permit fee is determined from the capital cost associated with any modifications of existing sources or the installation of any new emission sources. Therefore, based upon the capital cost associated with this permit application, a fee of $3,000 is required. Equistar is requesting expedited review of the permit application and has included a $20,000 surcharge associated with Federal NSR permitting.

Please note that all modifications represented in the amendment application received under PI-1, March 1, 2013 are completed; therefore, all MAERT items with footnote (13) are no longer relevant. The enclosed PI-1 workbook does not reflect these MAERT entries. Similarly, footnote (11) is no longer relevant therefore the enclosed PI-1 workbook does not reflect these MAERT entries either.

Page 8: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Texas Commission on Environmental Quality

Form PI-1 General ApplicationGeneral

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

I agree

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 column width, I have not changed the TCEQ application workbook in any way, including but not limited to changing formulas, formatting, content, or protections.

https://www.sos.state.tx.us

Environmental Engineer

Mailing Address:

Prefix (Mr., Ms., Dr., etc.): Mr.

78460-0940Telephone Number:

TX

Equistar Chemicals, LP

Email Address: [email protected]

Address Line 2:

PetersTitle:

State:

361-242-8075Fax Number:

Equistar Chemicals LP

Mailing Address: P.O. Box 10940

City:

ZIP Code:

Corpus Christi

Last Name:

City: Corpus ChristiState: TX

Company or Legal Name:

I. Applicant Information

Texas Secretary of State Charter/Registration Number (if given):

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.

A. Company Information

B. Company Official Contact Information: must not be a consultantPrefix (Mr., Ms., Dr., etc.): Ms.First Name: Alicia R.Last Name: MatusTitle: CCO Site Manager

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:

Company or Legal Name:

361-242-5028

D. Assigned Numbers

CN600124705Enter 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 is affiliated with a regulated entity.

Telephone Number:Fax Number:Email Address: [email protected]

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.

361-242-8030

ZIP Code: 78460-0940

First Name: H. Scott

P.O. Box 10940Address Line 2:

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationGeneral

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

No

HAP Major Source [FCAA § 112(g)]: Not applicable, Initial, Major Modification

PAL: Not applicable, Initial, Amendment, Renewal, Renewal/Amendment, Alteration

GHG PSD: Not applicable, Initial, Major Modification, Voluntary Update

Not applicable

Major Modification

Not applicable

Permit Number (if assigned)

PSD-TX-761-GHG (TCEQ No. GHGPSDTX32)

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 RN for portable units is assigned to the unit itself, and that same RN should be used when applying for authorization at a different location.

This cell intentionally left blank

Not applicable

II. Delinquent Fees and Penalties

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Minor NSR (can be a Title V major source): Not applicable, Initial, Amendment, Renewal, Renewal Certification, Renewal/Amendment, Relocation/Alteration, Change of Location, Alteration, Extension to Start of Construction

Additional information regarding the different NSR authorizations can be found at:

RN100221662

Nonattainment: Not applicable, Initial, Major Modification

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

Not applicable

Action Type Requested(do not leave blank)

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 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

Major Modification

4682B

PSDTX761M3

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.

https://www.tceq.texas.gov/permitting/air/guidance/authorize.html

Amendment

Permit Type

A. Permit and Action Type (multiple may be selected, leave no blanks)

Special Permit: Not applicable, Amendment, Renewal, Renewal Certification, Renewal/Amendment, Alteration, Extension to Start of Construction

III. Permit Information

De Minimis: Not applicable, Initial Not applicable

Not applicable

PSD: Not applicable, Initial, Major Modification

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationGeneral

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

No

No

Yes

No

Is this facility located at a site required to obtain a site operating permit (SOP) or general operating permit (GOP)?

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

this application fully addresses the proposed project

How are/will MSS activities for sources associated with this project be authorized?

Another NSR permit

List the permit number, registration number, and/or PBR number.

Are there any standard permits, standard exemptions, or PBRs to be incorporated by reference?

Is a SOP or GOP review pending for this source, area, or site?

O1486

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 attached to this application at the time of submittal for any authorization to be incorporated by consolidation.

This cell intentionally left blank

B. MSS Activities

83864 (No MSS emissions associated with this permit application)

Will this permit be consolidated into another NSR permit with this action?

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

C. Consolidating NSR Permits

131202, 136589, 141992, 155067

D. Incorporation of Standard Permits, Standard Exemptions, and/or Permits By Rule (PBR)

If yes, list any PBR, standard exemptions, or standard permits that need to be consolidated:

E. Associated Federal Operating Permits

GHG projects: List the non-GHG applications (pending or being submitted) that are associated with the project. Note: All preconstruction authorizations (including authorization for emissions of greenhouse gases, if applicable) must be obtained prior to start of construction.

Yes

If yes, are emission calculations, BACT analysis, and an impacts analysis included for each authorization to be consolidated? If any required information is not provided, the authorization will be incorporated by reference.

Yes

Will NSR permits be consolidated into this permit with this action?

No

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationGeneral

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

No

attainment or unclassified for all pollutants

Permanent or portable facility?

B. General InformationSite Name:

Are there any schools located within 3,000 feet of the site boundary?

City: If the address is not located in a city, then enter the city or town closest to the facility, even if it is not in the same county as the facility.

ZIP Code: Include the ZIP Code of the physical facility site, not the ZIP Code of the applicant's mailing address.

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 prime meridian and will always be between 93 and 107 degrees west (W) in Texas.

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 equator and will always be between 25 and 37 degrees north (N) in Texas.

C. Portable FacilityPermanent

Nueces

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. Vague names such as Chemical Plant are not acceptable.

County attainment status as of Sept. 23, 2019

Is this a project for a lead smelter, concrete crushing facility, and/or a hazardous waste management facility?

County: Enter the county where the facility is physically located.

Olefins Plant

78410

Street Address:

097:35:37

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.

A. LocationIV. Facility Location and General Information

TCEQ Region Region 14

027:48:36

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.

D. Industry TypePetrochemical

1501 McKinzie Road

No

Corpus Christi Complex

Corpus Christi

Principal Company Product/Business:

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationGeneral

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Yes

No

Yes

YesYes

No

D. Operating Schedule

Projected Start of Construction:

If yes, did you attach copies of any correspondence from the agency and provide the RN associated with the investigation, notice of violation, or enforcement action?

325110Principal NAICS code:

https://www.tceq.texas.gov/permitting/air/confidential.htmlB. Is the Core Data Form (Form 10400) attached?

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)

State Senator:

NAICS codes and conversions between NAICS and SIC Codes are available at:

Juan "Chuy" Hinojosa

https://www.census.gov/eos/www/naics/

E. State Senator and Representative for this site

https://wrm.capitol.texas.gov/

This information can be found at (note, the website is not compatible to Internet Explorer):

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).

Will sources in this project be authorized to operate 8760 hours per year?

The purpose of this application is to authorize flare emission increases needed to meet the net heating value in the combustion zone (NHVcz) targets.

Is this application in response to, or related to, an agency investigation, notice of violation, or enforcement action?

Provide a brief description of the project that is requested. (Limited to 500 characters).

A list of SIC codes can be found at:

VI. Application Materials

https://www.tceq.texas.gov/assets/public/permitting/centralregistry/10400.docx

A. Confidential Application MaterialsIs confidential information submitted with this application?If yes, is each confidential page marked "CONFIDENTIAL" in large red letters?

https://www.naics.com/sic-codes-industry-drilldown/

C. Enforcement ProjectsProjected Start of Operation:

Abel Herrero

2869Principal SIC code:

District: 20

B. Project Timing

A. DescriptionV. Project Information

34District:State Representative:

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THSC §382.041 requires us not to disclose any information related to manufacturing processes that is marked Confidential. Mark any information related to secret or proprietary processes or methods of manufacture Confidential if you do not want this information in the public file. All confidential information should be separated from the application and submitted as a separate file. Additional information regarding confidential information can be found at:

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationGeneral

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Yes

Yes

Yes

Yes

Yes

N/A

Yes

Yes

Yes

Yes

N/A

N/A

N/A

Yes

No

N/AYes

H. Is a material balance (Table 2, Form 10155) attached?

C. Is a current area map attached?

Does the map show a 3,000-foot radius from the property boundary?

The owner or operator of the facility must apply for authority to construct. The appropriate company official (owner, plant manager, president, vice president, or environmental director) must sign all copies of the application. The applicant’s consultant cannot sign the application. Important Note: Signatures must be original in ink, not reproduced by photocopy, fax, or other means, and must be received before any permit is issued.

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 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.

Does the process description also explain how the facility or facilities will be operating when the maximum possible emissions are produced?

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, hospitals, day care centers, and churches?

VII. Signature

Are emission rates and associated calculations for planned MSS facilities and related activities attached?

J. Is a discussion of state regulatory requirements attached, addressing 30 TAC Chapters 101, 111, 112, 113, 115, and 117?For all applicable chapters, does the discussion include how the facility will comply with the requirements of the chapter?

For all not applicable chapters, does the discussion include why the chapter is not applicable?K. Are all other required tables, calculations, and descriptions attached?

I. Is a list of MSS activities attached?

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D. Is a plot plan attached?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?

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 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 currently authorized?

E. Is a process flow diagram attached?

F. Is a process description attached?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 emissions), and where the emissions enter the atmosphere?

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationGeneral

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Name:

Signature:

Date:

The signature below confirms that I have knowledge of the facts included in this application and that these facts are true and correct to the best of my knowledge and belief. I further state that to the best of my knowledge and belief, the project for which application is made will not in any way violate any provision of the Texas Water Code (TWC), Chapter 7; the Texas Health and Safety Code, Chapter 382; the Texas Clean Air Act (TCAA); the air quality rules of the Texas Commission on Environmental Quality; or any local governmental ordinance or resolution enacted pursuant to the TCAA. I further state that I understand my signature indicates that this application meets all applicable nonattainment, prevention of significant deterioration, or major source of hazardous air pollutant permitting requirements. The signature further signifies awareness that intentionally or knowingly making or causing to be made false material statements or representations in the application is a criminal offense subject to criminal penalties.

Original signature is required.

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationTechnical

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Yes

No

No

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B. Title 40 CFR Part 61

Does this project require an impacts analysis?

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IX. Emissions ReviewA. Impacts AnalysisAny 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.

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B. Disaster ReviewIf 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.pdfDoes this application involve any air contaminants for which a disaster review is required?

C. Air Pollutant Watch ListCertain 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.htmlIs the proposed facility located in a watch list area?

VIII. Federal Regulatory QuestionsIndicate if any of the following requirements apply to the proposed facility. Note that some federal regulations apply to minor sources. Enter all applicable Subparts.

List applicable subparts you will demonstrate compliance with (e.g. Subpart VVVV)

Subpart A

Do MACT subpart(s) apply to a facility in this application?

Yes

A. Title 40 CFR Part 60Do NSPS subpart(s) apply to a facility in this application?

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Do NESHAP subpart(s) apply to a facility in this application?

No

C. Title 40 CFR Part 63

Yes

List applicable subparts you will demonstrate compliance with (e.g. Subpart M)

Subpart A

I. Additional Questions for Specific NSR Minor Permit Actions

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Version 4.0 Page 1

Page 16: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Texas Commission on Environmental Quality

Form PI-1 General ApplicationTechnical

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

No

Is this project for a bulk fuel terminal?

Is this facility located at a site within the Houston/Galveston nonattainment area (Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties)?

D. Mass Emissions Cap and Trade

A. Bulk Fuel Terminals

B. Plant Fuel Gas Facilities

No

YesDoes this site utilize plant fuel gas?

X. Additional RequirementsThis cell intentionally left blank

Version 4.0 Page 2

Page 17: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Texas Commission on Environmental Quality

Form PI-1 General ApplicationUnit Types - Emission Rates

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Action Requested (only 1 action per FIN)

Include these emissions in annual (tpy) summary?

Facility ID Number (FIN)

Emission Point Number (EPN) Source Name Pollutant

Current Short-Term (lb/hr)

Current Long-Term (tpy)

ConsolidatedCurrent Short-Term (lb/hr)

Consolidated Current Long-Term (tpy)

Proposed Short-Term (lb/hr)

Proposed Long-Term (tpy)

Short-Term Difference (lb/hr)

Long-Term Difference (tpy)

Unit Type (Used for reviewing BACT and Monitoring Requirements)

Unit Type Notes (only if "other" unit type in Column O)

Not New/Modified Yes B-1601A 1A USC Furnace A CO 6.74 29.52 6.74 29.52 0 0 FurnaceNOx 11.28 49.41 11.28 49.41 0 0PM 0.94 4.12 0.94 4.12 0 0PM2.5 0.94 4.12 0.94 4.12 0 0PM10 0.94 4.12 0.94 4.12 0 0SO2 0.11 0.48 0.11 0.48 0 0VOC 1.01 4.44 1.01 4.44 0 0CO2 Equivalent 94303 94303 0 0CO2 93838 93838 0 0CH4 5.5 5.5 0 0N2O 1.1 1.1 0 0

Not New/Modified Yes B-1601B 1B USC Furnace B CO 6.74 29.52 6.74 29.52 0 0 FurnaceNOx 11.28 49.41 11.28 49.41 0 0PM 0.94 4.12 0.94 4.12 0 0PM2.5 0.94 4.12 0.94 4.12 0 0PM10 0.94 4.12 0.94 4.12 0 0SO2 0.11 0.48 0.11 0.48 0 0VOC 1.01 4.44 1.01 4.44 0 0CO2 Equivalent 94303 94303 0 0CO2 93838 93838 0 0CH4 5.5 5.5 0 0N2O 1.1 1.1 0 0

Not New/Modified Yes B-1601C 1C USC Furnace C CO 10.4 45.54 10.4 45.54 0 0 FurnaceNOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1601D 1D USC Furance D CO 10.4 45.54 10.4 45.54 0 0 FurnaceNOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1601E 1E USC Furance E CO 10.4 45.54 10.4 45.54 0 0 FurnaceNOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1601F 1F USC Furance F CO 10.4 45.54 10.4 45.54 0 0 FurnaceNOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1601G 1G USC Furance G CO 10.4 45.54 10.4 45.54 0 0 Furnace

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Chemical / EnergyPermit primary industry (must be selected for workbook to function)

Version 4.0 Page 1

Page 18: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Texas Commission on Environmental Quality

Form PI-1 General ApplicationUnit Types - Emission Rates

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Action Requested (only 1 action per FIN)

Include these emissions in annual (tpy) summary?

Facility ID Number (FIN)

Emission Point Number (EPN) Source Name Pollutant

Current Short-Term (lb/hr)

Current Long-Term (tpy)

ConsolidatedCurrent Short-Term (lb/hr)

Consolidated Current Long-Term (tpy)

Proposed Short-Term (lb/hr)

Proposed Long-Term (tpy)

Short-Term Difference (lb/hr)

Long-Term Difference (tpy)

Unit Type (Used for reviewing BACT and Monitoring Requirements)

Unit Type Notes (only if "other" unit type in Column O)

NOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1601H 1H USC Furance H CO 10.4 45.54 10.4 45.54 0 0 FurnaceNOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1601J 1J USC Furance J CO 10.4 45.54 10.4 45.54 0 0 FurnaceNOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1601K 1K USC Furnace K CO 6.74 29.52 6.74 29.52 0 0 FurnaceNOx 11.28 49.41 11.28 49.41 0 0PM 0.94 4.12 0.94 4.12 0 0PM2.5 0.94 4.12 0.94 4.12 0 0PM10 0.94 4.12 0.94 4.12 0 0SO2 0.11 0.48 0.11 0.48 0 0VOC 1.01 4.44 1.01 4.44 0 0CO2 Equivalent 94303 94303 0 0CO2 93838 93838 0 0CH4 5.5 5.5 0 0N2O 1.1 1.1 0 0

Not New/Modified Yes B-1601L 1L USC Furnace L CO 6.74 29.52 6.74 29.52 0 0 FurnaceNOx 11.28 49.41 11.28 49.41 0 0PM 0.94 4.12 0.94 4.12 0 0PM2.5 0.94 4.12 0.94 4.12 0 0PM10 0.94 4.12 0.94 4.12 0 0SO2 0.11 0.48 0.11 0.48 0 0VOC 1.01 4.44 1.01 4.44 0 0CO2 Equivalent 94303 94303 0 0CO2 93838 93838 0 0CH4 5.5 5.5 0 0N2O 1.1 1.1 0 0

Not New/Modified Yes B-1601M 1M USC Furance M CO 10.4 45.54 10.4 45.54 0 0 FurnaceNOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1601N 1N USC Furance N CO 10.4 45.54 10.4 45.54 0 0 FurnaceNOx 17.4 76.21 17.4 76.21 0 0PM 1.45 6.35 1.45 6.35 0 0PM2.5 1.45 6.35 1.45 6.35 0 0PM10 1.45 6.35 1.45 6.35 0 0

Version 4.0 Page 2

Page 19: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Texas Commission on Environmental Quality

Form PI-1 General ApplicationUnit Types - Emission Rates

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Action Requested (only 1 action per FIN)

Include these emissions in annual (tpy) summary?

Facility ID Number (FIN)

Emission Point Number (EPN) Source Name Pollutant

Current Short-Term (lb/hr)

Current Long-Term (tpy)

ConsolidatedCurrent Short-Term (lb/hr)

Consolidated Current Long-Term (tpy)

Proposed Short-Term (lb/hr)

Proposed Long-Term (tpy)

Short-Term Difference (lb/hr)

Long-Term Difference (tpy)

Unit Type (Used for reviewing BACT and Monitoring Requirements)

Unit Type Notes (only if "other" unit type in Column O)

SO2 0.17 0.75 0.17 0.75 0 0VOC 1.56 6.85 1.56 6.85 0 0CO2 Equivalent 145468 145468 0 0CO2 144751 144751 0 0CH4 8.4 8.4 0 0N2O 1.7 1.7 0 0

Not New/Modified Yes B-1602A 3A VMR Furnace A CO 4.54 19.89 4.54 19.89 0 0 FurnaceNOx 7.6 33.3 7.6 33.3 0 0PM 0.63 2.77 0.63 2.77 0 0PM2.5 0.63 2.77 0.63 2.77 0 0PM10 0.63 2.77 0.63 2.77 0 0SO2 0.07 0.33 0.07 0.33 0 0VOC 0.68 2.99 0.68 2.99 0 0CO2 Equivalent 63542 63542 0 0CO2 63241 63241 0 0CH4 3.7 3.7 0 0N2O 0.7 0.7 0 0

Not New/Modified Yes B-1602B 3B VMR Furnace B CO 4.54 19.89 4.54 19.89 0 0 FurnaceNOx 7.6 33.3 7.6 33.3 0 0PM 0.63 2.77 0.63 2.77 0 0PM2.5 0.63 2.77 0.63 2.77 0 0PM10 0.63 2.77 0.63 2.77 0 0SO2 0.07 0.33 0.07 0.33 0 0VOC 0.68 2.99 0.68 2.99 0 0CO2 Equivalent 63542 63542 0 0CO2 63241 63241 0 0CH4 3.7 3.7 0 0N2O 0.7 0.7 0 0

Not New/Modified Yes B-1603A 4A HP Steam Boiler A CO 23.65 103.59 23.65 103.59 0 0 Boiler: Liquid and Gas Fuel, > 40 MMBtu/hrNOx 94.63 414.46 94.63 414.46 0 0PM10 23.14 101.33 23.14 101.33 0 0SO2 284.48 1246.04 284.48 1246.04 0 0SO3 10.33 25.24 10.33 25.24 0 0VOC 1.56 6.78 1.56 6.78 0 0

Not New/Modified Yes B-1603B 4B HP Steam Boiler B CO 23.65 103.59 23.65 103.59 0 0 Boiler: Liquid and Gas Fuel, > 40 MMBtu/hrNOx 53.5 234.32 53.5 234.32 0 0PM10 2.14 9.37 2.14 9.37 0 0SO2 0.18 0.78 0.18 0.78 0 0VOC 1.56 6.78 1.56 6.78 0 0

Not New/Modified Yes B-1603C 4C HP Steam Boiler C CO 23.65 103.59 23.65 103.59 0 0 Boiler: Liquid and Gas Fuel, > 40 MMBtu/hrNOx 53.5 234.32 53.5 234.32 0 0PM10 2.14 9.37 2.14 9.37 0 0SO2 0.18 0.78 0.18 0.78 0 0VOC 1.56 6.78 1.56 6.78 0 0

Not New/Modified Yes B-1603D 4D HP Steam Boiler D CO 23.65 103.59 23.65 103.59 0 0 Boiler: Liquid and Gas Fuel, > 40 MMBtu/hrNOx 53.5 234.32 53.5 234.32 0 0PM10 2.14 9.37 2.14 9.37 0 0SO2 0.18 0.78 0.18 0.78 0 0VOC 1.56 6.78 1.56 6.78 0 0

Not New/Modified Yes B-1604A 5A Steam Superheater A CO 5.22 22.86 5.22 22.86 0 0 HeaterNOx 8.74 38.26 8.74 38.26 0 0PM 0.73 3.19 0.73 3.19 0 0PM2.5 0.73 3.19 0.73 3.19 0 0PM10 0.73 3.19 0.73 3.19 0 0SO2 0.09 0.38 0.09 0.38 0 0VOC 0.79 3.44 0.79 3.44 0 0CO2 Equivalent 73018 73018 0 0CO2 72675 72675 0 0CH4 4.2 4.2 0 0N2O 0.8 0.8 0 0

Not New/Modified Yes B-1604B 5B Steam Superheater B CO 5.22 22.86 5.22 22.86 0 0 Heater

NOx 8.74 38.26 8.74 38.26 0 0PM 0.73 3.19 0.73 3.19 0 0PM2.5 0.73 3.19 0.73 3.19 0 0PM10 0.73 3.19 0.73 3.19 0 0SO2 0.09 0.38 0.09 0.38 0 0VOC 0.79 3.44 0.79 3.44 0 0CO2 Equivalent 73018 73018 0 0CO2 72675 72675 0 0

Version 4.0 Page 3

Page 20: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Texas Commission on Environmental Quality

Form PI-1 General ApplicationUnit Types - Emission Rates

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Action Requested (only 1 action per FIN)

Include these emissions in annual (tpy) summary?

Facility ID Number (FIN)

Emission Point Number (EPN) Source Name Pollutant

Current Short-Term (lb/hr)

Current Long-Term (tpy)

ConsolidatedCurrent Short-Term (lb/hr)

Consolidated Current Long-Term (tpy)

Proposed Short-Term (lb/hr)

Proposed Long-Term (tpy)

Short-Term Difference (lb/hr)

Long-Term Difference (tpy)

Unit Type (Used for reviewing BACT and Monitoring Requirements)

Unit Type Notes (only if "other" unit type in Column O)

CH4 4.2 4.2 0 0N2O 0.8 0.8 0 0

Not New/Modified Yes B-1851 6 HDA Feed Heater CO 7.08 31 7.08 31 0 0 HeaterNOx 8.42 36.9 8.42 36.9 0 0PM10 0.64 2.8 0.64 2.8 0 0SO2 0.05 0.23 0.05 0.23 0 0VOC 0.46 2.03 0.46 2.03 0 0

Not New/Modified Yes B-1852 7 HDA Recycle Heater CO 0.49 2.15 0.49 2.15 0 0 HeaterNOx 0.59 2.56 0.59 2.56 0 0PM10 0.04 0.19 0.04 0.19 0 0SO2 0.01 0.02 0.01 0.02 0 0VOC 0.03 0.14 0.03 0.14 0 0

Not New/Modified Yes B-1706 8Dryer Regeneration Heater

CO 1.61 7.05 1.61 7.05 0 0 Heater

NOx 1.92 8.39 1.92 8.39 0 0PM10 0.15 0.64 0.15 0.64 0 0SO2 0.01 0.05 0.01 0.05 0 0VOC 0.11 0.46 0.11 0.46 0 0

Not New/Modified Yes B-1705 8ACat. Reactivation Furnace

CO 2.12 9.3 2.12 9.3 0 0 Furnace

NOx 2.53 11.07 2.53 11.07 0 0PM10 0.19 0.84 0.19 0.84 0 0SO2 0.02 0.07 0.02 0.07 0 0VOC 0.14 0.61 0.14 0.61 0 0

Not New/Modified Yes L-1663C 9ASouth Decoking Cyclone

CO 1932.94 135.8 1932.94 135.8 0 0 Other Cyclone

PM 11.63 1.37 11.63 1.37 0 0PM2.5 3.58 0.43 3.58 0.43 0 0PM10 3.58 0.43 3.58 0.43 0 0VOC 0.05 0.02 0.05 0.02 0 0

Not New/Modified Yes L-1663D 9BNorth Decoking Cyclone

CO 1999.16 133.8 1999.16 133.8 0 0 Other Cyclone

PM 12.47 1.35 12.47 1.35 0 0PM2.5 3.84 0.42 3.84 0.42 0 0PM10 3.84 0.42 3.84 0.42 0 0VOC 0.04 0.02 0.04 0.02 0 0

Not New/Modified Yes L-1663C, L-1663D 9A, 9BNorth & South Decoking Cyclones

CO2 Equivalent 1270 1270 0 0 Other Cyclone

CO2 1270 1270 0 0New/Modified Yes L-2019A 10 Hot Flare CO 1092.65 37 4.9 21.46 1097.55 152.24 0 93.78 Control: Flare

NOx 209.76 8.21 0.68 2.97 210.44 24.17 0.0001 12.99SO2 64.68 2.51 64.68 2.66 0 0.15VOC 369.22 6.94 369.22 16.02 0 9.08CO2 Equivalent 48958 0 48958CO2 45396.92 0 45396.92CH4 137.03 0 137.03N2O 0.45 0 0.45

New/Modified Yes L-2019B 11 Cold Flare CO 100.84 13.84 6.97 30.55 107.81 128.6 0 84.21 Control: FlareNOx 19.39 2.92 0.97 4.23 20.36 18.81 0 11.66SO2 0.08 0.13 0.08 0.28 0 0.15VOC 76.88 2.61 3 76.88 14.65 0 9.04CO2 Equivalent 48752 0 48752CO2 45205.52 0 45205.52CH4 136.45 0 136.45N2O 0.45 0 0.45

Not New/Modified Yes U-2010 12 Cooling Tower VOC 2.92 12.79 2.92 12.79 0 0 Cooling TowerPM 4.05 15.33 4.05 15.33 0 0PM10 4.05 15.33 4.05 15.33 0 0PM2.5 1.2 4.55 1.2 4.55 0 0

Not New/Modified Yes L-2010B 12B Cooling Tower VOC 2.02 3.72 2.02 3.72 0 0 Cooling TowerPM 1.2 4.54 1.2 4.54 0 0PM10 1.2 4.54 1.2 4.54 0 0PM2.5 0.36 1.35 0.36 1.35 0 0

Not New/Modified Yes 13C 13CCarbon Canisters in Series

VOC 0.06 0.01 0.06 0.01 0 0 Control: Adsorption System: Disposable

Not New/Modified Yes F-2015 16Naphtha Feedstock Day Tank

VOC 1.52 2.52 1.52 2.52 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2016 17Kerosene Feedstock Day Tank

VOC 1.52 2.47 1.52 2.47 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes FA-1663 18 Light Oil Fuel Tank VOC 3.07 4.3 3.07 4.3 0 0

Version 4.0 Page 4

Page 21: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Texas Commission on Environmental Quality

Form PI-1 General ApplicationUnit Types - Emission Rates

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Action Requested (only 1 action per FIN)

Include these emissions in annual (tpy) summary?

Facility ID Number (FIN)

Emission Point Number (EPN) Source Name Pollutant

Current Short-Term (lb/hr)

Current Long-Term (tpy)

ConsolidatedCurrent Short-Term (lb/hr)

Consolidated Current Long-Term (tpy)

Proposed Short-Term (lb/hr)

Proposed Long-Term (tpy)

Short-Term Difference (lb/hr)

Long-Term Difference (tpy)

Unit Type (Used for reviewing BACT and Monitoring Requirements)

Unit Type Notes (only if "other" unit type in Column O)

Not New/Modified Yes F-2005 19Raw Pyrolysis Gasoline Tank

VOC 1.74 4.9 1.74 4.9 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2010A 20A Heavy Oil Fuel Tank VOC 4.3 5.1 4.3 5.1 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes F-2010B 20B Heavy Oil Fuel Tank VOC 4.3 5.1 4.3 5.1 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes F-2009A 23A Benzene Tank VOC 0.17 0.31 0.17 0.31 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2008 24 HDA Tank VOC 1.45 3.94 1.45 3.94 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2001A 30A Feedstock Tank VOC 3.37 10.01 3.37 10.01 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2001B 30B Feedstock Tank VOC 3.37 10.04 3.37 10.04 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2001C 30C Feedstock Tank VOC 3.39 10.13 3.39 10.13 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes B-1801 31Second Stage Feed Heater

CO 1.27 5.55 1.27 5.55 0 0 Heater

NOx 1.51 6.6 1.51 6.6 0 0PM10 0.11 0.5 0.11 0.5 0 0SO2 0.01 0.04 0.01 0.04 0 0VOC 0.08 0.36 0.08 0.36 0 0

Not New/Modified Yes F-1790 32 Lube Oil Tank VOC 16.27 0.15 16.27 0.15 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes F-1789X 33 Wash Oil Tank VOC 0.23 0.43 0.23 0.43 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2102A 39ASpent Caustic Gasoline Wash Tank

VOC 0.64 1.07 0.64 1.07 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2102B 39BSpent Caustic Gasoline Wash Tank

VOC 0.41 0.85 0.41 0.85 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2104 40 Recovered Oil Tank VOC 0.3 0.87 0.3 0.87 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-1791 42 Methanol Tank VOC 4.08 0.04 4.08 0.04 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes L43 43Fuel Oil Truck Loading

VOC 29.63 7.04 29.63 7.04 0 0 Loading: Truck

Not New/Modified Yes F-2301 50Spent Caustic Wastewater

VOC 0.03 0.06 0.03 0.06 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2305 51Spent Caustic Wastewater

VOC 0.06 0.12 0.06 0.12 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-1608 52 Wastewater Tank VOC 0.75 1.15 0.75 1.15 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F2102C 53 Slop Oil Tank VOC 0.26 0.77 0.26 0.77 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes F-2113 55 Hot Water Belt Tank VOC 1.01 3.19 1.01 3.19 0 0Storage Tank (4): Floating roof with TVP <11.0 psia

Not New/Modified Yes J2021A AC-1Air Compressor Engine No. 1

CO 2.74 2.05 2.74 2.05 0 0 Other Diesel engine

NOx 3.03 2.27 3.03 2.27 0 0PM10 0.16 0.12 0.16 0.12 0 0SO2 0.97 0.73 0.97 0.73 0 0VOC 0.12 0.09 0.12 0.09 0 0

Not New/Modified Yes J2021B AC-2Air Compressor Engine No. 2

CO 2.74 2.05 2.74 2.05 0 0 Other Diesel engine

NOx 3.03 2.27 3.03 2.27 0 0PM10 0.16 0.12 0.16 0.12 0 0SO2 0.97 0.73 0.97 0.73 0 0VOC 0.12 0.09 0.12 0.09 0 0

Not New/Modified Yes F2602A F2602A Vehicle Diesel Tank VOC 0.7 0.01 0.7 0.01 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes F2603 F2603 Vehicle Gasoline Tank VOC 51.22 1.26 51.22 1.26 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes FA1665 FA1665 Diesel Tank VOC 0.22 0.01 0.22 0.01 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes FU-1 FU-1EMACT Process Fugitives

VOC 23.13 101.36 0.01 0.06 23.14 101.42 0.0001 0.0001 Fugitives: Piping and Equipment Leak

Not New/Modified Yes FU-2 FU-2HON Process Fugitives

VOC 0.93 4.08 0.93 4.08 0 0 Fugitives: Piping and Equipment Leak

Not New/Modified Yes FU-3 FU-3 Process Fugitives VOC 13.73 60.13 13.73 60.13 0 0 Fugitives: Piping and Equipment Leak

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationUnit Types - Emission Rates

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Action Requested (only 1 action per FIN)

Include these emissions in annual (tpy) summary?

Facility ID Number (FIN)

Emission Point Number (EPN) Source Name Pollutant

Current Short-Term (lb/hr)

Current Long-Term (tpy)

ConsolidatedCurrent Short-Term (lb/hr)

Consolidated Current Long-Term (tpy)

Proposed Short-Term (lb/hr)

Proposed Long-Term (tpy)

Short-Term Difference (lb/hr)

Long-Term Difference (tpy)

Unit Type (Used for reviewing BACT and Monitoring Requirements)

Unit Type Notes (only if "other" unit type in Column O)

Not New/Modified Yes FU-4 FU-4 NESHAP FF Fugitives VOC 0.02 0.1 0.02 0.1 0 0 Fugitives: Piping and Equipment Leak

Consolidate Yes FUG FUG Fugitive Emissions VOC 7.96 34.87 0.06 0.27 8.02 35.14 0 0.0001 Fugitives: Piping and Equipment Leak

Not New/Modified Yes FWDIESLA FWDIESELA Firewater Diesel Tank VOC 0.02 0.01 0.02 0.01 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes FWDIESELB FWDIESELB Firewater Diesel Tank VOC 0.02 0.01 0.02 0.01 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes FWDIESELC FWDIESELC Firewater Diesel Tank VOC 0.02 0.01 0.02 0.01 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes FWDIESELD FWDIESELD Firewater Diesel Tank VOC 0.02 0.01 0.02 0.01 0 0Storage Tank (1): Fixed roof with capacity < 25,000 gal or TVP < 0.50 psia

Not New/Modified Yes J2019A J-2019-AOlefin Firewater Engine

CO 2.87 0.36 2.87 0.36 0 0 Engine: Emergency, Diesel

NOx 13.33 1.67 13.33 1.67 0 0PM10 0.95 0.12 0.95 0.12 0 0SO2 0.88 0.11 0.88 0.11 0 0VOC 1.06 0.13 1.06 0.13 0 0

Not New/Modified Yes J2019B J-2019-BOlefin Firewater Engine

CO 2.87 0.36 2.87 0.36 0 0 Engine: Emergency, Diesel

NOx 13.33 1.67 13.33 1.67 0 0PM10 0.95 0.12 0.95 0.12 0 0SO2 0.88 0.11 0.88 0.11 0 0VOC 1.06 0.13 1.06 0.13 0 0

Not New/Modified Yes J2019C J-2019-COlefin Firewater Engine

CO 2.87 0.36 2.87 0.36 0 0 Engine: Emergency, Diesel

NOx 13.33 1.67 13.33 1.67 0 0PM10 0.95 0.12 0.95 0.12 0 0SO2 0.88 0.11 0.88 0.11 0 0VOC 1.06 0.13 1.06 0.13 0 0

Not New/Modified Yes J2019D J-2019-DOlefin Firewater Engine

CO 2.87 0.36 2.87 0.36 0 0 Engine: Emergency, Diesel

NOx 13.33 1.67 13.33 1.67 0 0PM10 0.95 0.12 0.95 0.12 0 0SO2 0.88 0.11 0.88 0.11 0 0VOC 1.06 0.13 1.06 0.13 0 0

Not New/Modified Yes L1697 L-1697 Emergency Generator CO 0.85 0.02 0.85 0.02 0 0 Engine: Emergency, Diesel

NOx 10.37 0.27 10.37 0.27 0 0PM10 0.06 0.01 0.06 0.01 0 0SO2 1.65 0.04 1.65 0.04 0 0VOC 0.02 0.01 0.02 0.01 0 0

Not New/Modified Yes PAINT PAINT Painting VOC 7.39 4.81 7.39 4.81 0 0 Other Painting

Not New/Modified Yes WWC-1 WWC-1 Wastewater Collection VOC 2 0.32 2 0.32 0 0 Wastewater Facilities

Not New/Modified Yes 10 DBN MSS 10 DBN MSSElevated Flare -MSS

CO2 Equivalent 4201 4201 0 0 Control: Flare

CO2 3866 3866 0 0CH4 13.3 13.3 0 0N2O 0.01 0.01 0 0

0 00 00 00 00 00 00 00 00 0

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Texas Commission on Environmental QualityForm PI-1 General Application

Stack Parameters

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

EPNIncluded in EMEW?

UTM Coordinates

ZoneEast (Meters)

North (Meters)

BuildingHeight (ft)

Height Above Ground (ft)

Stack Exit Diameter (ft)

Velocity (FPS)

Temperature (°F)

Fugitives - Length (ft)

Fugitives - Width (ft)

Fugitives - Axis Degrees

1A No1B No1C No1D No1E No1F No1G No1H No1J No1K No1L No1M No1N No3A No3B No4A No4B No4C No4D No5A No5B No6 No7 No8 No8A No9A No9B No9A, 9B No10 Yes11 Yes12 No12B No13C No16 No17 No18 No19 No20A No20B No23A No24 No30A No30B No30C No

Emission Point Discharge Parameters

Version 4.0 Page 1

Page 24: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Texas Commission on Environmental QualityForm PI-1 General Application

Stack Parameters

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

EPNIncluded in EMEW?

UTM Coordinates

ZoneEast (Meters)

North (Meters)

BuildingHeight (ft)

Height Above Ground (ft)

Stack Exit Diameter (ft)

Velocity (FPS)

Temperature (°F)

Fugitives - Length (ft)

Fugitives - Width (ft)

Fugitives - Axis Degrees

31 No32 No33 No39A No39B No40 No42 No43 No50 No51 No52 No53 No55 NoAC-1 NoAC-2 NoF2602A NoF2603 NoFA1665 NoFU-1 NoFU-2 NoFU-3 NoFU-4 NoFUG YesFWDIESELA NoFWDIESELB NoFWDIESELC NoFWDIESELD NoJ-2019-A NoJ-2019-B NoJ-2019-C NoJ-2019-D NoL-1697 NoPAINT NoWWC-1 No10 DBN MSS No

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationPublic Notice

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Yes

Yes

No

No

This row is optional. If you do not think the table below accurately represents public notice applicability increases for your project, provide discussion here (1000 characters).

Please see Table 1-1 of the application for a summary of PTE changes for public notice applicability. As noted in Section 5.1 of the application, the calculated emission increases in this application supersede the annual emission increases presented in Standard Premit 136589.

Is this an application for a minor permit amendment?Is there any change in character of emissions in this application (a new criteria pollutant or a new VOC or PM species)?Is there a new air contaminant in this application?

I. Public Notice Applicability

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

For public notice applicability, the agency does not include consolidation or incorporation of any previously authorized facility or activity (PBR, standard permits, etc.), changes to permitted allowable emission rates when exclusively due to changes to standardized emission factors, or reductions in emissions which are not enforceable through the amended permit. Thus, the total emissions increase would be the sum of emissions increases under the amended permit and the emissions decreases under the amended permit for each air contaminant.

The table below will generate emission increases based on the values represented on the "Unit Types - Emission Rates" sheet. Use the "yes" and "no" options in column B of the "Unit Types - Emission Rates" worksheet to indicate if a unit's proposed change of emissions should be included in these totals.

Notes:1. Emissions of PM, PM10, and/or PM2.5 may have been previously quantified and authorized as PM, PM10,and/or PM2.5. These emissions will be speciated based on current guidance and policy to demonstrate compliance with current standards and public notice requirements may change during the permit review.

2. All renewals require public notice.

A. Application Type

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

NoDo the facilities handle, load, unload, dry, manufacture, or process grain, seed, legumes, or vegetable fibers (agricultural facilities)?

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationPublic Notice

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

PollutantCurrent Long-Term (tpy)

Consolidated Emissions (tpy)

Proposed Long-Term (tpy)

Project Change in Allowable (tpy)

PN Threshold

Notice required?

VOC 431.36 3.33 452.81 18.12 5 Yes

PM 108.14 0.00 108.14 0.00 5 No

PM10 241.41 0.00 241.41 0.00 5 No

PM2.5 92.30 0.00 92.30 0.00 5 No

NOx 2232.21 7.20 2264.06 24.65 5 Yes

CO 1408.85 52.01 1638.85 177.99 50 Yes

SO2 1263.46 0.00 1263.76 0.30 10 No

Pb 0.00 0.00 0.00 0.00 0.6 No

CO2 Equivalent 1965015 0 2062725 97710 ** Yes

CO2 1955079 0 2045681.44 90602.44 5 Yes

CH4 126.7 0 400.18 273.48 5 Yes

N2O 22.71 0 23.61 0.9 5 No

SO3 25.24 0 25.24 0 5 No

* Notice is required for PM, PM10, and PM2.5 if one of these pollutants is above the threshold.

** Notice of a GHG action is determined by action type. Initial and major modification always require notice. Voluntary updates require a consolidated notice if there is a change to BACT. Project emission increases of CO2e (CO2 equivalent) are not relevant for determining public notice of GHG permit actions.

II. Public Notice Information

A. Contact InformationEnter 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.):

Last Name:Title:Company Name:Mailing Address:Address Line 2:City:State:

P.O. Box 10940

Corpus ChristiTX

Equistar Chemicals, LP

361-242-8075ZIP Code:Telephone Number:Fax Number:Email Address:

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

78460-0940

Ms.Alicia R.MatusCCO Site Manager

[email protected]

No

This cell intentionally left blank

C. Is public notice required for this project as represented in this workbook?If no, proceed to Section III Small Business Classification.Note: public notice applicability for this project may change throughout the technical review.

Yes

First Name:

D. Are any HAPs to be authorized/re-authorized with this project? The category "HAPs" must be specifically listed in the public notice if the project authorizes (reauthorizes for renewals) any HAP pollutants.

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationPublic Notice

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Address Line 2:

First Name:

Has the public place granted authorization to place the application for public viewing and copying?

Title:

Corpus ChristiTX

P.O. Box 10940

Telephone Number:

Email Address:Fax Number:

Name of Public Place:Physical Address:

Peters

Prefix (Mr., Ms., Dr., etc.):

361-242-8030

Last Name:

Owen R. Hopkins Public Library

Yes

City: Corpus Christi78410Nueces

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.

B. Public placePlace 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.

Equistar Chemicals, LP

[email protected]

State:

Yes

78460-0940361-242-5028

ZIP Code:

City:

Company Name:

Mr.H. Scott

Environmental Engineer

Mailing Address:Address Line 2:

ZIP Code:County:

3202 Mckinzie Rd

Does the public place have Internet access available for the public?

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationPublic Notice

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

No

No

D. PSD and Nonattainment Permits Only

NoAre the proposed facilities located within 100 km or less of an affected state or Class I Area?

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 the district?

Consolidated Public Notice

Address Line 2:City:State:ZIP Code:

ZIP Code:State:City:Address Line 2:

Corpus Christi

MayorP.O. Box 9277

Spanish

The Honorable:Mailing Address:

Provide the information for the County Judge for the location where the facility is or will be located.

901 Leopard St.

Small business classification:

This cell intentionally left blank

Does the company (including parent companies and subsidiary companies) have fewer than 100 employees or less than $6 million in annual gross receipts?

JoeMcComb

If yes to either question above, list which language(s) are required by the bilingual program?

Yes

YesIs a bilingual program required by the Texas Education Code in the School District?

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.

III. Small Business Classification

Provide the information for the Presiding Officer(s) of the municipality for this facility site. This is frequently the Mayor.

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:

Title:Last Name:

Corpus ChristiTX78401

78469

Mailing Address:

https://www.txdirectory.com

TX

Barbara Canales

First Name:

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.

Floor: 3rd Room: 303

C. Alternate Language PublicationIn 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.

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationFederal Applicability

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Determination:

No

Pollutant Project Increase Threshold PSD Review Required?

CO 206.46 100 Yes

NOx 28.93 40 No

PM

PM10

PM2.5

SO2 2.61 40 No

Ozone (as VOC) 18.12 40 No

Ozone (as NOx) 28.93 40 No

Pb

H2S

TRS

Reduced sulfur compounds (including H2S)

H2SO4

Fluoride (excluding HF)

CO2e 97709.43 75000 Yes

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

Is netting required for the PSD analysis for this project?

This cell intentionally left blank

I. County Classification

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

Nueces

II. PSD and GHG PSD Applicability Summary

This cell intentionally left blank

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

Does the project require retrospective review? No

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationFees

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

No

No

This cell intentionally left blank

IV. Calculations - Non-RenewalFor GHG permits: A single PSD fee (calculated on the capital cost of the project per 30 TAC § 116.163) will be required for all of the associated permitting actions for a GHG PSD project. Other NSR permit fees related to the project that have already been remitted to the TCEQ can be subtracted when determining the appropriate fee to submit with the GHG PSD application. Identify these other fees in the GHG PSD permit application.

Ambient air monitoring network. $0.00Sub-Total: $0.00

Sub-Total: $0.00

This cell intentionally left blank

III. Indirect Costs - Non-Renewal

Type of Cost AmountFinal engineering design and supervision, and administrative overhead. $0.00Construction expense, including construction liaison, securing local building permits, insurance, temporary construction facilities, and construction clean-up. $0.00

Contractor's fee and overhead. $0.00

Process and control equipment not previously owned by the applicant and not currently authorized under this chapter.

$0.00

Auxiliary equipment, including exhaust hoods, ducting, fans, pumps, piping, conveyors, stacks, storage tanks, waste disposal facilities, and air pollution control equipment specifically needed to meet permit and regulation requirements.

$0.00

Freight charges. $0.00Site preparation, including demolition, construction of fences, outdoor lighting, road, and parking areas.

$0.00

Auxiliary buildings, including materials storage, employee facilities, and changes to existing structures.

$0.00

I. General Information - Non-Renewal

II. Direct Costs - Non-RenewalThis cell intentionally left blank

Is this project for new facilities controlled and operated directly by the federal government? (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 sections II and III.

Select Application Type Major Application

Installation, including foundations, erection of supporting structures, enclosures or weather protection, insulation and painting, utilities and connections, process integration, and process control equipment.

$0.00

Type of Cost Amount

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationFees

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

$0.00

$3,000.00

$3,000.00

Yes3,000.00$

$3,000.00

No

No

C. Total Paid

A. Payment One (required)

Is the estimated capital cost of the project above $2 million?

Is the application required to be submitted under the seal of a Texas licensed P.E.?Note: an electronic PE seal is acceptable.

Greater than $25,000,000 N/A

Less than $300,000 $3,000 (minimum fee)$300,000 - $7,500,000 1.0% of capital cost$300,000 - $25,000,000 N/AGreater than $7,500,000 $75,000 (maximum fee)

Estimated Capital Cost Major Application Fee

This cell intentionally left blank

Your estimated capital cost: Minimum fee applies.Permit Application Fee: $3,000.00

This cell intentionally left blank

VIII. Professional Engineer Seal Requirement

This cell intentionally left blank

VII. Payment Information

This cell intentionally left blank

This cell intentionally left blank

VI. Total Fees

Note: fees can be paid together with one payment or as two separate payments.Non-Renewal Fee

Total

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.

Enter the check, money order, ePay Voucher, or other transaction number:Enter the Company name as it appears on the check:

TBD

n/a

Enter the fee amount:Was the fee paid online?

Version 4.0 Page 2

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationImpacts

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

PollutantDoes this pollutant require PSD review?

How will you demonstrate that this project meets all applicable requirements?

Notes Additional Notes (optional)

Ozone No Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

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

CO YesProtocol (required for all PSD projects, excluding GHG PSD)

Attach a protocol meeting all requirements listed on the TCEQ website.

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

PM No Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

PM2.5 No Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

PM10 No Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

SO2 No Modeling: screen or refined Attach a completed "Electronic Modeling Evaluation Workbook" (EMEW).

CO2 Equivalent Yes Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

CO2 Yes Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

CH4 Yes Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

N2O Yes Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

SO3 No Not applicableThis pollutant is not a part of this project or does not require an impacts analysis.

Version 4.0 Page 1

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationBACT

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Current Tier I BACT Confirm Additional Notes

Maximum short term H2S emissions: 0.1 gr/dscf or 160 ppmv. Maximum annual H2S

Action Requested FINs Unit Type Pollutant Current Tier I BACT Confirm Additional Notes

New/Modified L-2019A Control: Flare CO Provide emission factor used and reference. Yes TCEQ factor for high-Btu steam-assisted flares (0.3503 lb/MMBtu)

New/Modified L-2019A Control: Flare NOx Provide emission factor used and reference. Yes TCEQ factor for high-Btu steam-assisted flares (0.0485 lb/MMBtu)

New/Modified L-2019A Control: Flare SO2 Provide emission factor used and reference. Yes 5 ppm sulfur in the fuel gas and 100% conversion to SO2

New/Modified L-2019A Control: Flare VOCVOC: Meets 40 CFR 60.18. Destruction Efficiency: 99% for certain compounds up to three carbons, 98% otherwise. No flaring of halogenated compounds is allowed. Flow monitor required. Composition or BTU analyzer may be required.

Yes 99.5% DRE for propane and ethylene

New/Modified L-2019A Control: Flare CO2 Equivalent See additional notes: Yesflare designed to meet the requirements of 40 CFR 60.18; proper operation and maintenance in accordance with good combustion practices

New/Modified L-2019A Control: Flare CO2 See additional notes: Yesflare designed to meet the requirements of 40 CFR 60.18; proper operation and maintenance in accordance with good combustion practices; no measurable CO2 in flared gas

New/Modified L-2019A Control: Flare CH4 See additional notes: Yesflare designed to meet the requirements of 40 CFR 60.18; proper operation and maintenance in accordance with good combustion practices

New/Modified L-2019A Control: Flare N2O See additional notes: Yesflare designed to meet the requirements of 40 CFR 60.18; proper operation and maintenance in accordance with good combustion practices

New/Modified L-2019A Control: Flare

New/Modified L-2019A Control: Flare

New/Modified L-2019A Control: Flare

New/Modified L-2019A Control: Flare

New/Modified L-2019A Control: Flare

New/Modified L-2019A Control: Flare MSS Same as normal operation BACT requirements. Yes

New/Modified L-2019B Control: Flare CO Provide emission factor used and reference. Yes TCEQ factor for high-Btu steam-assisted flares (0.3503 lb/MMBtu)

New/Modified L-2019B Control: Flare NOx Provide emission factor used and reference. Yes TCEQ factor for high-Btu steam-assisted flares (0.0485 lb/MMBtu)

New/Modified L-2019B Control: Flare SO2 Provide emission factor used and reference. Yes 5 ppm sulfur in the fuel gas and 100% conversion to SO2

New/Modified L-2019B Control: Flare VOCVOC: Meets 40 CFR 60.18. Destruction Efficiency: 99% for certain compounds up to three carbons, 98% otherwise. No flaring of halogenated compounds is allowed. Flow monitor required. Composition or BTU analyzer may be required.

Yes 99.5% DRE for propane and ethylene

New/Modified L-2019B Control: Flare CO2 Equivalent See additional notes: Yesflare designed to meet the requirements of 40 CFR 60.18; proper operation and maintenance in accordance with good combustion practices

New/Modified L-2019B Control: Flare CO2 See additional notes: Yesflare designed to meet the requirements of 40 CFR 60.18; proper operation and maintenance in accordance with good combustion practices; no measurable CO2 in flared gas

New/Modified L-2019B Control: Flare CH4 See additional notes: Yesflare designed to meet the requirements of 40 CFR 60.18; proper operation and maintenance in accordance with good combustion practices

New/Modified L-2019B Control: Flare N2O See additional notes: Yesflare designed to meet the requirements of 40 CFR 60.18; proper operation and maintenance in accordance with good combustion practices

New/Modified L-2019B Control: Flare

New/Modified L-2019B Control: Flare

New/Modified L-2019B Control: Flare

New/Modified L-2019B Control: Flare

New/Modified L-2019B Control: Flare

New/Modified L-2019B Control: Flare MSS Same as normal operation BACT requirements.

Plant Type

Plant fuel gas facilityThis cell intentionally blank.

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationBACT

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

Action Requested FINs Unit Type Pollutant Current Tier I BACT Confirm Additional Notes

Consolidate FUG Fugitives: Piping and Equipment Leak VOC

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. 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.

Yes 28VHP LDAR aplied

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak

Consolidate FUG Fugitives: Piping and Equipment Leak MSS Same as normal operation BACT requirements. Yes

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Texas Commission on Environmental QualityForm PI-1 General Application

Monitoring

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

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

Additional Notes for Measuring:

L-2019A Control: Flare CO

Pilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured at the instrument's capability or every 15 minutes, which ever is less), with hourly averages recorded. A Btu analyzer may be substituted for the composition analyzer where the composition is understood.

Yes Required by Special Condition 23

L-2019A Control: Flare NOx

Pilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured at the instrument's capability or every 15 minutes, which ever is less), with hourly averages recorded. A Btu analyzer may be substituted for the composition analyzer where the composition is understood.

Yes Required by Special Condition 23

L-2019A Control: Flare SO2

Pilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured at the instrument's capability or every 15 minutes, which ever is less), with hourly averages recorded. A Btu analyzer may be substituted for the composition analyzer where the composition is understood.

Yes Required by Special Condition 23

L-2019A Control: Flare VOC

Pilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured at the instrument's capability or every 15 minutes, which ever is less), with hourly averages recorded. A Btu analyzer may be substituted for the composition analyzer where the composition is understood.

Yes Required by Special Condition 23

L-2019A Control: Flare

CO2 Equivalent

See additional notes: YesPilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured every 15 minutes), with hourly averages recorded.

L-2019A Control: Flare CO2 See additional notes: YesPilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured every 15 minutes), with hourly averages recorded.

L-2019A Control: Flare CH4 See additional notes: YesPilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured every 15 minutes), with hourly averages recorded.

L-2019A Control: Flare N2O See additional notes: YesPilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured every 15 minutes), with hourly averages recorded.

L-2019A Control: Flare

L-2019A Control: Flare

L-2019A Control: Flare

L-2019A Control: Flare

L-2019A Control: Flare

L-2019B Control: Flare CO

Pilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured at the instrument's capability or every 15 minutes, which ever is less), with hourly averages recorded. A Btu analyzer may be substituted for the composition analyzer where the composition is understood.

Yes Required by Special Condition 23

L-2019B Control: Flare NOx

Pilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured at the instrument's capability or every 15 minutes, which ever is less), with hourly averages recorded. A Btu analyzer may be substituted for the composition analyzer where the composition is understood.

Yes Required by Special Condition 23

L-2019B Control: Flare SO2

Pilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured at the instrument's capability or every 15 minutes, which ever is less), with hourly averages recorded. A Btu analyzer may be substituted for the composition analyzer where the composition is understood.

Yes Required by Special Condition 23

L-2019B Control: Flare VOC

Pilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured at the instrument's capability or every 15 minutes, which ever is less), with hourly averages recorded. A Btu analyzer may be substituted for the composition analyzer where the composition is understood.

Yes Required by Special Condition 23

L-2019B Control: Flare

CO2 Equivalent

See additional notes: YesPilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured every 15 minutes), with hourly averages recorded.

This cell intentionally left blank

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Texas Commission on Environmental QualityForm PI-1 General Application

Monitoring

Date: 12/18/2019Permit #: 4682B

Company: Equistar Chemicals, LP

L-2019B Control: Flare CO2 See additional notes: YesPilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured every 15 minutes), with hourly averages recorded.

L-2019B Control: Flare CH4 See additional notes: YesPilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured every 15 minutes), with hourly averages recorded.

L-2019B Control: Flare N2O See additional notes: YesPilot flame presence monitored continuously. Waste gas flow and composition monitored continuously (measured every 15 minutes), with hourly averages recorded.

L-2019B Control: Flare

L-2019B Control: Flare

L-2019B Control: Flare

L-2019B Control: Flare

L-2019B Control: Flare

FUGFugitives: Piping and Equipment Leak

VOC

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 repair (LDAR) Program 28M has a leak definition where repair action is 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.

Yes Required by Special Condition 21

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

FUG Fugitives: Piping and Equipment Leak

Version 4.0 Page 2

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Texas Commission on Environmental Quality

Form PI-1 General ApplicationMaterials

Date: December 2019Permit #: 4682B

Company: Equistar Chemicals, LP

How submitted Date submitted

STEERS 12/18/2019Not applicableNot applicable

STEERS 12/18/2019STEERS 12/18/2019STEERS 12/18/2019

STEERS

STEERS 12/18/2019Not applicable

STEERS 12/18/2019STEERS 12/18/2019

STEERS 12/18/2019

Not applicableSTEERS 12/18/2019STEERS 12/18/2019

Electronic Modeling Evaluation Workbook: NonSCREEN3

C. Federal Applicability

E. Impacts Analysis

D. Technical Information

F. Additional Attachments

Material Balance (if applicable)Calculations

Netting analysis (if required) - Tables 3F and 4F as needed

MERA analysis

PSD modeling protocol

Electronic Modeling Evaluation Workbook: SCREEN3

Qualitative impacts analysis

State regulatory requirements discussion

Area map

BACT discussion, if additional details are attachedMonitoring information, if additional details are attached

List of MSS activities

Process descriptionProcess flow diagram

Summary and project emission increase determination - Tables 1F and 2F

Plot plan

Item

Core Data Form

Form PI-1 General ApplicationHard copy of the General sheet with original (ink) signature

B. General Information

A. Administrative Information

Professional Engineer Seal

Copy of current permit (both Special Conditions and MAERT)

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TCEQ 20706 (APDG 6257v1, Revised 11/14) Form APD-EXPThis form for use by facilities subject to air quality permits requirements andmay be revised periodically. Page 2 of 2

Form APD-EXP Expedited Permitting Request

I. Contact Information

Company or Other Legal Customer Name:

Customer Reference Number (CN):

Regulated Entity Number (RN):

Company Official or Technical Contact Name:

Phone Number:

Email:

II. Project Information

Facility Type:

Permit Number:

Project Number:

III. Economic Justification

The purpose of the application associated with economy of this state or an area of this state.

this request to expedite will benefit the YES NO

IV. Delinquent Fees and Penalties

Applications will not be expedited if any delinquent fees and/or penalties are owed to the TCEQ or the Office of the Attorney General on behalf of the TCEQ. For more information regarding Delinquent Fees and Penalties, go to the TCEQ Web site at: www.tceq.texas.gov/agency/delin/index.html.

V. Signature

The signature below confirms that I have knowledge of the facts included in this application and that these facts are true and correct to the best of my knowledge and belief. As the applicant, I commit to fulfilling all expectations of the expedited permitting program and application requirements promptly. Failure to meet any expectation or requirement may cause my application to be removed from the expedited permitting program and possibly voided at the discretion of the TCEQ Executive Director. The signature further signifies awareness that intentionally or knowingly making or causing to be made false material statements or representations in the application is a criminal offense subject to criminal penalties.

Name:

Signature:

Date:

Equistar Chemicals, LP

CN600124705

RN100221662

H. Scott Peters

361-242-5028

[email protected]

Corpus Christi Complex

4682B, PSDTX761M3, PSD-TX-761-GHG (TCEQ No. GHGPSDTX32)

TBD

Reset Form

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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 Commission on Environmental Quality

Form APD-APS Air Permitting Surcharge Payment

I. Contact Information

Company or Other Legal Customer Name: Equistar Chemicals, LP

Customer Reference Number (CN): CN600124705

Regulated Entity Number (RN): RN100221662

Company Official or Technical Contact Information:

( Mr. Mrs. Ms. Other: )

Name: H. Scott Peters

Title: Environmental Engineer

Mailing Address: P.O. Box 10940

City: Corpus Christi

State: TX

ZIP Code: 78460-0940

Telephone Number: 361-242-5028

E-mail Address: [email protected]

II. Project Information

Facility Name: Corpus Christi Complex

Permit Number: 4682B, PSDTX761M3, PSD-TX-761-GHG (TCEQ No. GHGPSDTX32)

Project Number: TBD

III. Surcharge Payment

Project Type: Federal NSR permits

Fee Amount: $20,000

Check, Money Order, Transaction Number, and/or ePay Voucher Number: (below)

TBD

Paid Online: YES NO

Company Name on Check: n/a

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PERMIT 4682B AMENDMENT

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3 AREA MAP AND PLOT PLAN

An area map is provided in Figure 3-1 which includes a 3,000-foot distance marking. An overall site plan is provided in Figure 3-2.

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637000 637500 638000 638500 639000 639500 640000 640500 641000

UTM Easting (meters)

3075

500

3076

000

3076

500

3077

000

3077

500

3078

000

3078

500

UT

M N

orth

ing

(met

ers)

Figure 4-1Area Map

Source: Google EarthZone: 15Coordinate Datum: NAD 83

North

3,000 ft Radius

4801 Southwest Parkway, Parkway 2, Suite 150Austin TX 78735, USA

Fence Line

Scale

(feet)0 1000 2000 3000 4000

Figure 3-1 Area Map

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CC Plant Plot PlanScale

(feet)

BENCHMARK3,077,375 m Northing 638,215 m Easting

0 300 600 900 1200 1500

1A U.S.C. FURNACE “A”1B U.S.C. FURNACE “B”1C U.S.C. FURNACE “C”1D U.S.C. FURNACE “D”1E U.S.C. FURNACE “E”1F U.S.C. FURNACE “F”1G U.S.C. FURNACE “G”1H U.S.C. FURNACE “H”1J U.S.C. FURNACE “J”1K U.S.C. FURNACE “K”1L U.S.C. FURNACE “L”1M U.S.C. FURNACE “M”1N U.S.C. FURNACE “N”3A V.M.R. FURNACE “A”3B V.M.R. FURNACE “B”5A STEAM S. HEATER “A”5B STEAM S. HEATER “B”9A SOUTH DECOKING CYCLONE9B NORTH DECOKING CYCLONE10 FLARE 1011 FLARE 11FUG Fugitive Emissions

LEGENDEPN DESCRIPTION

Figure 3-2

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PERMIT 4682B AMENDMENT

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4 PROCESS DESCRIPTION

The Olefins Unit, which produces process gases that are controlled by the Hot Flare (EPN 10) and Cold Flare (EPN 11), is a production facility for ethylene, propylene and other intermediate products used in chemical manufacturing.

This project seeks to authorize the emissions associated with the addition of higher BTU gas to be supplemented to the existing flare vent gas stream to meet the EPA requirement for flare control devices. The EPA requirements for flare control devices will be driven by both changes in 40 CFR 63 Subpart YY and the EPA flare consent decrees. The requirements will mirror the existing flare rules found in 40 CFR 63 Subpart CC in §63.670. The EPA regulation requires the NHVcz of the flare to be a minimum of 270 Btu/scf. In order to meet this heating value, the existing vent gas to the flare will need to be supplemented with plant fuel gas and/or natural gas to raise the vent gas heating value.

The supplemental BTU gas will increase the heating value of the vent gas and help ensure the EPA required minimum of 270 BTU/scf is being met in the combustion zone of the flare tip, which EPA has determined is required to ensure proper combustion efficiency. The addition of the supplemental high BTU gas is solely to meet the EPA requirements and is not associated with any production or Olefins Unit process changes.

The addition of higher BTU gas will only increase the flare collateral combustion byproduct emissions; there are no upstream or downstream impacts. The addition of fuel gas and/or natural gas for the higher BTU value will not require additional testing, monitoring, recordkeeping or reporting. The flares already have sufficient requirements that are currently being met and will continue to be met with the existing applicable permit conditions found in NSR Permit 4682B Special Condition 23 A-D and existing state and federal regulations including 40 CFR §60.18 and §63.11 and 30 TAC 115. The addition of higher BTU gas will not require any changes to these requirements.

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5 EMISSION CALCULATIONS

This section describes the emission calculation methods used to estimate the emissions rates for the facilities included in this application. Detailed emission calculations are presented in Appendix A.

5.1 Criteria Pollutants NOx and CO emissions were calculated based on the heating value of the material combusted and appropriate emission factors from TCEQ’s Technical Guidance Package for Chemical Sources: Flares and Vapor Oxidizers, October 2000. Factors for high-BTU steam-assisted flares are applied. The total heat input from the streams routed to the flares was determined based on the volumetric flow and the heating value. Propane and ethylene emissions are calculated using a 99.5% destruction efficiency. A higher DRE of 99.5% has already been reviewed and approved by TCEQ and is not proposed to be changed as part of this project (see response to questions submitted November 24, 2010 for additional details). Emissions of SO2 were calculated based on 5 parts per million (ppm) sulfur in the fuel gas and 100% conversion to SO2.

Emission calculations are shown for the proposed emission increases associated with the project. As shown in Table 1-1, the calculated annual emissions should be added to the emission rates currently authorized in Permit 4682B. The calculated emission increases in this application supersede the annual emission increases presented in Standard Permit 136589. This project is not proposing to change the currently authorized short-term (hourly) emissions from the rates currently authorized.

5.2 Greenhouse Gases Carbon dioxide (CO2) emissions from the flare were based on CO2 emissions formed during the combustion of hydrocarbons in the combusted stream. The combustion CO2 emissions were calculated following equation Y-2 from 40 CFR 98 Subpart Y. Methane (CH4) emissions were calculated following equation Y-4 from 40 CFR 98 Subpart Y. Nitrous oxide (N2O) emissions were calculated following equation Y-5 from 40 CFR 98 Subpart Y. The Global Warming Potential (GWP) factors from Table A-1 to Subpart A of Part 98 were used to calculate the CO2 equivalents (CO2e) emissions.

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6 BEST AVAILABLE CONTROL TECHNOLOGY

As stated in Section 116.111(a)(2)(C), new or modified facilities must utilize best available control technology (BACT), with consideration given to the technical practicability and economic reasonableness of reducing or eliminating the emissions from the facility. Each facility is evaluated on a case-by-case basis. Engineering principles and agency experience, concerning the practicality and reasonableness of an emission reduction option, are used in this determination.

As described in the guidance documents entitled Evaluating Best Available Control Technology (BACT) in Air Permit Applications (April 2001) and Technical Guidance Package for: Prevention of Significant Deterioration (PSD) Air Quality (January 2001), the TCEQ BACT evaluation is conducted using a “tiered” analysis approach. The evaluation begins at the first tier and continues sequentially through subsequent tiers if necessary as determined by the evaluation process described in this document. In each tier, BACT is evaluated on a case-by-case basis.

In the first tier, controls accepted as BACT in a recent permit review for the same process in the same industry are approved as BACT in a current review if no new technical developments have been made that would justify additional controls as economically or technically reasonable. 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.

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 EPA’s RACT/BACT/LAER Clearinghouse.

With the adoption of rules for the authorization of emissions of greenhouse gases (GHGs), TCEQ states “While the commission has incorporated by reference the definition of BACT in federal rule in §116.160(c)(1)(A), it agrees…that the SIP approval of the state's PSD program allows the use of the state's three-tier BACT review process. Therefore, there is no need for incorporation of EPA's [“top down”] method as a method for BACT reviews for GHG PSD permit applications.” Consistent with this determination, Equistar addresses BACT for GHG emission sources in this application using the SIP approved BACT process.

The following sections describe the BACT analysis for the sources covered in this application. As discussed below for each source type, Tier I control technology is utilized for all sources associated with this application. The Current BACT Spreadsheet from TCEQ website3 was used for the BACT evaluation below. Appendix C includes tables summarizing the results of RACT/BACT/LAER Clearinghouse4 (RBLC) searches. The data obtained from EPA’s website has been sorted and formatted for ease of use and to only include relevant sources and pollutants.

6.1 Criteria Pollutants The flares are designed and operated consistent with the TCEQ’s BACT guidance and the requirements in NSPS, Subpart A, Section 60.18 (40 CFR §60.18). The flares will result in emissions of NOx, CO, VOC, and SO2. BACT for each of these pollutants is addressed below. GHG emissions are discussed in Section 6.2. An RBLC database search for flare controls was conducted and is summarized in Appendix C of this application.

Nitrogen Oxide (NOx) Emissions Flare NOx emissions result from thermal NOx formation from elemental nitrogen in the air. The flared gas streams will not contain any significant nitrogen compounds other than elemental nitrogen; therefore, no “fuel NOx” will be produced. The RBLC database search results show good combustion practices, including

3 https://www.tceq.texas.gov/permitting/air/nav/air_bact_chemsource.html [accessed 11/20/2019]

4 https://cfpub.epa.gov/rblc/index.cfm?Action=search.BasicSearch [accessed 11/20/2019]

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compliance with 60.18, for NOx control from flares. Minimization of flared gas is also presented in the RBLC for MSS entries. The above practices are the only available options for controlling NOx emissions from flaring. As such, Equistar will employ these design and operating measures for the flares to satisfy BACT.

Carbon Monoxide (CO) Emissions CO is produced from incomplete combustion of carbon compounds. Equistar proposes to minimize the formation of CO emissions through the use of good engineering design and proper operation of the flares.

Equistar will maintain the flame integrity through the implementation of good combustion practices and flame detection monitoring with an automatic re-ignition system and designing and operating the flares in accordance with 40 CFR §60.18 and the anticipated MACT Subpart YY requirements. Since the combustion efficiency (i.e., destruction/removal efficiency) of a flare is primarily influenced by temperature, residence time, and the mixing of air and process gases in the combustion zone, implementation of these design considerations and use of a natural gas pilot flame will support a flare design that maximizes efficiency and minimizes incomplete combustion. These design requirements satisfy BACT for CO.

Sulfur Dioxide (SO2) Emissions The flares convert sulfur compounds in the waste gas streams to SO2; therefore, proper operation of the flares inherently results in SO2 emissions due to the intended destruction of the reduced sulfur compounds. This destruction efficiency will be met by operating the flares in accordance with the specifications for flares in 40 CFR §60.18 as described previously. Furthermore, by limiting the material combusted in the flares to low-sulfur fuel gas, the available sulfur for SO2 formation is severely limited. These design and operating methods satisfy BACT for SO2.

Volatile Organic Compound (VOC) Emissions VOC emissions from the flares are the result of incomplete combustion of VOC compounds in the flared gas streams. The RBLC database search results show no control for VOC from flares other than proper design and operation of the flares as already described. A minimum 98% DRE for VOCs is presented in the RBLC entries, which is consistent with TCEQ BACT guidance.

The flares will be designed and operated consistent with the TCEQ’s BACT guidance and should achieve a destruction/removal efficiency (DRE) of 99.5% for propane and ethylene. As discussed in Section 5.1, this DRE has already been reviewed and approved by TCEQ. The above practices are the only available options for controlling VOC emissions from flaring and therefore represent BACT.

6.2 Greenhouse Gases The flares are designed and operated consistent with the TCEQ’s BACT guidance and the requirements in NSPS, Subpart A, Section 60.18 (40 CFR §60.18). The flares will result in emissions of GHG emissions including CO2, CH4, and N2O. BACT for each of these pollutants is addressed below. An RBLC database search for flare controls was conducted and is summarized in Appendix C of this application.

Carbon Dioxide (CO2) Emissions GHG emissions from flares can result from uncombusted CO2 in the process gas and from the conversion of the carbon in the flared gas to CO2. Equistar’s plant gas does not contain measurable amounts of CO2 so all calculated CO2 is from VOC combustion.

An evaluation of flare BACT from GHG permits issued by both TCEQ and EPA in Texas revealed that accepted BACT for flares is proper operation in compliance with 40 §CFR 60.18, and good combustion practices. Flare gas recovery systems are sometimes utilized at refineries to minimize flows to the flare. Even with flare gas recovery the same amount of supplemental plant fuel gas would have to be added to the existing flares since the flares are process safety control devices that have to be in service at all times and require steam addition per the manufacturer’s requirements. The emission increases in this permit application would still be required even if the system had flare gas recovery. Further, flare gas recovery is not a reasonable option for Equistar given the given the low level of routine emissions and the sporadic nature of MSS emissions controlled by the flare. Consistent with the RBLC database results, Equistar proposes to design the flares to meet the requirements of 40 CFR 60.18 and to properly maintain and operate the flare in accordance with good combustion practices. The proposed use of steam-assisted

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combustion will allow for improved flare gas combustion control and minimize periods of poor combustion. These controls are proposed to meet Tier I BACT.

Methane (CH4) Emissions Following good combustion practices will minimize VOC emissions from the flares and subsequently CH4 emissions will be minimized. In addition, the flares are designed to meet the requirements of 40 CFR 60.18 and to achieve 99%+ DRE for methane. These design considerations are proposed to meet Tier I BACT.

Nitrous Oxide (N2O) Emissions The only control method identified for N2O is the implementation of good combustion practices and use of natural gas fuel. Equistar’s flares will combust natural gas or plant fuel gas, which is very similar to natural gas. In addition, the flares are designed to meet the requirements of 40 CFR 60.18. Implementation of good combustion practices is proposed to meet Tier I BACT.

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7 FEDERAL PERMITTING REVIEW

Non-attainment New Source Review (NNSR) permitting is required for each non-attainment pollutant for which a modification of an existing major source will result in a significant net emissions increase. Prevention of Significant Deterioration (PSD) permitting is required for a modification of an existing major source for each attainment pollutant and other regulated pollutants (such as H2S and H2SO4) for which the modification will result in a significant net emissions increase. Nueces County is currently designated as attainment/unclassified for all criteria pollutants; therefore, NNSR review does not apply to this project.

The Corpus Christi Complex is an existing major source PSD permitting purposes. Table 7-1 summarizes the project emission increases and compares them to the PSD significant modification thresholds. As shown in Table 7-1, the NOx, VOC, and SO2 project emission increases are below the significance level so netting is not necessary and PSD review is not required for these pollutants. CO triggers PSD review and GHG triggers as an “anyway source”. Table 1F and Table 2Fs are included in Appendix B.

Application of BACT ensures that emissions are minimized to the extent technically feasible and economically reasonable. Section 6 of this application includes a detailed discussion of the control technology applied to each facility included in this application.

Table 7-1 PSD Applicability Analysis Summary

Pollutant Project Increase

(tpy)

Significant Threshold

(tpy)

Triggers PSD Review?

NOx 28.93 40 no CO 206.46 100 yes

VOC 18.12 40 no SO2 2.61 40 no

CO2e 97,709 75,000 yes

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8 PERMIT BY RULE INCORPORATION

In accordance with 30 TAC §116.116(d) and following additional TCEQ guidance provided in the September 26, 2006 memorandum entitled “Revised Permit by Rule (PBR) and Standard Permit (SP) Consolidation Into Permits”, Equistar is incorporating PBRs into Permit 4682B as required. Table 8-1 provides a summary of the PBR and SP authorizations to be incorporated as part of this project, along with the authorized emission rates that should be added to the associated NSR permit for each affected EPN.

Please note that some authorizations impact other permits besides Permit 4682B; therefore, the authorizations below with other permits identified should not be voided until those emissions can be incorporated into the associated NSR permits.

Table 8-1 Permit by Rule Incorporation Summary Registration

No. EPN Pollutant lb/hr tpyPermit

No. 131202 11 VOC 0.00 3.00 4682B

136589

10

CO 1097.55 58.46

4682B

NOx 210.44 11.18 SO2 64.68 2.51 VOC 369.22 6.94

11

CO 107.81 44.39 NOx 20.36 7.15 SO2 0.08 0.13 VOC 76.88 2.61

BX001FL, 10, 11

CO 721.67 54.97

83864 NOx 138.78 10.57 SO2 92.79 6.14 VOC 1132.54 67.86 H2S 0.27 0.02

141992 FU-1 VOC 0.01 0.06 4682B

MSS-ATM VOC 0.04 <0.01 83864

155067 FUG VOC 0.06 0.27 4682B

MSS-ATM VOC 0.45 0.01 83864

TCEQ requires that BACT be addressed in order for PBRs and SPs to be incorporated into a permit. The following sections discuss the BACT applicability for each project:

PBR Registration No. 131202 PBR Registration No. 131202 authorizes additional annual routine flaring from EPN 11. The additional flaring only increases the TPY of VOC and does not increase the pound per hour emissions. The flare meets the applicable requirements of 40 CFR §60.18 and 40 CFR §63.11. Please refer to Section 6 for a discussion of BACT associated with the Cold Flare (EPN 11).

Standard Permit No. 136589 Standard Permit No. 136589 is a Pollution Control Project used to authorize new flare tips on the Hot Flare (EPN 10) and Cold Flare (EPN 11). The authorization was later revised to authorize updated emissions representations associated with the addition of plant fuel gas and/or natural gas to the flares. As noted in Section 5.1 the calculated emission increases in this application supersede the annual emission increases presented in Standard Permit 136589. Please refer to Section 6 for a discussion of BACT associated with the Hot Flare (EPN 10) and Cold Flare (EPN 11).

PBR Registration No. 141922 PBR Registration No. 141922 authorizes fugitive component emissions associated with unloading pyrolysis gasoline at the unloading station. Fugitive emissions calculated using SOCMI w/o ethylene leak factors and

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application of the 28VHP LDAR program. Total uncontrolled fugitive emissions from EPN FU-1 are greater than 25 tpy. The use of the 28VHP Leak Detection and Repair Program is considered BACT for this level of emissions, per TCEQ’s website.

PBR Registration No. 155067 PBR Registration No. 155067 authorizes piping fugitive components, valves and flanges, for a mixed light hydrocarbon feedstock to the ethylene cracking furnaces. Additionally, the maintenance, startup and shutdown (MSS) emission composition change is also included as a separate calculation. Fugitive emissions calculated using SOCMI w/o ethylene leak factors and application of the 28VHP LDAR program. Total uncontrolled fugitive emissions from EPN FUG are greater than 25 tpy. The use of the 28VHP Leak Detection and Repair Program is considered BACT for this level of emissions, per TCEQ’s website.

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9 GENERAL APPLICATION REQUIREMENTS

Pursuant to 30 TAC §116.111, Equistar proposes to meet the rules and regulations of the TCEQ and the intent of the Texas Clean Air Act (TCAA). This section addresses each of those requirements.

Protection of Public Health and Welfare – 30 TAC §116.111(a)(2)(A) The emissions from facilities included in this application will comply with all air quality rules and regulations and with the intent of the TCAA, including protection of public health and welfare. Applicable regulations for the condensate upgrader facility are as follows:

Chapter 101 – General Air Quality Rules The facilities included in this application will operated in accordance with the General Rules relating to circumvention, nuisance, traffic hazard, notification requirements for emissions events and scheduled maintenance, startup and shutdown activities, sampling, sampling ports, emissions inventory requirements, sampling procedures, compliance with Environmental Protection Agency standards, the Primary and Secondary National Ambient Air Quality Standards, inspection fees, emissions fees, and all other applicable General Rules.

Chapter 106 – Permits by Rule Equistar is subject to and will operate in compliance with all requirements of 30 TAC Chapter 106. Please refer to Section 8 for a summary of Permit by Rule authorizations that are being incorporated into Permit 4682B as part of this project.

Chapter 111 – Visible Emissions and Particulate Matter Facilities included in this application are subject to and will operate in compliance with the applicable requirements of 30 TAC Chapter 111.

Chapter 112 – Sulfur Compounds The Corpus Christi Complex is subject to and will operate in compliance with the applicable requirements of 30 TAC Chapter 112.

Chapter 113 – Toxic Materials This chapter references the regulations under 40 CFR Part 63. Applicability for those regulations is addressed below.

Chapter 114 – Motor Vehicles There are no motor vehicles specifically associated with the facilities included in this application. To the extent that motor vehicles are owned by Equistar, the company will comply with applicable requirements in 30 TAC Chapter 114.

Chapter 115 – Volatile Organic Compounds (VOC) Facilities at the Corpus Christi Complex are subject to and will operate in compliance with the applicable requirements of 30 TAC Chapter 115. The specific sources included in this application are not subject to requirements under 30 TAC Chapter 115.

Chapter 116 – New Construction or Modification Facilities included in this application are subject to and will operate in compliance with the applicable requirements of 30 TAC Chapter 116.

Chapter 117 – Nitrogen Compounds Facilities at the Corpus Christi Complex are subject to and will operate in compliance with the applicable requirements of 30 TAC Chapter 117. The specific sources included in this application are not subject to requirements under 30 TAC Chapter 117.

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Chapter 118 – Air Pollution Episodes Facilities included in this application will operate in compliance with the applicable requirements of 30 TAC Chapter 118.

Chapter 122 – Federal Operating Permits Equistar will update Title V Permit No. O1486 as required.

Impact on Schools There are no schools located within 3,000 feet of the Corpus Christi Complex.

Measurement of Emissions – 30 TAC §116.111(a)(2)(B) Emissions will be sampled upon request of the Executive Director of the TCEQ.

BACT Technology – 30 TAC §116.111(a)(2)(C) Section 7 of this application provides a detailed best available control technology analysis for the facilities included in this application. Section 8 addresses BACT for PBR and SP incorporations.

NSPS – 30 TAC §116.111(a)(2)(D) Facilities included in this application are subject to and will operate in compliance with the applicable requirements of the following New Source Performance Standards (NSPS):

40 CFR 60, Subpart A General Provisions

Other facilities at the Corpus Christi Complex are subject to other NSPS Subparts as specified in Permit O1486.

NESHAP – 30 TAC §116.111(a)(2)(E) Facilities included in this application are not subject any National Emission Standards for Hazardous Air Pollutants Subparts (NESHAP). Other facilities at the Corpus Christi Complex are subject to other NESHAP Subparts as specified in Permit O1486.

NESHAP for Source Categories – 30 TAC §116.111(a)(2)(F) Facilities included in this application are subject to and will operate in compliance with the applicable requirements of the following National Emission Standards for Hazardous Air Pollutants for Source Categories (a.k.a. Maximum Achievable Control Technology (MACT)) Subparts:

40 CFR Part 63, Subpart A General Provisions

Other facilities at the Corpus Christi Complex are subject to other MACT Subparts as specified in Permit O1486.

Performance Demonstration – 30 TAC §116.111(a)(2)(G) The facilities included in this application will perform as represented in the application and as required by the permit.

Nonattainment Review – 30 TAC §116.111(a)(2)(H) Nueces County is currently classified as attainment/unclassifiable for all pollutants. Nonattainment New Source Review (NNSR) is not applicable to this project.

Prevention of Significant Deterioration Review – 30 TAC §116.111(a)(2)(I) The Corpus Christi Complex is an existing major source for PSD purposes. The CO and GHG emissions are more than the significant emission thresholds so PSD review is required for this project. See Section 7 for a detailed PSD applicability analysis.

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Air Dispersion Modeling – §116.111(a)(2)(J) Equistar will provide dispersion modeling results demonstrating compliance with all applicable air quality standards and guidelines as required.

Hazardous Air Pollutants – 30 TAC §116.111(a)(2)(K) The Corpus Christi Complex is subject to MACT standards; therefore, it is not an affected source subject to the requirements of FCAA 112(g).

Mass Cap and Trade Allowances – 30 TAC §116.111(a)(2)(L) The Corpus Christi Complex is not located in the Houston-Galveston-Brazoria ozone nonattainment and, therefore, not subject to the Mass Emissions Cap and Trade (MECT) program.

Public Notice – 30 TAC §116.111(b) Equistar will publish notice for this project as required by 30 TAC §39.402.

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APPENDIX A

Emission Calculations (Confidential)

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APPENDIX B

Federal Permitting Tables

This section contains the following tables:

Table 1F Table 2F – NOx Table 2F – CO Table 3F – CO Table 2F – VOC Table 2F – SO2 Table 2F – CO2e Table 3F – CO2e

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Permit No.: 4682B Application Submittal Date: December 2019

RN: 100221662

City: Corpus Christi

Permit Unit I.D.: TBD Permit Name: Olefins Complex

Other1

VOC NOx GHG

Nonattainment? Yes Yes No No No No No No No

PSD? No No Yes Yes Yes Yes Yes Yes Yes

Existing site PTE (tpy)? >100 >100 >100 >100 >100 >100 >100 >100 >100,000

Proposed project emission increases (tpy from 2F)2 18.12 28.93 206.46 n/a n/a n/a 28.93 2.61 97,709.43

Is the existing site a major source? yes yes yes yes yes yes yes yes yes2If not, is the project a major source by itself? n/a n/a n/a n/a n/a n/a n/a n/a n/a

If netting required, estimated start of construction?

5 years prior to start of construction February 2015 contemporaneous

Estimated start of operation February 2020 periodNet contemporaneous change, including proposed project, from Table 3F. (tpy)

n/a n/a 206.46 n/a n/a n/a n/a n/a 97,709.43

Major NSR Applicable? no no yes no no no no no yes

1 Other PSD pollutants. [Pb, H2S, TRS, H2SO4, Fluoride excluding HF, ect.]

2 Sum of proposed emissions minus baseline emissions, increases only.

The representations made above and on the accompanying tables are true and correct to the best of my knowledge.

Signature Title Date

TCEQ - 10154 (Revised 04/12) Table 1FThese forms are for use by facilities subject to air quality permit requirements and maybe revised periodically. (APDG 5912v2)

TABLE 1F

Company: Equistar Chemicals, LP (CN600124705)

Facility Location: 1501 McKinzie Rd

County: Nueces

Permit Activity: New Source Modification X

February 2020

Complete for all Pollutants with a Project Emission Increase.

POLLUTANTS

OzoneCO PM PM10 PM2.5 NOx SO2

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Pollutant: NOx

A B C

FIN EPN

1L-2019A

KNOCKOUTPT10 4682B 7.30 7.30 24.17 - 16.87 - 16.87

2L-2019B

KNOCKOUTPT11 4682B 6.74 6.74 18.81 - 12.07 - 12.07

3 - - - - - - - - - -4 - - - - - - - - - -5 - - - - - - - - - -6 - - - - - - - - - -7 - - - - - - - - - -8 - - - - - - - - - -9 - - - - - - - - - -10 - - - - - - - - - -11 - - - - - - - - - -12 - - - - - - - - - -13 - - - - - - - - - -14 - - - - - - - - - -15 - - - - - - - - - -16 - - - - - - - - - -17 - - - - - - - - - -18 - - - - - - - - - -19 - - - - - - - - - -

Notes:

Project

Increase(tons/yr)

Page Subtotal: 28.93

Table 2F - NOxProject Emission Increase

Permit No.: 4682BBaseline Period: 2016-2017

Affected or Modified Facilities Permit No.

Actual

Emissions(tons/yr)

Baseline Emissions(tons/yr)

Proposed Emissions(tons/yr)

Projected Actual Emissions(tons/yr)

Difference

((C or B)-A)(tons/yr)

Correction(tons/yr)

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Pollutant: CO

A B C

FIN EPN

1L-2019A

KNOCKOUTPT10 4682B 37.42 37.42 152.24 - 114.83 - 114.83

2L-2019B

KNOCKOUTPT11 4682B 36.96 36.96 128.60 - 91.64 - 91.64

3 - - - - - - - - - -4 - - - - - - - - - -5 - - - - - - - - - -6 - - - - - - - - - -7 - - - - - - - - - -8 - - - - - - - - - -9 - - - - - - - - - -10 - - - - - - - - - -11 - - - - - - - - - -12 - - - - - - - - - -13 - - - - - - - - - -14 - - - - - - - - - -15 - - - - - - - - - -16 - - - - - - - - - -17 - - - - - - - - - -18 - - - - - - - - - -19 - - - - - - - - - -

Notes:

Project

Increase(tons/yr)

Page Subtotal: 206.46

Table 2F - COProject Emission Increase

Permit No.: 4682BBaseline Period: 2016-2017

Affected or Modified Facilities Permit No.

Actual

Emissions(tons/yr)

Baseline Emissions(tons/yr)

Proposed Emissions(tons/yr)

Projected Actual Emissions(tons/yr)

Difference

((C or B)-A)(tons/yr)

Correction(tons/yr)

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Company: Equistar Chemicals, LPPermit Application Number: TBD Criteria Pollutant: CO

A B

FIN EPNL-2019A

KNOCKOUTPT10 N/A 37.00 - 37.00 -

L-2019BKNOCKOUTPT

11 N/A 13.84 - 13.84 -

D10.0004, L-2019A, L-2019B

BX001FL, 10, 11 N/A 54.97 - 54.97 -

L-2019AKNOCKOUTPT

10 N/A 58.46 - 58.46 -

L-2019BKNOCKOUTPT

11 N/A 44.39 - 44.39 -

D10.0004, L-2019A, L-2019B

BX001FL, 10, 11 N/A 54.97 - 54.97 -

3 (current) (various) (various) 4682B Current Application [see 2F] [see 2F] [see 2F] 206.46 206.46Summary of Contemporaneous Changes Total 263.63 - 470.09 206.46

1Individual Table 3Fs should be used to summarize the project emission increase and net emissions increase for each criteria pollutant.2The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed.3Emisson Point No. as designated in NSR Permit or Emissions Inventory.4All records and calculations for these values must be available upon request.5All records and calculations for these values must be available upon request.6Proposed (column A) - Baseline (column B).7If portion of the decrease not creditable, enter creditable amount

Project Notes1 The emissions calculated for this project line item are being replaced by the emissions calculated for this application submittal.2 The emissions calculated for this project line item are being replaced by the emissions calculated for this application submittal.

Note that TCEQ's website also lists a pending application for Permit 136589; however, this application is being cancelled by Equistar and is therefore not listed above.

Creditable Decrease or

Increase7

1 11/23/2015PCP: Flare Tip Replacement for

Both Olefin Flares

TABLE 3F - COPROJECT CONTEMPORANEOUS CHANGES1

Project Date2

Facility at Which Emission Change

Occurrred3 Permit No. Project Name or ActivityBaseline Period

(years)

Proposed Emissions

(tons/year)4

Baseline Emissions

(tons/year)5

Difference

(A-B)6

136589

6/6/2019 136589PCP: Flare Tip Revision of Permit

for Both Olefin Flares2

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Pollutant: VOC

A B C

FIN EPN

1L-2019A

KNOCKOUTPT10 4682B 17.52 6.94 16.02 - 9.08 - 9.08

2L-2019B

KNOCKOUTPT11 4682B 20.26 5.61 14.65 - 9.04 - 9.04

3 - - - - - - - - - -4 - - - - - - - - - -5 - - - - - - - - - -6 - - - - - - - - - -7 - - - - - - - - - -8 - - - - - - - - - -9 - - - - - - - - - -10 - - - - - - - - - -11 - - - - - - - - - -12 - - - - - - - - - -13 - - - - - - - - - -14 - - - - - - - - - -15 - - - - - - - - - -16 - - - - - - - - - -17 - - - - - - - - - -18 - - - - - - - - - -19 - - - - - - - - - -

Notes:

Project

Increase(tons/yr)

Page Subtotal: 18.12

Table 2F - VOCProject Emission Increase

Permit No.: 4682BBaseline Period: 2016-2017

Affected or Modified Facilities Permit No.

Actual

Emissions(tons/yr)

Baseline Emissions(tons/yr)

Proposed Emissions(tons/yr)

Projected Actual Emissions(tons/yr)

Difference

((C or B)-A)(tons/yr)

Correction(tons/yr)

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Pollutant: SO2

A B C

FIN EPN

1L-2019A

KNOCKOUTPT10 4682B 0.31 0.31 2.66 - 2.36 - 2.36

2L-2019B

KNOCKOUTPT11 4682B 0.03 0.03 0.28 - 0.25 - 0.25

3 - - - - - - - - - -4 - - - - - - - - - -5 - - - - - - - - - -6 - - - - - - - - - -7 - - - - - - - - - -8 - - - - - - - - - -9 - - - - - - - - - -10 - - - - - - - - - -11 - - - - - - - - - -12 - - - - - - - - - -13 - - - - - - - - - -14 - - - - - - - - - -15 - - - - - - - - - -16 - - - - - - - - - -17 - - - - - - - - - -18 - - - - - - - - - -19 - - - - - - - - - -

Notes:

Project

Increase(tons/yr)

Page Subtotal: 2.61

Table 2F - SO2Project Emission Increase

Permit No.: 4682BBaseline Period: 2015-2016

Affected or Modified Facilities Permit No.

Actual

Emissions(tons/yr)

Baseline Emissions(tons/yr)

Proposed Emissions(tons/yr)

Projected Actual Emissions(tons/yr)

Difference

((C or B)-A)(tons/yr)

Correction(tons/yr)

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Pollutant: CO2e

A B C

FIN EPN

1L-2019A

KNOCKOUTPT10 4682B - - 48,957.92 - 48,957.92 - 48,957.92

2L-2019B

KNOCKOUTPT11 4682B - - 48,751.51 - 48,751.51 - 48,751.51

3 - - - - - - - - - -4 - - - - - - - - - -5 - - - - - - - - - -6 - - - - - - - - - -7 - - - - - - - - - -8 - - - - - - - - - -9 - - - - - - - - - -10 - - - - - - - - - -11 - - - - - - - - - -12 - - - - - - - - - -13 - - - - - - - - - -14 - - - - - - - - - -15 - - - - - - - - - -16 - - - - - - - - - -17 - - - - - - - - - -18 - - - - - - - - - -19 - - - - - - - - - -

Notes:

Table 2F - CO2eProject Emission Increase

Permit No.: 4682BBaseline Period: n/a

Affected or Modified Facilities Permit No.

Actual

Emissions(tons/yr)

Baseline Emissions(tons/yr)

Proposed Emissions(tons/yr)

Projected Actual Emissions(tons/yr)

Difference

((C or B)-A)(tons/yr)

Correction(tons/yr)

Project

Increase(tons/yr)

Page Subtotal: 97,709.43- The Proposed Emissions (B) above are the project increase only because GHG emissions are not currently quantified. Since GHG emissions are not reported in the EI, baseline emissions are conservatively treated as zero.

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Company: Equistar Chemicals, LPPermit Application Number: TBD Criteria Pollutant: CO2e

A B

FIN EPN1 (current) (various) (various) 4682B Current Application [see 2F] [see 2F] [see 2F] 97,709.43 97,709.43

Summary of Contemporaneous Changes Total - - 97,709.43 97,709.43

1Individual Table 3Fs should be used to summarize the project emission increase and net emissions increase for each criteria pollutant.2The start of operation date for the modified or new facilities. Attach Table 4F for each project reduction claimed.3Emisson Point No. as designated in NSR Permit or Emissions Inventory.4All records and calculations for these values must be available upon request.5All records and calculations for these values must be available upon request.6Proposed (column A) - Baseline (column B).7If portion of the decrease not creditable, enter creditable amount

No other projects occurred during the contemporaneous period that addressed GHG emission increases.

Creditable Decrease or

Increase7

TABLE 3F - GHGPROJECT CONTEMPORANEOUS CHANGES1

Project Date2

Facility at Which Emission Change

Occurrred3 Permit No. Project Name or ActivityBaseline Period

(years)

Proposed Emissions

(tons/year)4

Baseline Emissions

(tons/year)5

Difference

(A-B)6

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APPENDIX C

RBLC Search Results

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Table C-1RBLC Search Results: Flare

Permit Date Between 01/01/2009 And 11/20/2019And Process Contains 'flare'revised to exclude open flares; only relevant pollutants shown

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

AK-0082

POINT THOMSON PRODUCTION FACILITY

EXXON MOBIL CORPORATION Drilling, HP, and LP Flares 19.31 Gas 50 MMscf/yr

50 MMscf/yr Drilling Flare, 35 MMscf/yr HP Flare-Pilot/Purge, 20 MMscf/yr LP Flare-Pilot/Purge

Volatile Organic Compounds (VOC) N 0.14 LB/MMBTU

BACT-PSD 0

AK-0083KENAI NITROGEN OPERATIONS AGRIUM U.S. INC. Three (3) Flares 19.31 Natural Gas 1.25 MMBTU/H

1.25 MMBtu/hr Ammonia Tank Flare, 0.4 MMBtu/hr Emergency Flare, and 1.25 MMBtu/hr Small Flare

Volatile Organic Compounds (VOC) P

Work Practice Requirements and Limited Use (limit venting to 168 hr/yr each during startup, shutdown, and maintenance events) 0.0054 LB/MMBTU

BACT-PSD 0

FL-0318HIGHLANDS ETHANOL FACILITY VERENIUM Product Loadout and Flare 70.19 14.8 T/H

pper hour (TPH) and in any consecutive twelve month period 129,298 tons which is the equivalent to an ethanol production rate of 39.4 million gallons per year (MGPY) which when blended with gasoline will equal up to 41.5 MGPY of denatured

ethanol product. This process:

The denatured ethanol product will be loaded onto tank trucks at a rate of 600 gallons per minute. Vapors displaced from the trucks will be exhausted to a flare (006). The product loadout flare will have a rated capacity of 9.42 million Btu per hour (mmBtu/hr) to control vapors displaced from the trucks during the loading of denatured ethanol. The trucks are assumed as not in dedicated ethanol service (i.e., some trucks will have returned from delivering gasoline and gasoline vapors will be displaced).

Volatile Organic Compounds (VOC) P

The flare shall be operated at all times when truck loading operations are taking place. Only E95 to E98 shall only be loaded into the trucks. 0 OPACITY

BACT-PSD 0

The flare shall be designed for and operated with no visible emissions (VE) except for periods not to exceed a total of 5 minutes during any 2

consecutive hours The flare system is designed to combust vapors displaced from the trucks during the loading of the denatured ethanol product. The trucks are assumed to not to be in dedicated denatured ethanol product service (i.e., some trucks will have returned from delivering gasoline and gasoline vapors will be displaced). The product loadout flare will have a rated capacity of 9.42 mmBtu/hr. NG will be used as the fuel for the pilot which has a rated capacity of 0.18 mmBtu/hr. If NG is not available, propane will be used for the pilot until NG becomes available.

FL-0318HIGHLANDS ETHANOL FACILITY VERENIUM

Wastewater Treatment Plant, Biogas Conditioning and Flare 22.9 1640 G/M

The facility will include a WWTP to treat process wastewaters and to condition the resulting biogas for use as fuel in the boilers or to flare it when it cannot be used in the boilers. The effluent from the WWTP will be recycled to the plant or reused for irrigation. The flow through the WWTP will be approximately 1,640 gallons per minute (gpm). The WWTP and associated systems will consist of an equalization basin, clarifiers, anaerobic reactors, aeration basin and sand filters.

Volatile Organic Compounds (VOC) N

The flare shall be operated with a flame present at all times. The presence of a flare pilot flame shall be monitored using a thermocouple or any other equivalent device to detect the presence of a flame. 5.4 T/YR

BACT-PSD 0

The flare shall be designed for and operated with no visible emissions (VE) except for periods not to exceed a total of 5 minutes during any 2

consecutive hours. The flare system is designed to combust biogas when the biomass and backup boilers are not operating. The WWTP flare will have a rated capacity of 44.03 mmBtu/hr. Natural gas will be used as fuel for the pilot which has a rated capacity of 0.18 mmBtu/hr. If NG is not available, propane will be used for the pilot until NG becomes available.

*GU-0050

MCELMO CREEK UNIT OIL PRODUCTION FACILITY

RESOLUTE NATURAL RESOURCES COMPANY Main Flare 50.001 Natural gas 618104 SCF/HR

Process gas from the TEG dehydrator and upset gases from the oilfield operation are ducted to the Main Flare.

Volatile Organic Compounds (VOC) P

Operate flare in accordance with 40 CFR 60.18; use air-assist technology; ensure that net heating value for dilution is greater than or equal to 24.4 BTU/scf2. 95.4 TPY

CUMULATIVE 365-DAY ROLLING TOTAL

BACT-PSD 0

Federal consent decree requirement. Process gas from the TEG dehydrator and upset gases from the oilfield operation are ducted to the Main Flare.

IA-0106

CF INDUSTRIES NITROGEN, LLC - PORT NEAL NITROGEN COMPLEX

CF INDUSTRIES NITROGEN, LLC Flares 61.012 natural gas 0

Three (3) flares of different sizes. One is for syngas, one is for the ammonia process, and one is for ammonia tanks. All have the same BACT limits

Volatile Organic Compounds (VOC) P

good operating practices and use of natural gas 0

BACT-PSD 0

There are no emission limits on the flares. The BACT limits for the flares is a set of work practices which includes the units being fueled with natural gas, maintaining pressure during idling, and proper design.

IN-0179OHIO VALLEY RESOURCES, LLC

OHIO VALLEY RESOURCES, LLC

FRONT END PROCESS FLARE 19.31

NATURAL GAS PILOT 0.25 MMBTU/H

HEAT INPUT IS FOR NATURAL GAS PILOT ONLY. SSM EMISSIONS ARE CONTROLLED BY THE FLARE AND ARE LIMITED TO 336 HOURS OF VENTING PER YEAR.

Volatile Organic Compounds (VOC) P

NATURAL GAS FOR PILOT, FLARE MINIMIZATION PRACTICES 0.0054 LB/MMBTU

3-HR AVERAGE

BACT-PSD 0 SSM VENTING LIMITED TO 336 HR PER YEAR.

IN-0179OHIO VALLEY RESOURCES, LLC

OHIO VALLEY RESOURCES, LLC BACK END AMMONIA FLARE 19.31

NATURAL GAS 0.25 MMBTU/H

HEAT INPUT IS FOR PILOT ONLY. SSM EMISSIONS ARE CONTROLLED BY THE FLARE AND ARE LIMITED TO 336 HR/YR.

Volatile Organic Compounds (VOC) P

NATURAL GAS PILOT, FLARE MINIMIZATION PRACTICES 0.0054 LB/MMBTU

3-HR AVERAGE

BACT-PSD 0 SSM VENTING LIMITED TO 336 HR PER YEAR.

LA-0295WESTLAKE FACILITY

EQUISTAR CHEMICALS, LP

M-Line Production Area Flare (FL061) (Z2, EQT 19) 19.31 0

Flare is subject to 40 CFR 60.18 and Subpart DDD.

Volatile Organic Compounds (VOC) P Good combustion practices 8882.92 LB/H

HOURLY MAXIMUM

BACT-PSD

NSPS , OPERATING PERMIT 0

Annual VOC emissions from the Cogeneration Plant Flare (449, EQT 326); the M-Line Production Area Flare (Z2, EQT 19); and the Plant 5 Flare (Z1, EQT 138) (not addressed in the PSD permit) are limited to 465.93 TPY (GRP 12).

LA-0295WESTLAKE FACILITY

EQUISTAR CHEMICALS, LP

Cogeneration Plant Flare (449, EQT 326) 19.31 0

Flare is subject to 40 CFR 60.18 and Subpart DDD.

Volatile Organic Compounds (VOC) P Good combustion practices 165.75 LB/H

HOURLY MAXIMUM

BACT-PSD

NSPS , OPERATING PERMIT 0

Annual VOC emissions from the Cogeneration Plant Flare (449, EQT 326); the M-Line Production Area Flare (Z2, EQT 19); and the Plant 5 Flare (Z1, EQT 138) (not addressed in the PSD permit) are limited to 465.93 TPY (GRP 12).

LA-0296

LAKE CHARLES CHEMICAL COMPLEX LDPE UNIT

SASOL CHEMICALS (USA) LLC

LLPDE/LDPE Multi-Point Ground Flare (EQT 640) 19.31 0

The flare controls the following process vents: Purgas C-1 (LDPE-C-1, EQT 0641)

Compressor Area C-2 (LDPE-C-2, EQT 0642)Comonomer Degassing Column C-3 (LDPE-C-3,

EQT 0643)Isopentane Degassing Column C-4 (LDPE-C-4,

EQT 0644)Purification Bed Regeneration C-7 (LDPE-C-7,

EQT 0645) Analyzer Vents C-8 (LDPE-C-8, EQT 0646)

Vent Recovery Accumulator C-9 (LDPE-C-9, EQT 0647)

Volatile Organic Compounds (VOC) P

Compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS; minimization of flaring through adherence to the SSMP developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas. 305.08 LB/HR

HOURLY MAXIMUM

BACT-PSD

NSPS , MACT , OPERATING PERMIT 0

BACT is compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS, including, but not limited to, the closed vent system requirements of 40 CFR 63.983, the flare compliance assessment requirements of 40 CFR 63.987 and 40 CFR 63.2450(f), and the flame

monitoring requirements of 40 CFR 63.987. BACT is also determined to be minimization of flaring through adherence to the Lake Charles Chemical Complex’s startup, shutdown, and malfunction plan (SSMP) developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas.

LA-0316CAMERON LNG FACILITY CAMERON LNG LLC Flares (3 units) 19.39 natural gas 0

ground flare EU20 = 91 MM BTU/hrlow pressure flare EU20A = 1077 mm btu/hr

Volatile Organic Compounds (VOC) P

proper plant operations and maintaining the presence of the flame at the flare tips when vent gas is routed to the flares 0

BACT-PSD NSPS 0

Search Criteria

1 of 14

Page 66: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

LA-0331CALCASIEU PASS LNG PROJECT

VENTURE GLOBAL CALCASIEU PASS, LLC

Flares (WRMFLR, CLDFLR, LPFLR) 19.39 Natural Gas 21.74 MM BTU/h

Flare system to provide safe and reliable disposal of streams released during start-up, shutdown, plant upsets, and emergency conditions.

Volatile Organic Compounds (VOC) P

Proper equipment design, proper operation, and good combustion practices. 0.006 LB/H

BACT-PSD

OPERATING PERMIT 0 When Flare is Operating.

NM-0052 ZIA II GAS PLANTDCP MIDSTREAM L.P.

Units FL1 &amp; FL2: Refinery Flares (Inlet Gas Flare &amp; Acid Gas Flare) 19.33

natural gas, acid gas 2.3 mmBtu/hr

Only for routine or predictable Startup, Shutdown, or Maintenance of units controlled by Flares (Blowdown/Venting, Amine Unit-Acid Gas Injection well maintenance)

Volatile Organic Compounds (VOC) P

NOx, CO, PM10, PM2.5, SO2 controlled through Good Combustion Practices (GCP), pipeline quality natural gas for pilot; limits on flaring events. VOC & CO2e controlled through GCP, limits on flaring and meet 40 CFR 60.18. 2558.4 PPH

BACT-PSD

NSPS , SIP , OPERATING PERMIT 98

OH-0308

SUN COMPANY, INC., TOLEDO REFINERY SUNOCO, INC. FLARE, STEAM ASSISTED 50.008

PROCESS GASES 155.44 MMBTU/H

FLARE, STEAM ASSISTED, TO CONTROL HYDROCARBON EMISSIONS FROM PROCESS VENTS. SUBJECT TO PART 63, SUBPART CC AND PART 60, SUBPARTS A, J, AND GGG.

Volatile Organic Compounds (VOC) A

FLARE IS CONTROL FOR HYDROCARBONS 0.84 LB/H MACT

NSPS , MACT , SIP 0

OH-0368PALLAS NITROGEN LLC

PALLAS NITROGEN LLC

Back-End Process with flare (P003) 61.012 150 MMBTU/H

Back-End Process Flare (emissions from non-routine releases from the amine regeneration and MDEA storage system) - the pilot flare has a maximum heat input of 0.9 mmBtu/hr (operates 8,760 hours per year) and the flare has a maximum heat input of 150 mmBtu/hr.

Volatile Organic Compounds (VOC) B

utilizing a flare with good combustion practices, natural gas to fuel pilots, and venting flare during only start-up, shutdown

and malfunction events. This emissions unit shall be equipped with a flare to control OC emissions. The flare shall be fired with natural gas and shall be operated with at least 98% control efficiency. 85.5 LB/H

BACT-PSD 98 0.57 lb/mmBtu of heat input

OH-0368PALLAS NITROGEN LLC

PALLAS NITROGEN LLC

Ammonia Synthesis Process with flare (P004) 61.012 150 MMBTU/H

Ammonia Synthesis Process with flare - the pilot flare has a maximum heat input of 0.9 mmBtu/hr (operates 8,760 hours per year) and the flare has a maximum heat input of 150 mmBtu/hr.

Volatile Organic Compounds (VOC) B

utilizing a flare with good combustion practices, natural gas to fuel pilots, and venting flare during only start-up, shutdown

and malfunction events. This emissions unit shall be equipped with a flare to control OC emissions. The flare shall be fired with natural gas and shall be operated with at least 98% control efficiency. 85.5 LB/H

BACT-PSD 98 0.57 lb/mmBtu of heat input

OH-0378

PTTGCA PETROCHEMICAL COMPLEX

PTTGCA PETROCHEMICAL COMPLEX

High Pressure Ground Flare (P003) 19.31 Natural gas 1.8 MMBTU/H

1.8 MMBtu/hr high-pressure, multi-point, staged ground flare.

The high pressure (HP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the HP ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing

associated with control requirements. The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805.

Volatile Organic Compounds (VOC) A

The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805. The control efficiency is 98% 4.494 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 98

The high pressure (HP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the HP ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing

associated with control requirements. The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805.

OH-0378

PTTGCA PETROCHEMICAL COMPLEX

PTTGCA PETROCHEMICAL COMPLEX

Low Pressure Ground Flare (P004) 19.31 Natural gas 0.78 MMBTU/H

0 8 tu/ o p essu e, u t po t, staged ground flare.

The low pressure (LP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the ECU ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing associated with control

requirements. The low pressure (LP) flare controls VOC emissions from units P804 and P805.

Volatile Organic Compounds (VOC) A

The low pressure (LP) flare controls VOC emissions from units P804 and P805. The control efficiency is 98%. 1.97 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 98

The low pressure (LP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the ECU ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing associated with control

requirements. The low pressure (LP) flare controls VOC emissions from units P804 and P805.

*OR-0052

COLUMBIA RIDGE LANDFILL AND RECYCLING CENTER

WASTE MANAGEMENT DISPOSAL SERVICES OF OREGON, INC. Flares 19.32 landfill gas 1156 MMdscfCH4/yr

Two enclosed flares (FLR-1, FLR-2, both rated at 4,000 scfm, 132 MMBtu/hr) and smaller utility flare (FLR-3, rated at 1,350 scfm, 40.5 MMBtu/hr)

Volatile Organic Compounds (VOC) N 20

PPM @3%O2

BACT-PSD 0

Only FLR 2 requires BACT for VOC and NMOC. One of the primary purposes of the flare is to destroy the VOC and NMOC in the landfill gas. Most LFG flares guarantee a 98% to 99% destruction of organics. Typical BACT determinations for LFG flares is 98% destruction efficiency or 20 ppmv as hexane @ 3% oxygen. The New Source Performance Standard for Municipal Solid Waste Landfills (40 CFR Subpart WWW) also requires a reduction of NMOC by 98% by weight. BACT for FLR-2 will be established as a 98% destruction or 20 ppmv as hexane @ 3% oxygen VOC and NMOC.

SC-0183NUCOR STEEL - BERKELEY NUCOR STEEL

Vacuum Tank Degasser Equipment (vaccum tank degasser flares) 19.39 0

Vacuum degasser flares (flare 1/existing and flare 2/new) are used to control emissions from vacuum degasser tanks no.1 and no.2 (both existing).

Volatile Organic Compounds (VOC) N 0

BACT-PSD 0

TX-0574VALERO THREE RIVERS REFINERY

DIAMOND SHAMROCK REFINING COMPANY L.P. FLARE MSS 50.008 0

EMISSIONS FROM MSS ACTIVITIES THAT ARE CONTROLLED BY THE PLANT FLARES.

Volatile Organic Compounds (VOC) P BEST PRACTICES 0 SEE NOTE

BACT-PSD 0

USE BEST PRACTICES TO RECOVER FLUIDS TO PROCESS AS MUCH AS POSSIBLE BEFORE VENTING RESIDUALS TO FLARE.

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Page 67: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

TX-0575

SABINA PETROCHEMICALS LLC

SABINA PETROCHEMICALS LLC

HIGH AND LOW PRESSURE FLARES 19.31

NATURAL GAS 1600 T/YR

THE NOX EMISSIONS INCREASES FROM THE FLARES ARE DUE TO THE COMBUSTION OF NATURAL GAS USED AS SWEEP GAS IN THE FLARE HEADER SYSTEM. THE NATURAL GAS ALSO HELPS TO MAINTAIN THE MINIMUM HEATING VALUE NECESSARY TO ENSURE DESTRUCTION OF THE VOCS IN THE VENT STREAMS. THE NATURAL GAS FLOW WAS NOT COMPLETELY ACCOUNTED FOR IN THE ORIGINAL PERMIT REPRESENTATIONS AND IS BEING ADDED TO THE PERMIT AT THIS TIME. THERE IS NO APPLICABLE POST-COMBUSTION TECHNOLOGY TO REDUCE NOX EMISSIONS FROM FLARES. EMISSIONS ARE MINIMIZED BY PROPER OPERATION OF THE FLARES, INCLUDING COMPLIANCE WITH THE APPLICABLE PROVISIONS IN SECTION 60.18 OF SUBPART A OF THE FEDERAL NEW SOURCE PERFORMANCE STANDARDS (NSPS) IN 40 CFR PART 60 AND THE PROVISIONS OF SPECIAL CONDITION 13 OF PERMIT 41945. SPECIAL CONDITION 13 REQUIRES THE FLARES TO BE OPERATED WITH A FLAME PRESENT AT ALL TIMES, MONITORING TO ENSURE THE PRESENCE OF A CONSTANT PILOT FLAME, NO VISIBLE EMISSIONS, AND CONTINUOUS FLOW RATE AND BTU CONTENT MONITORING OF THE FLARED STREAMS. THESE OPERATING REQUIREMENTS WERE DETERMINED TO SATISFY LAER IN THE ORIGINAL PERMITTING

Volatile Organic Compounds (VOC) A FLARE 0.32 T/YR ANNUAL LAER 98

TX-0671 PROJECT JUMBOM&G RESINS USA, LLC Flare 11.31 Natural gas 0

Flare is required to meet 40CFR60.18, and a DRE of 99% for compounds up to three carbons, 98% for others. No flaring of halogenated compounds is allowed.

Volatile Organic Compounds (VOC) P Meet 40CFR60.18 for steam assisted flare 99 PERCENT

DRE AT ALL TIMES

BACT-PSD NSPS , NESHAP 99

TX-0672

CORPUS CHRISTI LIQUEFACTION PLANT

CORPUS CHRISTI LIQUEFACTION LLC Flares 19.39 natural gas 0

2 wet/dry flares are used mainly during maintenance, startup, and shutdown. There is a small flow from such things as compressor seals leaks during normal operation. Flares are required to meet 40 CFR 60.18.

Volatile Organic Compounds (VOC) A Flare is BACT for MSS 0

BACT-PSD 0

Flare will be desinged to meet 99% DRE for <C3 and 98% DRE for C3+

TX-0677

FREEPORT LNG LIQUEFACTION PLANT

FREEPORT LNG DEVELOPMENT LP Flare 19.39 natural gas 0

Ground Flare is for maintenance, startup, and shutdown. Flare is pressure-assisted.

Volatile Organic Compounds (VOC) A

Designed to meet 98% DRE for less than C3 and 99% DRE for C3+ 0

BACT-PSD 0

TX-0678

FREEPORT LNG PRETREATMENT FACILITY

FREEPORT LNG DEVELOPMENT LP Flare 19.39 natural gas 0 Ground flare is pressure-assisted.

Volatile Organic Compounds (VOC) A

Designed for 99% DRE for less than C3 and 99% control for C3+ compounds 0

BACT-PSD 0

TX-0681 OLEFINS PLANT

FORMOSA PLASTICS CORPORATION Flare 19.31

vent gases and NG 0

flare combusts the vents from pellet degassing silos to control the VOC in the vent gases. Flare will meet 40CFR60.18.

Volatile Organic Compounds (VOC) P 98% DRE for VOC 0

BACT-PSD

NSPS , MACT , SIP 98

TX-0684ENTERPRISE MONT BELVIEU COMPLEX

ENTERPRISE PRODUCTS OPERATING LLC Flare 19.39

Natural gas and process gas 0

Flare will be designed and operated to minimize VOC and CO emissions and will operate in accordance with NSPS Section. 60.18. Flare will be air assisted by a variable speed fan, will have waste stream composition identified by a highly reactive volatile organic compound (HRVOC) monitor, will only receive a waste stream that does not vary excessively in volumetric flow rate, and will primarily only receive easily combustible compounds containing three carbon compounds or less.

Volatile Organic Compounds (VOC) P

proper flare design and operation in accordance with NSPS 60.18. 99.5% DRE for VOC. 4.75 TPY

OTHER CASE-BY-CASE NSPS 99.5

TX-0697

ETHYLENE PRODUCTION PLANT

THE DOW CHEMICAL COMPANY Low Pressure Flare 19.31

NG and waste gas 10000 Btu/scf

The low pressure flare will be used to control the majority of all normal emissions from the ethylene and propylene process, including emission from the tanks noted in the permit and from the bleeds on dual seal compressors and some relief valves

Volatile Organic Compounds (VOC) P

flare will meet NSPS 60.18 standards for continuous pilot flame, waste gas heat content and tip velocity 98 %

FOR VOCS C4 AND HIGHER

BACT-PSD NSPS 98

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Page 68: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

TX-0703

LOW DENSITY POLYETHYLENE (LDPE) PLANT

FORMOSA PLASTICS CORPORATION

Low Density Polyethylene Production 63.999 0

The new LDPE unit will make low density polyethylene from ethylene in a polymerization process which is comprised of compression, intermediate reactions, polymerization, recovery, extrusion, drying, degassing and blending steps. Affected process equipment and sources of air emissions include numerous vents and filters, loading emissions, process fugitive components in various liquid and gas services, a diesel generator, a cooling tower, MSS emissions. A flare and a regenerative thermal oxidizer will be used as control devices.

Volatile Organic Compounds (VOC) B

Process vents (upstream of the extruder) will be flared or recycled to process for control of VOC. No control is proposed for process vents at or downstream of the extruder (meets Tier 1 BACT for emissions

in the range of 155 lb VOC/MMlb product). The pellet degassing silos are routed to a flare or Regenerative Thermal Oxidizer for control of VOC emissions. The Flare will meet 40CFR60.18 requirements and will

provide 98 wt.% DRE. Fixed roof storage tans are less than 25,000 gallon capacity, in service for materials of less than 0.5 psia, painted white and aluminum, located out of direct sunlight and either re-filled off-site or by submerged fill

on-site. Fugitive emissions are mimized by a modified 28 VHP Leak Detection and Repair

program, using 500 ppm leak definition. VOC emission from loading are controlled by submerged fill for materials of vapor pressure <0.5 psia. For materials with VP>0.5 psia fom the Vinylacetate column, a (OL3 Flare) will be used for control of VOC emissions. 0

BACT-PSD

NSPS , MACT , SIP 0

TX-0703

LOW DENSITY POLYETHYLENE (LDPE) PLANT

FORMOSA PLASTICS CORPORATION Flare 19.31 natural gas 0

The pellet degassin silos, loading emissions for materials with VP>0.5 psia, MSS emissions and all other vents that may need control are routed to a flare with 98% DRE

Volatile Organic Compounds (VOC) P

flare combustion of VOC vent emissions. Flare will achieve 98% DRE 0

BACT-PSD

NSPS , MACT , SIP 98

TX-0706NATURAL GAS FRACTIONATION

OCCIDENTAL CHEMICAL CORPORATION Emergency Flare 19.39 0

The emergency flare will achieve a DRE of 98%. It will meet the requirements of 40 CFR 60.18 and will achieve a destruction efficiency of 98%

Volatile Organic Compounds (VOC) P

Emergency Flare will meet 40CFR 60.18 requirements and 98% DRE 0

BACT-PSD NSPS 98

TX-0721

PROPANE DEHYDROGENATION UNIT

THE DOW CHEMICAL COMPANY Flare 19.31

NG or gaseous fuels 0

DRE for VOC for all flares is 99% destruction efficiency for compounds up to three carbons, all others 98%. No flaring of halogenated compounds allowed.

Volatile Organic Compounds (VOC) P

good combustion. 99% DRE for compounds up to three carbons, all others 98%. No flaring of halogenated compounds 5.5 LB/MMSCF

AP-42 FACTOR USED FOR NG COMBUSTION

BACT-PSD NSPS , NESHAP 98

TX-0722ORGANIC CHEMICAL MANUFACTURING

CHEVRON PHILLIPS CHEMICAL LP Flare 50.999

Waste gas and assist gas 0

Emissions from the flares during normal operations result from combustion of waste gas and assist gas.

Volatile Organic Compounds (VOC) B

The VOC emission rates are estimated based on an assumed destruction efficiency of 99% for three carbons and smaller and 98% for four carbons. The worst case emission factor for NOX and CO from the TCEQ guidance document was utilized due to the variability of the vent stream heating value. 0 LAER NSPS , NESHAP 98

TX-0728

PEONY CHEMICAL MANUFACTURING FACILITY BASF ammonia flare 19.31

Natural gas, ammonia, hydrogen 106396 MMBtu/yr

g pA flare is used to combust unreacted hydrogen, destroy impure hydrogen/ammonia streams, and to control process shutdowns. The Flare is claimed to achieve 99% control for ammonia. Best Available Control Technology (BACT) for carbon monoxide (CO) from flares is good combustion practices. Sulfur Dioxide (SO2) emissions are controlled with the use of pipeline quality natural gas as fuel gas. The only volatile organic compound (VOC) emitted from the flare result from using natural gas as fuel gas. As the flare is not used for control of VOC, assist gas is not needed to control emissions of particulate

matter (PM).Emission rates provided are for worst case maintenance, start-up and shutdown (MSS) scenarios.

Volatile Organic Compounds (VOC) N 9.32 LB/H

OTHER CASE-BY-CASE N/A 0

All VOC is from fuel gas not waste gas. Emission rates provided are for worst-case MSS scenarios.

TX-0812

CRUDE OIL PROCESSING FACILITY

GRAVITY MIDSTREAM CORPUS CHRISTI LLC Refinery Flares 19.33 0

Flare used for process turnarounds and upsets only.

Volatile Organic Compounds (VOC) A

The flare must conform to 40 CFR § 60.18 requirements. Vent stream composition and flow must be continuously monitored to demonstrate compliance. 0

BACT-PSD NSPS , SIP 98 NSPS Ja, 30 TAC 115, SUBCHAPTER D

TX-0823

LYONDELL CHEMICAL BAYPORT CHOATE PLANT

LYONDELL CHEMICAL COMPANY FLARE 64.999 0

Receives process vents emissions from the isobutylene absorber (94% removal of VOC from the vent stream for recycle to the process). The absorber effluent is then routed to the flare, for additional 98-99 wt.-% VOC destruction of organic compounds. Estimated combined effects of the absorber and flare - approximately 99.8 wt.-% DRE. Relief valves & rupture discs routed to atmosphere relieve only in emergencies.

Volatile Organic Compounds (VOC) A

Compliance with 40 CFR 60.18 to demonstrate 98-99.9 wt% VOC DRE 0 LAER 98

TX-0835CHANNELVIEW TERMINAL TARGA PROCESS VENTS TO FLARE 19.33

NATURAL GAS 10410100 SCF/YR

control of normal operations and MSS produced waste gas.

The site produces off-gas intermittently as part of normal operations. A portion of the off-gas can contain contaminates that will affect the quality of the off-gas being used as refinery fuel. In event the off-gas may not be routed to the hot oil heater (EPN: H-4) due to the intermittent production and/or low quality, the flare is the only effective facility to control waste gas emissions.

Volatile Organic Compounds (VOC) P

The flare 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 installed a continuous flow monitor and composition analyzer. Operation conditions and flaring of off-gas shall be re-evaluated every two-years. 0 LAER 98

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

*TX-0872CONDENSATE SPLITTER FACILITY

MAGELLAN PROCESSING, L.P. Flare (Routine and MSS) 19.33

NATURAL GAS 12000 SCR.H

the control of wastewater and MSS activitiesâ €™ emissions. In cases where the fuel gas is unable to be used in the heater, the site is permitted to flare the fuel gas. Please see SC 34.

Volatile Organic Compounds (VOC) P

Control for desalter 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. 19.13 LB/H

BACT-PSD NSPS 0 NSPS Ja

TX-0574VALERO THREE RIVERS REFINERY

DIAMOND SHAMROCK REFINING COMPANY L.P. FLARE MSS 50.008 0

EMISSIONS FROM MSS ACTIVITIES THAT ARE CONTROLLED BY THE PLANT FLARES.

Sulfur Oxides (SOx) P BEST PRACTICES 0 SEE NOTE

BACT-PSD 0

USE BEST PRACTICES TO RECOVER FLUIDS TO PROCESS AS MUCH AS POSSIBLE BEFORE VENTING RESIDUALS TO FLARE. MINIMIZE AMOUNT OF SULFUR COMPOUNDS VENTED TO FLARE.

AK-0074

ENDICOTT PRODUCTION FACILITY

BP EXPLORATION (ALASKA) Flares 19.39 Fuel gas 500 MMscf/day High pressure and low pressure flares

Sulfur Dioxide (SO2) P

Limit concentration of hydrogen sulfide in fuel gas to 1000 ppmv. 1000 PPMV ATANY TIME

BACT-PSD 0

FL-0333

HARVEST ENERGY GARDEN - ORLANDO

HARVEST POWER ORLANDO, LLC

Open Utility Flare rated at 1200 scfm 19.39 Biogas 0

An open utility, candlestick-type backup flare rated at 1,200 scfm of biogas (manufactured by Perennial Energy, Inc., Model No. FLR-301, or equivalent). The open flare stack will be 8 inches in diameter and 24 feet in height with a total volumetric flow rate of 3,454 acfm. At the design biogas flow rate with a biogas methane content 40% to 60%, the destruction efficiency is 98%

overall destruction of total hydrocarbons. The flare will operate under the following scenarios: when the engines are not available because of downtime or maintenance; or when biogas is generated in excess of the design fuel requirements of the engines. The biogas will not be treated when combusted in the flare.

Sulfur Dioxide (SO2) P Good combustion practice 39

TONS PER YEAR

OTHER CASE-BY-CASE OTHER 0

The emissions of SO2 from the combinede combustion sources in this project shall not exceed 39 tons per consecutive 12 months. Compliance with this SO2 emissions cap shall be demonstrated on a 12-month rolling basis using the following information: the H2S level in the scrubbed and unscrubbed biogas fired, the amount of biogas fired in each combustion source, and the assumption that all sulfur is converted to SO2.

*GU-0050

MCELMO CREEK UNIT OIL PRODUCTION FACILITY

RESOLUTE NATURAL RESOURCES COMPANY Main Flare 50.001 Natural gas 618104 SCF/HR

Process gas from the TEG dehydrator and upset gases from the oilfield operation are ducted to the Main Flare.

Sulfur Dioxide (SO2) P

Operate flare in accordance with 40 CFR 60.18. 60 TPY

CUMULATIVE 365-DAY ROLLING TOTAL

BACT-PSD 0

Monitor sulfur content, in terms of H2S, of the gas stream to the flare for calculating SO2 emissions. Federal consent decree requirement. Process gas from the TEG dehydrator and upset gases from the oilfield operation are ducted to the Main Flare.

*KS-0032CHS MCPHERSON REFINERY, INC.

CHS MCPHERSON REFINERY, INC. Main Flare and Alky Flare 19.33

natural gas/refinery gas 0

BACT for sulfur dioxide and PM/PM10 consists of design and workplace standards since there is no currently feasible method to measure emissions exiting the flares. BACT is using a flare design that meets the requirements of the New Source Performance Standards Subpart A, Section 60.18 (40 CFR Part 60.18) and API recommended practice 520 and 521. Workplace standards include continuously monitoring the pilot flame with infrared sensors, maintaining a natural gas/refinery gas purge so that the heating value of gases to the flares is not less than 300 Btu/scf, and using steam assisted mixing at the flare tip for smokeless operation.

Sulfur Dioxide (SO2) N 0

BACT-PSD 0

BACT for sulfur dioxide and PM/PM10 consists of design and workplace standards since there is no currently feasible method to measure emissions exiting the flares. BACT is using a flare design that meets the requirements of the New Source Performance Standards Subpart A, Section 60.18 (40 CFR Part 60.18) and API recommended practice 520 and 521. Workplace standards include continuously monitoring the pilot flame with infrared sensors, maintaining a natural gas/refinery gas purge so that the heating value of gases to the flares is not less than 300 Btu/scf, and using steam assisted mixing at the flare tip for smokeless operation.

LA-0296

LAKE CHARLES CHEMICAL COMPLEX LDPE UNIT

SASOL CHEMICALS (USA) LLC

LLPDE/LDPE Multi-Point Ground Flare (EQT 640) 19.31 0

The flare controls the following process vents: Purgas C-1 (LDPE-C-1, EQT 0641)

Compressor Area C-2 (LDPE-C-2, EQT 0642)Comonomer Degassing Column C-3 (LDPE-C-3,

EQT 0643)Isopentane Degassing Column C-4 (LDPE-C-4,

EQT 0644)Purification Bed Regeneration C-7 (LDPE-C-7,

EQT 0645) Analyzer Vents C-8 (LDPE-C-8, EQT 0646)

Vent Recovery Accumulator C-9 (LDPE-C-9, EQT 0647)

Sulfur Dioxide (SO2) P

Compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS; minimization of flaring through adherence to the SSMP developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas. 1.15 LB/HR

HOURLY MAXIMUM

BACT-PSD

OPERATING PERMIT 0

BACT is compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS, including, but not limited to, the closed vent system requirements of 40 CFR 63.983, the flare compliance assessment requirements of 40 CFR 63.987 and 40 CFR 63.2450(f), and the flame

monitoring requirements of 40 CFR 63.987. BACT is also determined to be minimization of flaring through adherence to the Lake Charles Chemical Complex’s startup, shutdown, and malfunction plan (SSMP) developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas.

LA-0331CALCASIEU PASS LNG PROJECT

VENTURE GLOBAL CALCASIEU PASS, LLC

Flares (WRMFLR, CLDFLR, LPFLR) 19.39 Natural Gas 21.74 MM BTU/h

Flare system to provide safe and reliable disposal of streams released during start-up, shutdown, plant upsets, and emergency conditions.

Sulfur Dioxide (SO2) P

Proper equipment design, proper operation, and good combustion practices. Combustion of Low Sulfur Gas in Pilot fuel. 4 PPMV

BACT-PSD

OPERATING PERMIT 0

Limit Unit is ppmv H2S. When Flare is Operating. Limit to Sulfur Content of Fuel.

NM-0052 ZIA II GAS PLANTDCP MIDSTREAM L.P.

Units FL1 &amp; FL2: Refinery Flares (Inlet Gas Flare &amp; Acid Gas Flare) 19.33

natural gas, acid gas 2.3 mmBtu/hr

Only for routine or predictable Startup, Shutdown, or Maintenance of units controlled by Flares (Blowdown/Venting, Amine Unit-Acid Gas Injection well maintenance)

Sulfur Dioxide (SO2) P

NOx, CO, PM10, PM2.5, SO2 controlled through Good Combustion Practices (GCP), pipeline quality natural gas for pilot; limits on flaring events. VOC & CO2e controlled through GCP, limits on flaring and meet 40 CFR 60.18. 13023.6 PPH

BACT-PSD

NSPS , SIP , OPERATING PERMIT 98

OH-0308

SUN COMPANY, INC., TOLEDO REFINERY SUNOCO, INC. FLARE, STEAM ASSISTED 50.008

PROCESS GASES 155.44 MMBTU/H

FLARE, STEAM ASSISTED, TO CONTROL HYDROCARBON EMISSIONS FROM PROCESS VENTS. SUBJECT TO PART 63, SUBPART CC AND PART 60, SUBPARTS A, J, AND GGG.

Sulfur Dioxide (SO2) N 4.2 LB/H N/A NSPS , SIP 0

THE H2SO4 LIMIT FROM PART 60 SUBPART J WAS USED TO ESTABLISH AN SO2 EMISSION FACTOR OF 0.027 LB/MMBTU.

OH-0362LIMA REFINING COMPANY Acid Gas Flare (P050) 50.006 0

Sulfur Recovery Units Acid Gas Flare, non-assisted

Sulfur Dioxide (SO2) P

Use of natural gas or refinery fuel gas for the flare pilot flame and sweep gases, and implementation of a load shedding plan to minimize periods of gas release from the sulfur recovery units (Claus 1, Claus 2 and Claus 3 units) to the acid gas flare 0.001 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

0.001 ton/rolling, 12-month period from pilot and sweep gas firing only

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

*OR-0052

COLUMBIA RIDGE LANDFILL AND RECYCLING CENTER

WASTE MANAGEMENT DISPOSAL SERVICES OF OREGON, INC. Flares 19.32 landfill gas 1156 MMdscfCH4/yr

Two enclosed flares (FLR-1, FLR-2, both rated at 4,000 scfm, 132 MMBtu/hr) and smaller utility flare (FLR-3, rated at 1,350 scfm, 40.5 MMBtu/hr)

Sulfur Dioxide (SO2) N 300 PPM

BACT-PSD 0

Generally, the majority of landfill gas collected is burned in the landfill gas engines to generate electricity. Gas generated beyond the capacity of the landfill gas engines to burn is sent to the enclosed flares. Gas is also routed to the enclosed flares during maintenance to the engines. In addition, the syngas generated by the plasma gasifier can be sent to the flare (FLR-1). The utility flare is infrequently used as a backup during maintenance of the other flares.

SC-0183NUCOR STEEL - BERKELEY NUCOR STEEL

Vacuum Tank Degasser Equipment (vaccum tank degasser flares) 19.39 0

Vacuum degasser flares (flare 1/existing and flare 2/new) are used to control emissions from vacuum degasser tanks no.1 and no.2 (both existing).

Sulfur Dioxide (SO2) N 0

BACT-PSD 0

TX-0728

PEONY CHEMICAL MANUFACTURING FACILITY BASF ammonia flare 19.31

Natural gas, ammonia, hydrogen 106396 MMBtu/yr

g pA flare is used to combust unreacted hydrogen, destroy impure hydrogen/ammonia streams, and to control process shutdowns. The Flare is claimed to achieve 99% control for ammonia. Best Available Control Technology (BACT) for carbon monoxide (CO) from flares is good combustion practices. Sulfur Dioxide (SO2) emissions are controlled with the use of pipeline quality natural gas as fuel gas. The only volatile organic compound (VOC) emitted from the flare result from using natural gas as fuel gas. As the flare is not used for control of VOC, assist gas is not needed to control emissions of particulate

matter (PM).Emission rates provided are for worst case maintenance, start-up and shutdown (MSS) scenarios.

Sulfur Dioxide (SO2) N 1.02 LB/H

OTHER CASE-BY-CASE N/A 0

Emission rates provided are for worst-case MSS scenarios.

IA-0106

CF INDUSTRIES NITROGEN, LLC - PORT NEAL NITROGEN COMPLEX

CF INDUSTRIES NITROGEN, LLC Flares 61.012 natural gas 0

Three (3) flares of different sizes. One is for syngas, one is for the ammonia process, and one is for ammonia tanks. All have the same BACT limits

Nitrous Oxide (N2O) P

good operating practices and use of natural gas 0

BACT-PSD 0

There are no emission limits on the flares. The BACT limits for the flares is a set of work practices which includes the units being fueled with natural gas, maintaining pressure during idling, and proper design.

AK-0082

POINT THOMSON PRODUCTION FACILITY

EXXON MOBIL CORPORATION Drilling, HP, and LP Flares 19.31 Gas 50 MMscf/yr

50 MMscf/yr Drilling Flare, 35 MMscf/yr HP Flare-Pilot/Purge, 20 MMscf/yr LP Flare-Pilot/Purge

Nitrogen Oxides (NOx) N 0.068 LB/MMBTU

BACT-PSD 0

AK-0083KENAI NITROGEN OPERATIONS AGRIUM U.S. INC. Three (3) Flares 19.31 Natural Gas 1.25 MMBTU/H

1.25 MMBtu/hr Ammonia Tank Flare, 0.4 MMBtu/hr Emergency Flare, and 1.25 MMBtu/hr Small Flare

Nitrogen Oxides (NOx) P

Work Practice Requirements and Limited Use (limit venting to 168 hr/yr each during startup, shutdown, and maintenance events) 0.068 LB/MMBTU

BACT-PSD 0

AL-0249EVONIK DEGUSSA CORPORATION

EVONIK DEGUSSA CORPORATION

HCN PRODUCTION UNIT - FLARE A1 19.31 0

HCN PRODUCTION UNIT EMERGENCY FLARE - A1

Nitrogen Oxides (NOx) N GOOD COMBUSTION PRACTICES 14.29 LB/H

ANNUAL AVERAGE

BACT-PSD 0

AL-0249EVONIK DEGUSSA CORPORATION

EVONIK DEGUSSA CORPORATION

HCN PRODUCTION UNIT - FLARE A2 19.31 0

HCN PRODUCTION UNIT EMERGENCY FLARE A2

Nitrogen Oxides (NOx) N GOOD COMBUSTION PRACTICES 14.29 LB/H

ANNUAL AVERAGE

BACT-PSD 0

AL-0249EVONIK DEGUSSA CORPORATION

EVONIK DEGUSSA CORPORATION

HCN PRODUCTION UNIT - TANK FARM FLARE - A5 19.31 0

HCN PRODUCTION UNIT TANK FARM FLARE A5

Nitrogen Oxides (NOx) N GOOD COMBUSTION PRACTICES 1.79 LB/H

BACT-PSD 0

AL-0249EVONIK DEGUSSA CORPORATION

EVONIK DEGUSSA CORPORATION

ANDRUSSOW HCN PRODUCTION UNIT - FLARE HCNA - 2 19.31 0 ANDRUSSOW FLARE HCNA - 2

Nitrogen Oxides (NOx) N GOOD COMBUSTION PRACTICES 20.01 LB/H

BACT-PSD 0

DC-0009

BLUE PLAINS ADVANCED WASTEWATER TREATEMENT PLANT

DISTRICT OF COLUMBIA WATER AND SEWER AUTHORITY Emergency Flares (2) 19.32

Digester Gas 126 MMBTU/hr

Two Emergency flares, each rated at 126 MMBTU/hr

Nitrogen Oxides (NOx) N 0.042 LB/MMBTU LAER

SIP , OPERATING PERMIT 0

0.042 lb/MMBTU limit based on initial vendor information. Vendor later revised to 0.06 lb/MMBTU as guarantee. Initial stack test exceeded 0.042 lb/MMBTU. Further testing planned. Applicant may seek permit amendment if they find 0.042 lb/MMBTU not attainable.

FL-0333

HARVEST ENERGY GARDEN - ORLANDO

HARVEST POWER ORLANDO, LLC

Open Utility Flare rated at 1200 scfm 19.39 Biogas 0

An open utility, candlestick-type backup flare rated at 1,200 scfm of biogas (manufactured by Perennial Energy, Inc., Model No. FLR-301, or equivalent). The open flare stack will be 8 inches in diameter and 24 feet in height with a total volumetric flow rate of 3,454 acfm. At the design biogas flow rate with a biogas methane content 40% to 60%, the destruction efficiency is 98%

overall destruction of total hydrocarbons. The flare will operate under the following scenarios: when the engines are not available because of downtime or maintenance; or when biogas is generated in excess of the design fuel requirements of the engines. The biogas will not be treated when combusted in the flare.

Nitrogen Oxides (NOx) P

Good combustion practices will be utilized at all times to ensure emissions from the flare system are minimized. 39

TONS PER YEAR

OTHER CASE-BY-CASE 0

NOX Emission Cap: The emissions of NOX from the combustion sources in this project (EU-001, 002, and 004, combined) shall not exceed 39 tons per consecutive 12 months. Compliance with this NOX emissions cap shall be demonstrated on a 12-month rolling basis using the following

equation.[(0.8 tons NOx/MMm3)(FlareBiogas)] + [(EFengine)(lb/454)(ton/2000 lb)(Engine1kW-

hours + Engine2kW-hours)] ≤ 39.0 TPY, NOx Where:

FlareBiogas=Rolling 12-month total of Biogas burned in flare (EU-004), million m3 (MMm3)

EFengine=NOx emission rate from most recent annual stack test, g/kW-hour

EnginekW-hours=Rolling 12-month total of operating kW-hours for each engine (EU-001 and

EU-002)If necessary, the permittee shall adjust engine operation to comply with the NOx emissions cap.

*GU-0050

MCELMO CREEK UNIT OIL PRODUCTION FACILITY

RESOLUTE NATURAL RESOURCES COMPANY Main Flare 50.001 Natural gas 618104 SCF/HR

Process gas from the TEG dehydrator and upset gases from the oilfield operation are ducted to the Main Flare.

Nitrogen Oxides (NOx) P

Operate flare in accordance with 40 CFR 60.18. 13.4 TPY

CUMULATIVE 365-DAY ROLLING TOTAL RACT 0

Federal consent decree requirement. Process gas from the TEG dehydrator and upset gases from the oilfield operation are ducted to the Main Flare.

IN-0179OHIO VALLEY RESOURCES, LLC

OHIO VALLEY RESOURCES, LLC

FRONT END PROCESS FLARE 19.31

NATURAL GAS PILOT 0.25 MMBTU/H

HEAT INPUT IS FOR NATURAL GAS PILOT ONLY. SSM EMISSIONS ARE CONTROLLED BY THE FLARE AND ARE LIMITED TO 336 HOURS OF VENTING PER YEAR.

Nitrogen Oxides (NOx) P

NATURAL GAS PILOT, FLARE MINIMIZATION PRACTICES 0.068 LB/MMBTU

3-HR AVERAGE

BACT-PSD 0

SSM VENTING HOURS LIMITED TO 336 PER YEAR.

IN-0179OHIO VALLEY RESOURCES, LLC

OHIO VALLEY RESOURCES, LLC BACK END AMMONIA FLARE 19.31

NATURAL GAS 0.25 MMBTU/H

HEAT INPUT IS FOR PILOT ONLY. SSM EMISSIONS ARE CONTROLLED BY THE FLARE AND ARE LIMITED TO 336 HR/YR.

Nitrogen Oxides (NOx) P

NATURAL GAS PILOT, FLARE MINIMIZATION PRACTICES 0.068 LB/MMBTU

3-HR AVERAGE

BACT-PSD 0 SSM EVENTS LIMITED TO 336 HRS PER YEAR

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

LA-0248DIRECT REDUCTION IRON PLANT

CONSOLIDATED ENVIRONMENTAL MANAGEMENT INC - NUCOR

DRI-110 - DRI Unit No. 1 Hot Flare 19.39

DRI Reducing Gas 1180 acfm

The reducing furnace must run as close to steady state operation as possible in order to produce product of acceptable quality. Due to the nature of the reducing gas recycle system periodic shifts in pressure may occur. The pressure of the reducing gas must be maintained below that of the seal gas system or an uncontrolled release of reducing gas will result from the top seal and the bottom seal. To maintain this condition, the reducing gas is occasionally flared to prevent a rise in pressure. The Hot Flare prevents an uncontrolled release of carbon monoxide from the system by combusting the reducing gas.

Nitrogen Oxides (NOx) P

A low-NOX fuel is one which results in a lower generation rate of NOX over traditional fossil fuels, on an equal energy basis. DRI reducing gas is a low-NOX fuel, generating less NOX per unit of energy as natural gas. This property is due to the low-BTU value of reducing gas, which burns at a cooler temperature, preventing the formation of much of the NOX seen with hotter natural gas combustion. 1.27 LB/H

BACT-PSD 0

LA-0248DIRECT REDUCTION IRON PLANT

CONSOLIDATED ENVIRONMENTAL MANAGEMENT INC - NUCOR

DRI-210 - DRI Unit No. 1 Hot Flare 19.39

DRI Reducing Gas 1180 acfm

The reducing furnace must run as close to steady state operation as possible in order to produce product of acceptable quality. Due to the nature of the reducing gas recycle system periodic shifts in pressure may occur. The pressure of the reducing gas must be maintained below that of the seal gas system or an uncontrolled release of reducing gas will result from the top seal and the bottom seal. To maintain this condition, the reducing gas is occasionally flared to prevent a rise in pressure. The Hot Flare prevents an uncontrolled release of carbon monoxide from the system by combusting the reducing gas.

Nitrogen Oxides (NOx) P

A low-NOX fuel is one which results in a lower generation rate of NOX over traditional fossil fuels, on an equal energy basis. DRI reducing gas is a low-NOX fuel, generating less NOX per unit of energy as natural gas. This property is due to the low-BTU value of reducing gas, which burns at a cooler temperature, preventing the formation of much of the NOX seen with hotter natural gas combustion. 1.27 LB/H

BACT-PSD 0

LA-0295WESTLAKE FACILITY

EQUISTAR CHEMICALS, LP

Cogeneration Plant Flare (449, EQT 326) 19.31 0

Flare is subject to 40 CFR 60.18 and Subpart DDD.

Nitrogen Oxides (NOx) N 12.6 LB/H

HOURLY MAXIMUM

BACT-PSD

OPERATING PERMIT 0

Annual NOx emissions from the Cogeneration Plant Flare (449, EQT 326); the M-Line Production Area Flare (Z2, EQT 19); and the Plant 5 Flare (Z1, EQT 138) (not addressed in the PSD permit) are limited to 36.65 TPY (GRP 12).

LA-0296

LAKE CHARLES CHEMICAL COMPLEX LDPE UNIT

SASOL CHEMICALS (USA) LLC

LLPDE/LDPE Multi-Point Ground Flare (EQT 640) 19.31 0

The flare controls the following process vents: Purgas C-1 (LDPE-C-1, EQT 0641)

Compressor Area C-2 (LDPE-C-2, EQT 0642)Comonomer Degassing Column C-3 (LDPE-C-3,

EQT 0643)Isopentane Degassing Column C-4 (LDPE-C-4,

EQT 0644)Purification Bed Regeneration C-7 (LDPE-C-7,

EQT 0645) Analyzer Vents C-8 (LDPE-C-8, EQT 0646)

Vent Recovery Accumulator C-9 (LDPE-C-9, EQT 0647)

Nitrogen Oxides (NOx) P

Compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS; minimization of flaring through adherence to the SSMP developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas. 174.09 LB/HR

HOURLY MAXIMUM

BACT-PSD

OPERATING PERMIT 0

BACT is compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS, including, but not limited to, the closed vent system requirements of 40 CFR 63.983, the flare compliance assessment requirements of 40 CFR 63.987 and 40 CFR 63.2450(f), and the flame

monitoring requirements of 40 CFR 63.987. BACT is also determined to be minimization of flaring through adherence to the Lake Charles Chemical Complex’s startup, shutdown, and malfunction plan (SSMP) developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas.

LA-0316CAMERON LNG FACILITY CAMERON LNG LLC Flares (3 units) 19.39 natural gas 0

ground flare EU20 = 91 MM BTU/hrlow pressure flare EU20A = 1077 mm btu/hr

Nitrogen Oxides (NOx) P

proper plant operations and maintaining the presence of the flame at the flare tips when vent gas is routed to the flares 0

BACT-PSD 0

LA-0331CALCASIEU PASS LNG PROJECT

VENTURE GLOBAL CALCASIEU PASS, LLC

Flares (WRMFLR, CLDFLR, LPFLR) 19.39 Natural Gas 21.74 MM BTU/h

Flare system to provide safe and reliable disposal of streams released during start-up, shutdown, plant upsets, and emergency conditions.

Nitrogen Oxides (NOx) P

Proper equipment design, proper operation, and good combustion practices. 0.068 LB/MM BTU

BACT-PSD

OPERATING PERMIT 0 When Flare is Operating.

NM-0052 ZIA II GAS PLANTDCP MIDSTREAM L.P.

Units FL1 &amp; FL2: Refinery Flares (Inlet Gas Flare &amp; Acid Gas Flare) 19.33

natural gas, acid gas 2.3 mmBtu/hr

Only for routine or predictable Startup, Shutdown, or Maintenance of units controlled by Flares (Blowdown/Venting, Amine Unit-Acid Gas Injection well maintenance)

Nitrogen Oxides (NOx) P

NOx, CO, PM10, PM2.5, SO2 controlled through Good Combustion Practices (GCP), pipeline quality natural gas for pilot; limits on flaring events. VOC & CO2e controlled through GCP, limits on flaring and meet 40 CFR 60.18. 695.2 PPH

BACT-PSD

NSPS , SIP , OPERATING PERMIT 98

The 2 emissions limits represent limits for Units FL1 and FL2.

OH-0308

SUN COMPANY, INC., TOLEDO REFINERY SUNOCO, INC. FLARE, STEAM ASSISTED 50.008

PROCESS GASES 155.44 MMBTU/H

FLARE, STEAM ASSISTED, TO CONTROL HYDROCARBON EMISSIONS FROM PROCESS VENTS. SUBJECT TO PART 63, SUBPART CC AND PART 60, SUBPARTS A, J, AND GGG.

Nitrogen Oxides (NOx) N 15.23 LB/H N/A SIP 0

OH-0362LIMA REFINING COMPANY Acid Gas Flare (P050) 50.006 0

Sulfur Recovery Units Acid Gas Flare, non-assisted

Nitrogen Oxides (NOx) P Use of good combustion practices 0.15 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

0.15 ton/rolling, 12-month period from pilot and sweep gas firing only

OH-0368PALLAS NITROGEN LLC

PALLAS NITROGEN LLC

Back-End Process with flare (P003) 61.012 150 MMBTU/H

Back-End Process Flare (emissions from non-routine releases from the amine regeneration and MDEA storage system) - the pilot flare has a maximum heat input of 0.9 mmBtu/hr (operates 8,760 hours per year) and the flare has a maximum heat input of 150 mmBtu/hr.

Nitrogen Oxides (NOx) B

utilizing a flare with good combustion practices, natural gas to fuel pilots, and venting flare during only start-up, shutdown and malfunction events 10.37 LB/H

BACT-PSD 0 0.068 lb/mmBtu of heat input

OH-0368PALLAS NITROGEN LLC

PALLAS NITROGEN LLC

Ammonia Synthesis Process with flare (P004) 61.012 150 MMBTU/H

Ammonia Synthesis Process with flare - the pilot flare has a maximum heat input of 0.9 mmBtu/hr (operates 8,760 hours per year) and the flare has a maximum heat input of 150 mmBtu/hr.

Nitrogen Oxides (NOx) B

utilizing a flare with good combustion practices, natural gas to fuel pilots, and venting flare during only start-up, shutdown and malfunction events 12.44 LB/H

BACT-PSD 0 0.068 lb/mmBtu of heat input

OH-0376IRONUNITS LLC - TOLEDO HBI

IRONUNITS LLC - TOLEDO HBI

Pressure Relief Vent Flare (P008) 81.9 0 Pressure Relief Vent Flare

Nitrogen Oxides (NOx) P

Minimize flaring from startup, shutdown, and upset events by operating in accordance

with flare minimization plan.Meet the 40 CFR 60.18 requirements. 121.21 LB/H

BACT-PSD 0

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

OH-0378

PTTGCA PETROCHEMICAL COMPLEX

PTTGCA PETROCHEMICAL COMPLEX

High Pressure Ground Flare (P003) 19.31 Natural gas 1.8 MMBTU/H

1.8 MMBtu/hr high-pressure, multi-point, staged ground flare.

The high pressure (HP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the HP ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing

associated with control requirements. The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805.

Nitrogen Oxides (NOx) P use of natural gas as pilot light fuel 0.536 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

The high pressure (HP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the HP ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing

associated with control requirements. The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805.

OH-0378

PTTGCA PETROCHEMICAL COMPLEX

PTTGCA PETROCHEMICAL COMPLEX

Low Pressure Ground Flare (P004) 19.31 Natural gas 0.78 MMBTU/H

0.78 MMBtu/hr low pressure, multi point, staged ground flare.

The low pressure (LP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the ECU ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing associated with control

requirements. The low pressure (LP) flare controls VOC emissions from units P804 and P805.

Nitrogen Oxides (NOx) P use of natural gas as pilot light fuel 0.232 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

The low pressure (LP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the ECU ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing associated with control

requirements. The low pressure (LP) flare controls VOC emissions from units P804 and P805.

*OR-0052

COLUMBIA RIDGE LANDFILL AND RECYCLING CENTER

WASTE MANAGEMENT DISPOSAL SERVICES OF OREGON, INC. Flares 19.32 landfill gas 1156 MMdscfCH4/yr

Two enclosed flares (FLR-1, FLR-2, both rated at 4,000 scfm, 132 MMBtu/hr) and smaller utility flare (FLR-3, rated at 1,350 scfm, 40.5 MMBtu/hr)

Nitrogen Oxides (NOx) N 0.6 LB/MMBTU

BACT-PSD 0

yfor flares that resulted in add-on controls for NOx emissions. BACT has almost universally been established as utilizing good combustion practices. There is a flare designed to have ultra low emissions (guaranteed 0.025 lb NOx/MMBtu) which would result in a 14 ton/year reduction for each of the enclosed flares. The existing enclosed flares have emissions in the 0.05 to 0.06 lb NOx/MMBtu range. The annualized cost to install a new ultra low emission flare is approximately $516,000. Costs to retrofit the existing flares could be slightly higher. The resulting cost effectiveness for NOx removal is about $36,900 per additional ton of NOx removed. In general, anything over $10,000 has not been considered cost effective in previous permit actions. BACT for the flares will be established at 0.06 lb NOx/MMBtu.

SC-0183NUCOR STEEL - BERKELEY NUCOR STEEL

Vacuum Tank Degasser Equipment (vaccum tank degasser flares) 19.39 0

Vacuum degasser flares (flare 1/existing and flare 2/new) are used to control emissions from vacuum degasser tanks no.1 and no.2 (both existing).

Nitrogen Oxides (NOx) N 0

BACT-PSD 0

TX-0575

SABINA PETROCHEMICALS LLC

SABINA PETROCHEMICALS LLC

HIGH AND LOW PRESSURE FLARES 19.31

NATURAL GAS 1600 T/YR

THE NOX EMISSIONS INCREASES FROM THE FLARES ARE DUE TO THE COMBUSTION OF NATURAL GAS USED AS SWEEP GAS IN THE FLARE HEADER SYSTEM. THE NATURAL GAS ALSO HELPS TO MAINTAIN THE MINIMUM HEATING VALUE NECESSARY TO ENSURE DESTRUCTION OF THE VOCS IN THE VENT STREAMS. THE NATURAL GAS FLOW WAS NOT COMPLETELY ACCOUNTED FOR IN THE ORIGINAL PERMIT REPRESENTATIONS AND IS BEING ADDED TO THE PERMIT AT THIS TIME. THERE IS NO APPLICABLE POST-COMBUSTION TECHNOLOGY TO REDUCE NOX EMISSIONS FROM FLARES. EMISSIONS ARE MINIMIZED BY PROPER OPERATION OF THE FLARES, INCLUDING COMPLIANCE WITH THE APPLICABLE PROVISIONS IN SECTION 60.18 OF SUBPART A OF THE FEDERAL NEW SOURCE PERFORMANCE STANDARDS (NSPS) IN 40 CFR PART 60 AND THE PROVISIONS OF SPECIAL CONDITION 13 OF PERMIT 41945. SPECIAL CONDITION 13 REQUIRES THE FLARES TO BE OPERATED WITH A FLAME PRESENT AT ALL TIMES, MONITORING TO ENSURE THE PRESENCE OF A CONSTANT PILOT FLAME, NO VISIBLE EMISSIONS, AND CONTINUOUS FLOW RATE AND BTU CONTENT MONITORING OF THE FLARED STREAMS. THESE OPERATING REQUIREMENTS WERE DETERMINED TO SATISFY LAER IN THE ORIGINAL PERMITTING

Nitrogen Oxides (NOx) N 9.07 T/YR ANNUAL LAER 0

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

TX-0728

PEONY CHEMICAL MANUFACTURING FACILITY BASF ammonia flare 19.31

Natural gas, ammonia, hydrogen 106396 MMBtu/yr

g pA flare is used to combust unreacted hydrogen, destroy impure hydrogen/ammonia streams, and to control process shutdowns. The Flare is claimed to achieve 99% control for ammonia. Best Available Control Technology (BACT) for carbon monoxide (CO) from flares is good combustion practices. Sulfur Dioxide (SO2) emissions are controlled with the use of pipeline quality natural gas as fuel gas. The only volatile organic compound (VOC) emitted from the flare result from using natural gas as fuel gas. As the flare is not used for control of VOC, assist gas is not needed to control emissions of particulate

matter (PM).Emission rates provided are for worst case maintenance, start-up and shutdown (MSS) scenarios.

Nitrogen Oxides (NOx) P no control 223.41 LB/H LAER N/A 0

The TPY emission rate is based on all operating scenarios. the lb/hr rate is based on worst case MSS scenarios.

IA-0106

CF INDUSTRIES NITROGEN, LLC - PORT NEAL NITROGEN COMPLEX

CF INDUSTRIES NITROGEN, LLC Flares 61.012 natural gas 0

Three (3) flares of different sizes. One is for syngas, one is for the ammonia process, and one is for ammonia tanks. All have the same BACT limits Methane P

good operating practices and use of natural gas 0

BACT-PSD 0

There are no emission limits on the flares. The BACT limits for the flares is a set of work practices which includes the units being fueled with natural gas, maintaining pressure during idling, and proper design.

OK-0142

WAYNOKA NATURAL GAS PROCESSING PLANT

ATLAS PIPELINE MIDCONTINENT WESTOK, LLC Flare, Amine Unit 19.39 Natural Gas 0 Amine Unit Flare Methane N 0

BACT-PSD 0 Mfg recommended operation and maintenance.

OK-0142

WAYNOKA NATURAL GAS PROCESSING PLANT

ATLAS PIPELINE MIDCONTINENT WESTOK, LLC Flares, Plant 19.39 Natural Gas 0 Plant Flare. Methane A Flare - Comply w/NSPS 60.18. 0

BACT-PSD 0 Mfg recommendations.

TX-0679

CORPUS CHRISTI LIQUEFACTION PLANT

CORPUS CHRISTI LIQUEFACTION LLC Flares 19.39 natural gas 0

2 wet/dry flares control emission during maintenance, startup, and shutdown. Flares must be designed to meet 40 CFR 60.18. Methane A

Design to 40 CFR 60.18 to achieve 99% DRE for methane 0

BACT-PSD 0

AK-0082

POINT THOMSON PRODUCTION FACILITY

EXXON MOBIL CORPORATION Drilling, HP, and LP Flares 19.31 Gas 50 MMscf/yr

50 MMscf/yr Drilling Flare, 35 MMscf/yr HP Flare-Pilot/Purge, 20 MMscf/yr LP Flare-Pilot/Purge

Carbon Monoxide N 0.37 LB/MMBTU

BACT-PSD 0

AK-0083KENAI NITROGEN OPERATIONS AGRIUM U.S. INC. Three (3) Flares 19.31 Natural Gas 1.25 MMBTU/H

1.25 MMBtu/hr Ammonia Tank Flare, 0.4 MMBtu/hr Emergency Flare, and 1.25 MMBtu/hr Small Flare

Carbon Monoxide P

Work Practice Requirements and Limited Use (limit venting to 168 hr/yr each during startup, shutdown, and maintenance events) 0.37 LB/MMBTU

BACT-PSD 0

*GU-0050

MCELMO CREEK UNIT OIL PRODUCTION FACILITY

RESOLUTE NATURAL RESOURCES COMPANY Main Flare 50.001 Natural gas 618104 SCF/HR

Process gas from the TEG dehydrator and upset gases from the oilfield operation are ducted to the Main Flare.

Carbon Monoxide P

Operate flare in accordance with 40 CFR 60.18. 73 TPY

CUMULATIVE 365-DAY ROLLING TOTAL

BACT-PSD 0

Federal consent decree requirement. Process gas from the TEG dehydrator and upset gases from the oilfield operation are ducted to the Main Flare.

IA-0106

CF INDUSTRIES NITROGEN, LLC - PORT NEAL NITROGEN COMPLEX

CF INDUSTRIES NITROGEN, LLC Flares 61.012 natural gas 0

Three (3) flares of different sizes. One is for syngas, one is for the ammonia process, and one is for ammonia tanks. All have the same BACT limits

Carbon Monoxide P

good operating practices and use of natural gas 0

BACT-PSD 0

There are no emission limits on the flares. The BACT limits for the flares is a set of work practices which includes the units being fueled with natural gas, maintaining pressure during idling, and proper design.

IN-0179OHIO VALLEY RESOURCES, LLC

OHIO VALLEY RESOURCES, LLC

FRONT END PROCESS FLARE 19.31

NATURAL GAS PILOT 0.25 MMBTU/H

HEAT INPUT IS FOR NATURAL GAS PILOT ONLY. SSM EMISSIONS ARE CONTROLLED BY THE FLARE AND ARE LIMITED TO 336 HOURS OF VENTING PER YEAR.

Carbon Monoxide P

NATURAL GAS PILOT, FLARE MINIMIZATION PRACTICES 0.37 LB/MMBTU

3-HR AVERAGE

BACT-PSD 0 SSM VENTING LIMITED TO 336 HR PER YEAR.

IN-0179OHIO VALLEY RESOURCES, LLC

OHIO VALLEY RESOURCES, LLC BACK END AMMONIA FLARE 19.31

NATURAL GAS 0.25 MMBTU/H

HEAT INPUT IS FOR PILOT ONLY. SSM EMISSIONS ARE CONTROLLED BY THE FLARE AND ARE LIMITED TO 336 HR/YR.

Carbon Monoxide P

NATURAL GAS PILOT, FLARE MINIMIZATION PRACTICES 0.37 LB/MMBTU

3-HR AVERAGE

BACT-PSD 0 SSM VENTING LIMITED TO 336 HR PER YEAR.

LA-0248DIRECT REDUCTION IRON PLANT

CONSOLIDATED ENVIRONMENTAL MANAGEMENT INC - NUCOR

DRI-110 - DRI Unit No. 1 Hot Flare 19.39

DRI Reducing Gas 1180 acfm

The reducing furnace must run as close to steady state operation as possible in order to produce product of acceptable quality. Due to the nature of the reducing gas recycle system periodic shifts in pressure may occur. The pressure of the reducing gas must be maintained below that of the seal gas system or an uncontrolled release of reducing gas will result from the top seal and the bottom seal. To maintain this condition, the reducing gas is occasionally flared to prevent a rise in pressure. The Hot Flare prevents an uncontrolled release of carbon monoxide from the system by combusting the reducing gas.

Carbon Monoxide P

The reducing gas is rich in carbon monoxide and hydrogen. The pilot for the flare is natural gas. Good combustion practices are used to reduce emissions of CO, as well as other pollutants, by optimizing conditions in the combustion zone of a fuel burning source. Good combustion practices typically entail introducing the proper ratio of combustion air to the fuel, maintaining a minimum temperature in the firebox of the combustor, or a minimum residence time of fuel and air in the combustion zone. By employing good combustion practices CO emissions may be greatly reduced. 1.47 LB/H

BACT-PSD 0

The hot flare will combust reducing gas, which contains a significant portion of carbon monoxide. Nucor will install a flare tip employing good combustion practices to control the generation of CO emissions due to incomplete combustion of reducing gas.

LA-0248DIRECT REDUCTION IRON PLANT

CONSOLIDATED ENVIRONMENTAL MANAGEMENT INC - NUCOR

DRI-210 - DRI Unit No. 1 Hot Flare 19.39

DRI Reducing Gas 1180 acfm

The reducing furnace must run as close to steady state operation as possible in order to produce product of acceptable quality. Due to the nature of the reducing gas recycle system periodic shifts in pressure may occur. The pressure of the reducing gas must be maintained below that of the seal gas system or an uncontrolled release of reducing gas will result from the top seal and the bottom seal. To maintain this condition, the reducing gas is occasionally flared to prevent a rise in pressure. The Hot Flare prevents an uncontrolled release of carbon monoxide from the system by combusting the reducing gas.

Carbon Monoxide P

The reducing gas is rich in carbon monoxide and hydrogen. The pilot for the flare is natural gas. Good combustion practices are used to reduce emissions of CO, as well as other pollutants, by optimizing conditions in the combustion zone of a fuel burning source. Good combustion practices typically entail introducing the proper ratio of combustion air to the fuel, maintaining a minimum temperature in the firebox of the combustor, or a minimum residence time of fuel and air in the combustion zone. By employing good combustion practices CO emissions may be greatly reduced. 1.27 LB/H

BACT-PSD 0

The hot flare will combust reducing gas, which contains a significant portion of carbon monoxide. Nucor will install a flare tip employing good combustion practices to control the generation of CO emissions due to incomplete combustion of reducing gas.

9 of 14

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

LA-0296

LAKE CHARLES CHEMICAL COMPLEX LDPE UNIT

SASOL CHEMICALS (USA) LLC

LLPDE/LDPE Multi-Point Ground Flare (EQT 640) 19.31 0

The flare controls the following process vents: Purgas C-1 (LDPE-C-1, EQT 0641)

Compressor Area C-2 (LDPE-C-2, EQT 0642)Comonomer Degassing Column C-3 (LDPE-C-3,

EQT 0643)Isopentane Degassing Column C-4 (LDPE-C-4,

EQT 0644)Purification Bed Regeneration C-7 (LDPE-C-7,

EQT 0645) Analyzer Vents C-8 (LDPE-C-8, EQT 0646)

Vent Recovery Accumulator C-9 (LDPE-C-9, EQT 0647)

Carbon Monoxide P

Compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS; minimization of flaring through adherence to the SSMP developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas. 947.25 LB/HR

HOURLY MAXIMUM

BACT-PSD

OPERATING PERMIT 0

BACT is compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS, including, but not limited to, the closed vent system requirements of 40 CFR 63.983, the flare compliance assessment requirements of 40 CFR 63.987 and 40 CFR 63.2450(f), and the flame

monitoring requirements of 40 CFR 63.987. BACT is also determined to be minimization of flaring through adherence to the Lake Charles Chemical Complex’s startup, shutdown, and malfunction plan (SSMP) developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas.

*LA-0306TOPCHEM POLLOCK, LLC

TOPCHEM POLLOCK, LLC

Process Flare FL-16-1 (EQT034) 19.31 2.17 MM BTU/hr

Flare shall not operate more than 4 hours above normal firing rate in any 24 consecutive hours and 148 hours per year.

Carbon Monoxide P

Compliance with the Louisiana Non-NSPS Flare Requirements 0.87 LB/H

HOURLY MAXIMUM

BACT-PSD

OPERATING PERMIT 0 Correct Flare Design and Proper Combustion

LA-0316CAMERON LNG FACILITY CAMERON LNG LLC Flares (3 units) 19.39 natural gas 0

ground flare EU20 = 91 MM BTU/hrlow pressure flare EU20A = 1077 mm btu/hr

Carbon Monoxide P

proper plant operations and maintaining the presence of the flame at the flare tips when vent gas is routed to the flares 0

BACT-PSD 0

LA-0331CALCASIEU PASS LNG PROJECT

VENTURE GLOBAL CALCASIEU PASS, LLC

Flares (WRMFLR, CLDFLR, LPFLR) 19.39 Natural Gas 21.74 MM BTU/h

Flare system to provide safe and reliable disposal of streams released during start-up, shutdown, plant upsets, and emergency conditions.

Carbon Monoxide P

Proper equipment design, proper operation, and good combustion practices. 0.31 LB/MM BTU

BACT-PSD

OPERATING PERMIT 0 When Flare is Operating.

NM-0052 ZIA II GAS PLANTDCP MIDSTREAM L.P.

Units FL1 &amp; FL2: Refinery Flares (Inlet Gas Flare &amp; Acid Gas Flare) 19.33

natural gas, acid gas 2.3 mmBtu/hr

Only for routine or predictable Startup, Shutdown, or Maintenance of units controlled by Flares (Blowdown/Venting, Amine Unit-Acid Gas Injection well maintenance)

Carbon Monoxide P

NOx, CO, PM10, PM2.5, SO2 controlled through Good Combustion Practices (GCP), pipeline quality natural gas for pilot; limits on flaring events. VOC & CO2e controlled through GCP, limits on flaring and meet 40 CFR 60.18. 3782.5 PPH

BACT-PSD

NSPS , SIP , OPERATING PERMIT 98

OH-0308

SUN COMPANY, INC., TOLEDO REFINERY SUNOCO, INC. FLARE, STEAM ASSISTED 50.008

PROCESS GASES 155.44 MMBTU/H

FLARE, STEAM ASSISTED, TO CONTROL HYDROCARBON EMISSIONS FROM PROCESS VENTS. SUBJECT TO PART 63, SUBPART CC AND PART 60, SUBPARTS A, J, AND GGG.

Carbon Monoxide N 12.8 LB/H

BACT-PSD NSPS , SIP 0

OH-0362LIMA REFINING COMPANY Acid Gas Flare (P050) 50.006 0

Sulfur Recovery Units Acid Gas Flare, non-assisted

Carbon Monoxide P Use of good combustion practices 0.84 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

0.84 ton/rolling, 12-month period from pilot and sweep gas firing only

OH-0368PALLAS NITROGEN LLC

PALLAS NITROGEN LLC

Back-End Process with flare (P003) 61.012 150 MMBTU/H

Back-End Process Flare (emissions from non-routine releases from the amine regeneration and MDEA storage system) - the pilot flare has a maximum heat input of 0.9 mmBtu/hr (operates 8,760 hours per year) and the flare has a maximum heat input of 150 mmBtu/hr.

Carbon Monoxide B

utilizing a flare with good combustion practices, natural gas to fuel pilots, and venting flare during only start-up, shutdown and malfunction events 46.57 LB/H

BACT-PSD 0 0.31 lb/mmBtu of heat input

OH-0368PALLAS NITROGEN LLC

PALLAS NITROGEN LLC

Ammonia Synthesis Process with flare (P004) 61.012 150 MMBTU/H

Ammonia Synthesis Process with flare - the pilot flare has a maximum heat input of 0.9 mmBtu/hr (operates 8,760 hours per year) and the flare has a maximum heat input of 150 mmBtu/hr.

Carbon Monoxide B

utilizing a flare with good combustion practices, natural gas to fuel pilots, and venting flare during only start-up, shutdown and malfunction events 46.57 LB/H

BACT-PSD 0 0.31 lb/mmBtu of heat input

OH-0376IRONUNITS LLC - TOLEDO HBI

IRONUNITS LLC - TOLEDO HBI

Pressure Relief Vent Flare (P008) 81.9 0 Pressure Relief Vent Flare

Carbon Monoxide P

Minimize flaring from startup, shutdown, and upset events by operating in accordance

with flare minimization plan.Meet the 40 CFR 60.18 requirements. 552.64 LB/H

BACT-PSD 0

OH-0378

PTTGCA PETROCHEMICAL COMPLEX

PTTGCA PETROCHEMICAL COMPLEX

High Pressure Ground Flare (P003) 19.31 Natural gas 1.8 MMBTU/H

1.8 MMBtu/hr high-pressure, multi-point, staged ground flare.

The high pressure (HP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the HP ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing

associated with control requirements. The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805.

Carbon Monoxide P use of natural gas as pilot light fuel 2.9171 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

The high pressure (HP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the HP ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing

associated with control requirements. The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805.

OH-0378

PTTGCA PETROCHEMICAL COMPLEX

PTTGCA PETROCHEMICAL COMPLEX

Low Pressure Ground Flare (P004) 19.31 Natural gas 0.78 MMBTU/H

0 8 tu/ o p essu e, u t po t, staged ground flare.

The low pressure (LP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the ECU ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing associated with control

requirements. The low pressure (LP) flare controls VOC emissions from units P804 and P805.

Carbon Monoxide P use of natural gas as pilot light fuel 1.26 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

The low pressure (LP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the ECU ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing associated with control

requirements. The low pressure (LP) flare controls VOC emissions from units P804 and P805.

OK-0142

WAYNOKA NATURAL GAS PROCESSING PLANT

ATLAS PIPELINE MIDCONTINENT WESTOK, LLC Flare, Amine Unit 19.39 Natural Gas 0 Amine Unit Flare

Carbon Monoxide N 0

BACT-PSD 0 Mfg recommended operation and maintenance.

10 of 14

Page 75: Permit 4682B Amendment - LyondellBasell...Equistar Chemicals, LP (Equistar) operates a petrochemical manufacturing facility located in Corpus Christi, Nueces County. The petrochemical

Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

OK-0142

WAYNOKA NATURAL GAS PROCESSING PLANT

ATLAS PIPELINE MIDCONTINENT WESTOK, LLC Flares, Plant 19.39 Natural Gas 0 Plant Flare.

Carbon Monoxide A Flare - Comply w/NSPS 60.18 0

BACT-PSD 0 Mfg recommendations.

*OR-0052

COLUMBIA RIDGE LANDFILL AND RECYCLING CENTER

WASTE MANAGEMENT DISPOSAL SERVICES OF OREGON, INC. Flares 19.32 landfill gas 1156 MMdscfCH4/yr

Two enclosed flares (FLR-1, FLR-2, both rated at 4,000 scfm, 132 MMBtu/hr) and smaller utility flare (FLR-3, rated at 1,350 scfm, 40.5 MMBtu/hr)

Carbon Monoxide N 0.2 LB/MMBTU

BACT-PSD 0

A search of BACT decisions nation wide indicate good combustion practices is the best available method for controlling CO emissions from flares with emission limits running from 0.017 to 0.4 lb CO/MMBtu. Tests on the existing enclosed flares have shown emissions ranging from 0.02 to 0.14 lb CO/MMBtu. Tuning the flare to reduce NOx emissions can result in an increase of CO emissions. Therefore the CO limit will be set a little higher to allow for greater reductions in NOx emissions. BACT will be established as the manufacturer’s guarantee of 0.2 lb CO/MMBtu for all flares.

SC-0183NUCOR STEEL - BERKELEY NUCOR STEEL

Vacuum Tank Degasser Equipment (vaccum tank degasser flares) 19.39 0

Vacuum degasser flares (flare 1/existing and flare 2/new) are used to control emissions from vacuum degasser tanks no.1 and no.2 (both existing).

Carbon Monoxide N 0

BACT-PSD 0

TX-0574VALERO THREE RIVERS REFINERY

DIAMOND SHAMROCK REFINING COMPANY L.P. FLARE MSS 50.008 0

EMISSIONS FROM MSS ACTIVITIES THAT ARE CONTROLLED BY THE PLANT FLARES.

Carbon Monoxide N BEST PRACTICES 0 SEE NOTES

BACT-PSD 0

USE BEST PRACTICES TO RECOVER FLUIDS TO PROCESS AS MUCH AS POSSIBLE BEFORE VENTING RESIDUALS TO FLARE.

TX-0684ENTERPRISE MONT BELVIEU COMPLEX

ENTERPRISE PRODUCTS OPERATING LLC Flare 19.39

Natural gas and process gas 0

Flare will be designed and operated to minimize VOC and CO emissions and will operate in accordance with NSPS Section. 60.18. Flare will be air assisted by a variable speed fan, will have waste stream composition identified by a highly reactive volatile organic compound (HRVOC) monitor, will only receive a waste stream that does not vary excessively in volumetric flow rate, and will primarily only receive easily combustible compounds containing three carbon compounds or less.

Carbon Monoxide P

proper flare design and operation in accordance with NSPS 60.18 41.21 LB/H

OTHER CASE-BY-CASE NSPS , NESHAP 0

TX-0697

ETHYLENE PRODUCTION PLANT

THE DOW CHEMICAL COMPANY Low Pressure Flare 19.31

NG and waste gas 10000 Btu/scf

The low pressure flare will be used to control the majority of all normal emissions from the ethylene and propylene process, including emission from the tanks noted in the permit and from the bleeds on dual seal compressors and some relief valves

Carbon Monoxide P Good combustion 0.3503 LB/MMBTU

OTHER CASE-BY-CASE NSPS 0

TX-0728

PEONY CHEMICAL MANUFACTURING FACILITY BASF ammonia flare 19.31

Natural gas, ammonia, hydrogen 106396 MMBtu/yr

g pA flare is used to combust unreacted hydrogen, destroy impure hydrogen/ammonia streams, and to control process shutdowns. The Flare is claimed to achieve 99% control for ammonia. Best Available Control Technology (BACT) for carbon monoxide (CO) from flares is good combustion practices. Sulfur Dioxide (SO2) emissions are controlled with the use of pipeline quality natural gas as fuel gas. The only volatile organic compound (VOC) emitted from the flare result from using natural gas as fuel gas. As the flare is not used for control of VOC, assist gas is not needed to control emissions of particulate

matter (PM).Emission rates provided are for worst case maintenance, start-up and shutdown (MSS) scenarios.

Carbon Monoxide P flare good combustion practices 950.41 LB/H

OTHER CASE-BY-CASE N/A 98

Emission rates provided are for worst-case MSS scenarios

TX-0795BEAUMONT CHEMICAL PLANT

EXXONMOBIL OIL CORPORATION PARAXYLENE FLARE 19.31 natural gas 5351 MM SCF / HR

The flare controls waste gas from the Paraxylene Unit. The operation of the flare is improving by the addition of instrumentation, controls, and increased supplemental natural gas.

Carbon Monoxide P

VOC emissions are controlled by the flare. Increasing clean supplemental fuel (natural gas) improves reliability and effectiveness of the primary function of this control device. The increase in natural gas yields the CO emissions increase. 50 T/YR

BACT-PSD NSPS 0 60.18

TX-0795BEAUMONT CHEMICAL PLANT

EXXONMOBIL OIL CORPORATION

East Low Pressure Flare and West High Pressure Flare 19.31 natural gas 8464 MM SCF / HR

These flares control waste gases from processes in the Olefins Unit. The operation of the flares is improving by the addition of instrumentation, controls, and increased supplemental natural gas. These two flares are joined by a common header.

Carbon Monoxide P

VOC emissions are controlled by the flares. Increasing clean supplemental fuel (natural gas) improves reliability and effectiveness of the primary function of these control devices. The increase in natural gas yields the CO emissions increase 188 T/YR

BACT-PSD NSPS 0 §60.18f

TX-0795BEAUMONT CHEMICAL PLANT

EXXONMOBIL OIL CORPORATION Udex Flare 19.31 natural gas 2914 MM SCF / HR

The flare controls waste gas from the Udex process unit and other process units within the plant. The operation of the flare is improving by the addition of instrumentation, controls, and increased supplemental natural gas.

Carbon Monoxide P

VOC emissions are controlled by the flare. Increasing clean supplemental fuel (natural gas) improves reliability and effectiveness of the primary function of this control device. The increase in natural gas yields the CO emissions increase. 40 T/YR

BACT-PSD NSPS 0 60.18

TX-0795BEAUMONT CHEMICAL PLANT

EXXONMOBIL OIL CORPORATION C&amp;S FLARE 19.31 natural gas 746 MM SCF / HR

The flare controls waste gas from the Catalyst and Synthetics Unit. The operation of the flare is improving by the addition of instrumentation, controls, and increased supplemental natural gas.

Carbon Monoxide P

VOC emissions are controlled by the flare. Increasing clean supplemental fuel (natural gas) improves reliability and effectiveness of the primary function of this control device. The increase in natural gas yields the CO emissions increase. 55 T/YR

BACT-PSD NSPS 0 60.18

TX-0796

BEAUMONT POLYETHYLENE PLANT

EXXONMOBIL OIL CORPORATION High Pressure Flare 19.31 natural gas 4988 MM SCF / HR

Improving the operation of the flare by the addition of instrumentation, controls, and increased supplemental natural gas.

Carbon Monoxide P

VOC emissions are controlled by the flare. Increasing clean supplemental fuel (natural gas) improves reliability and effectiveness of the primary function of this control device. The increase in natural gas yields the CO emissions increase. 155 T/YR

BACT-PSD NSPS 0 60.18

*TX-0872CONDENSATE SPLITTER FACILITY

MAGELLAN PROCESSING, L.P. Flare (Routine and MSS) 19.33

NATURAL GAS 12000 SCR.H

the control of wastewater and MSS activitiesâ €™ emissions. In cases where the fuel gas is unable to be used in the heater, the site is permitted to flare the fuel gas. Please see SC 34.

Carbon Monoxide P

Use of natural gas. Good combustion practices will be used to reduce CO including maintaining proper air-to-fuel ratio, necessary residence time, temperature and turbulence. 0.2755 LB/MMBTU HIGH BTU

BACT-PSD 0

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

AK-0083KENAI NITROGEN OPERATIONS AGRIUM U.S. INC. Three (3) Flares 19.31 Natural Gas 1.25 MMBTU/H

1.25 MMBtu/hr Ammonia Tank Flare, 0.4 MMBtu/hr Emergency Flare, and 1.25 MMBtu/hr Small Flare

Carbon Dioxide Equivalent (CO2e) P

Work Practice Requirements and Limited Use (limit venting to 168 hr/yr each during startup, shutdown, and maintenance events) 59.61

TONS/MMCF

BACT-PSD 0

CO-0067 LANCASTER PLANTKERR-MCGEE GATHERING Two Flares 19.39 0

The proposed Cryogenics Plant will have two flares (F-2 and F-3) that will control emissions from plant maintenance activities and purge gas from the two trains, generating combustion-related GHGs. Each flare also combusts pipeline quality natural gas, through its pilot, which has a firing rate of 0.5 MMBtu/hr, generating a small amount of combustion-related GHGs.

Carbon Dioxide Equivalent (CO2e) P 40 CFR 60.18 0

BACT-PSD

OPERATING PERMIT 0

The Division is determining for this site that good combustion practices and demonstrating initial and ongoing compliance in accordance with 40 CFR Part 60.18 is BACT for CO2 and CH4 control for flares.

IA-0106

CF INDUSTRIES NITROGEN, LLC - PORT NEAL NITROGEN COMPLEX

CF INDUSTRIES NITROGEN, LLC Flares 61.012 natural gas 0

Three (3) flares of different sizes. One is for syngas, one is for the ammonia process, and one is for ammonia tanks. All have the same BACT limits

Carbon Dioxide Equivalent (CO2e) P

good operating practices and use of natural gas 0

BACT-PSD 0

There are no emission limits on the flares. The BACT limits for the flares is a set of work practices which includes the units being fueled with natural gas, maintaining pressure during idling, and proper design.

LA-0296

LAKE CHARLES CHEMICAL COMPLEX LDPE UNIT

SASOL CHEMICALS (USA) LLC

LLPDE/LDPE Multi-Point Ground Flare (EQT 640) 19.31 0

The flare controls the following process vents: Purgas C-1 (LDPE-C-1, EQT 0641)

Compressor Area C-2 (LDPE-C-2, EQT 0642)Comonomer Degassing Column C-3 (LDPE-C-3,

EQT 0643)Isopentane Degassing Column C-4 (LDPE-C-4,

EQT 0644)Purification Bed Regeneration C-7 (LDPE-C-7,

EQT 0645) Analyzer Vents C-8 (LDPE-C-8, EQT 0646)

Vent Recovery Accumulator C-9 (LDPE-C-9, EQT 0647)

Carbon Dioxide Equivalent (CO2e) P

Compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS; minimization of flaring through adherence to the SSMP developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip; and the use of natural gas as pilot gas. 68285 TPY

ANNUAL MAXIMUM

BACT-PSD

OPERATING PERMIT 0

BACT is compliance with 40 CFR 63.11(b) and the applicable provisions of 40 CFR 63 Subpart SS, including, but not limited to, the closed vent system requirements of 40 CFR 63.983, the flare compliance assessment requirements of 40 CFR 63.987 and 40 CFR 63.2450(f), and the flame

monitoring requirements of 40 CFR 63.987. BACT is also determined to be minimization of flaring through adherence to the Lake Charles Chemical Complex’s startup, shutdown, and malfunction plan (SSMP) developed in accordance with 40 CFR 63.6(e)(3); continuously monitoring the volume of vent gas routed to the flare, the lower heating value or composition of the vent gas, the fuel gas flow rate, and for steam-assisted flares, the flow of steam to the flare tip;

and the use of natural gas as pilot gas. The CO2e limits are based on a CH4 global warming potential (GWP) of 21 and a N2O GWP of 310. In the event any GWP is revised, the CO2e limits shall be revised accordingly without the need to modify the permit.

*LA-0306TOPCHEM POLLOCK, LLC

TOPCHEM POLLOCK, LLC

Process Flare FL-16-1 (EQT034) 19.31 2.17 MM BTU/hr

Flare shall not operate more than 4 hours above normal firing rate in any 24 consecutive hours and 148 hours per year.

Carbon Dioxide Equivalent (CO2e) P

Compliance with the Louisiana Non-NSPS Flare Requirements 370 T/YR

ANNUAL MAXIMUM

BACT-PSD

OPERATING PERMIT 0 Correct Flare Design and Proper Combustion

LA-0316CAMERON LNG FACILITY CAMERON LNG LLC Flares (3 units) 19.39 natural gas 0

ground flare EU20 = 91 MM BTU/hrlow pressure flare EU20A = 1077 mm btu/hr

Carbon Dioxide Equivalent (CO2e) P

proper plant operations and maintaining the presence of the flame at the flare tips when vent gas is routed to the flares 0

BACT-PSD 0

LA-0331CALCASIEU PASS LNG PROJECT

VENTURE GLOBAL CALCASIEU PASS, LLC

Flares (WRMFLR, CLDFLR, LPFLR) 19.39 Natural Gas 21.74 MM BTU/h

Flare system to provide safe and reliable disposal of streams released during start-up, shutdown, plant upsets, and emergency conditions.

Carbon Dioxide Equivalent (CO2e) P

Proper equipment design, proper operation, and good combustion practices. 0

BACT-PSD

OPERATING PERMIT 0

NM-0052 ZIA II GAS PLANTDCP MIDSTREAM L.P.

Units FL1 &amp; FL2: Refinery Flares (Inlet Gas Flare &amp; Acid Gas Flare) 19.33

natural gas, acid gas 2.3 mmBtu/hr

Only for routine or predictable Startup, Shutdown, or Maintenance of units controlled by Flares (Blowdown/Venting, Amine Unit-Acid Gas Injection well maintenance)

Carbon Dioxide Equivalent (CO2e) P

NOx, CO, PM10, PM2.5, SO2 controlled through Good Combustion Practices (GCP), pipeline quality natural gas for pilot; limits on flaring events. VOC & CO2e controlled through GCP, limits on flaring and meet 40 CFR 60.18. 5626 PPH

BACT-PSD

NSPS , SIP , OPERATING PERMIT 98

The emission limits above represent CO2e from SSM for Units FL1 & FL2.

Additional limits for CO2e from pilot & purge are 1331.0 pph from unit FL1 and 1331.0 pph from Unit FL2.

OH-0362LIMA REFINING COMPANY Acid Gas Flare (P050) 50.006 0

Sulfur Recovery Units Acid Gas Flare, non-assisted

Carbon Dioxide Equivalent (CO2e) P

Use of low-carbon gaseous fuels (refinery fuel gas or natural gas) in the flareâ €™s pilot and sweep gases 266 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

266 tons per rolling, 12-month period from pilot and sweep gas firing only

OH-0368PALLAS NITROGEN LLC

PALLAS NITROGEN LLC

Back-End Process with flare (P003) 61.012 150 MMBTU/H

Back-End Process Flare (emissions from non-routine releases from the amine regeneration and MDEA storage system) - the pilot flare has a maximum heat input of 0.9 mmBtu/hr (operates 8,760 hours per year) and the flare has a maximum heat input of 150 mmBtu/hr.

Carbon Dioxide Equivalent (CO2e) P

good operational practices and energy efficient operation through a Minimization Plan and operation and maintenance in accordance with manufacturer recommendations. 714 T/YR

PER ROLLING 12 MONTH PERIOD

BACT-PSD 0

OH-0368PALLAS NITROGEN LLC

PALLAS NITROGEN LLC

Ammonia Synthesis Process with flare (P004) 61.012 150 MMBTU/H

Ammonia Synthesis Process with flare - the pilot flare has a maximum heat input of 0.9 mmBtu/hr (operates 8,760 hours per year) and the flare has a maximum heat input of 150 mmBtu/hr.

Carbon Dioxide Equivalent (CO2e) P

good operational practices and energy efficient operation through a Minimization Plan and operation and maintenance in accordance with manufacturer recommendations 714 T/YR

PER ROLLING 12 MONTH PERIOD

BACT-PSD 0

OH-0376IRONUNITS LLC - TOLEDO HBI

IRONUNITS LLC - TOLEDO HBI

Pressure Relief Vent Flare (P008) 81.9 0 Pressure Relief Vent Flare

Carbon Dioxide Equivalent (CO2e) P

Minimize flaring from startup, shutdown, and upset events by operating in accordance with flare minimization plan. 10386 T/YR

PER ROLLING 12 MONTH PERIOD

BACT-PSD 0

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

OH-0378

PTTGCA PETROCHEMICAL COMPLEX

PTTGCA PETROCHEMICAL COMPLEX

High Pressure Ground Flare (P003) 19.31 Natural gas 1.8 MMBTU/H

1.8 MMBtu/hr high-pressure, multi-point, staged ground flare.

The high pressure (HP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the HP ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing

associated with control requirements. The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805.

Carbon Dioxide Equivalent (CO2e) P use of natural gas as pilot light fuel 923 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

The high pressure (HP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the HP ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing

associated with control requirements. The high pressure (HP) flare controls VOC emissions from units P801, P802, P803, P804, and P805.

OH-0378

PTTGCA PETROCHEMICAL COMPLEX

PTTGCA PETROCHEMICAL COMPLEX

Low Pressure Ground Flare (P004) 19.31 Natural gas 0.78 MMBTU/H

0.78 MMBtu/hr low pressure, multi point, staged ground flare.

The low pressure (LP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the ECU ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing associated with control

requirements. The low pressure (LP) flare controls VOC emissions from units P804 and P805.

Carbon Dioxide Equivalent (CO2e) P use of natural gas as pilot light fuel 400 T/YR

PER ROLLING 12 MONTH PERIOD. SEE NOTES.

BACT-PSD 0

The low pressure (LP) ground flare is used to meet control requirements associated with BACT, NSPS, BAT, and MACT for affected facility operations and process vents. For efficient permitting structure, the ECU ground flare has been permitted as a separate and individual emissions unit to contain limitations, operational restrictions, monitoring, record keeping, reporting, and testing associated with control

requirements. The low pressure (LP) flare controls VOC emissions from units P804 and P805.

SC-0183NUCOR STEEL - BERKELEY NUCOR STEEL

Vacuum Tank Degasser Equipment (vaccum tank degasser flares) 19.39 0

Vacuum degasser flares (flare 1/existing and flare 2/new) are used to control emissions from vacuum degasser tanks no.1 and no.2 (both existing).

Carbon Dioxide Equivalent (CO2e) N 0

BACT-PSD 0

TX-0640

EQUISTAR CHEMICALS, LP LA PORTE COMPLEX

EQUISTAR CHEMICALS, LP Flares 99.19

Natural Gas and/or Process Gas 0

Acetylene Recovery Unit (ARU) Flare (QE3050B).

Elevated Flare (QE8050B).

Carbon Dioxide Equivalent (CO2e) N 39046 T/Y

12-MONTH ROLLING AVERAGE

BACT-PSD 0

Tonnage of CO2e is summation of CO2E emitted from ARU Flare (QE3050B) and from Elevated Flare (QE8050B)

TX-0649

ONEOK HYDROCARBON, MONT BELVIEU NGL FRACTIONATION PLANT

ONEOK HYDROCARBON, L.P. Flare (Frac-2 Contribution) 19.39 natural gas 0

Good combustion practices and flare gas recovery.

See permit condition III.C.1.FL-01

Carbon Dioxide Equivalent (CO2e) N 2278 T/Y

365-DAY ROLLING

BACT-PSD 0

Permittee shall calculate the CO2e emissions on a 12-month rolling basis, basedon the procedures and Global Warming Potentials (GWP) contained

inGreenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1, as published on October 30, 2009 (74 FR 56395).

TX-0744

C3 PETROCHEMICALS, PDH CHOCOLATE BAYOU PLANT

C3 PETROCHEMICALS LLC Ground Flare 19.39 Waste Gas 0

The non assisted ground flare will have 11 stages and shall be designed to achieve a min DRE of 98% VOC/CH4 during all times when waste gas is combusted. The only plant process gases that may flow continuously to the flare are: Pilot gas, sweep gas, process analyzer vents, process safety valve fugitives, and storage tank vents. The flare shall be operated with a flame present at all times and/or have a constant pilot flame. The pilot flame shall be continuously monitored by a thermocouple or an infrared monitor. the time, date and duration of any loss of pilot flame shall be recorded. The flare will be designed to meet 40 CFR 60.18

Carbon Dioxide Equivalent (CO2e) N 98

% DRE EFFICIENCY

12-MONTH ROLLING TOTAL

BACT-PSD 98

Permittee shall install a continuous flow monitor and composition analyzer that provides a record of the vent stream flow and composition to the flare. Readings shall be taken at least once every 15 minutes and the avg hourly values of the low and composition shall be recorded each hour.

TX-0744

C3 PETROCHEMICALS, PDH CHOCOLATE BAYOU PLANT

C3 PETROCHEMICALS LLC Ground Flare MSS 19.39 Waste Gas 0

Permittee shall depressurize sections of pipe and equipment to the flare or other parts of the process prior to performing MSS activities. MSS emissions that cannot be controlled by the flare are vented to the atmosphere. Venting to the atmosphere shall only occur when the hydrocarbon concentration in process vessels is below 10,000 ppmv, as determined by a LEL meter or Organic Vapor Analyzer. Records shall be maintained and includes a record of the hydrocarbon concentration as measured.

Carbon Dioxide Equivalent (CO2e) N 0

BACT-PSD 0 In addition to process notes, best practices.

TX-0747

LONE STAR NGL FRACTIONATORS, MONT BELVIEU GAS PLANT

LONE STAR NGL FRACTIONATORS Flare 19.39

Pipeline Nat Gas 200 scfh

Controls MSS emissions and emergency process releases. The flare’s pilots are fueled by pipeline quality natural gas. The pilot gas flow rate is 200 scfh. The flare will have a hydrocarbon destruction and removal efficiency (DRE) of 99%.

Carbon Dioxide Equivalent (CO2e) N 52 TPY CO2E

365-DAY TOTAL, ROLLED DAILY

BACT-PSD 0

Lone Star NGL will monitor the BTU content on the flared gas, and will have air assisted combustion allowing for improved flare gas combustion control and minimizing periods of poor combustion. Periodic maintenance will help maintain the efficiency of the flare.

TX-0766GOLDEN PASS LNG EXPORT TERMINAL

GOLDEN PASS PRODUCTS, LLC Flares 19.39 natural gas 0 One ground flare and one elevated flare at site

Carbon Dioxide Equivalent (CO2e) P

Equipment specifications & work practices- good combustion practices 0

BACT-PSD 99 Designed to meet 40 CFR 60.18

*TX-0872CONDENSATE SPLITTER FACILITY

MAGELLAN PROCESSING, L.P. Flare (Routine and MSS) 19.33

NATURAL GAS 12000 SCR.H

the control of wastewater and MSS activitiesâ €™ emissions. In cases where the fuel gas is unable to be used in the heater, the site is permitted to flare the fuel gas. Please see SC 34.

Carbon Dioxide Equivalent (CO2e) P

Use of natural gas. Good combustion practices will be used to reduce CO2e including maintaining proper air-to-fuel ratio, necessary residence time, temperature and turbulence. 0

BACT-PSD 0

AK-0082

POINT THOMSON PRODUCTION FACILITY

EXXON MOBIL CORPORATION Drilling, HP, and LP Flares 19.31 Gas 50 MMscf/yr

50 MMscf/yr Drilling Flare, 35 MMscf/yr HP Flare-Pilot/Purge, 20 MMscf/yr LP Flare-Pilot/Purge

Carbon Dioxide N 5317 TONS/YEAR COMBINED

BACT-PSD 0

IA-0106

CF INDUSTRIES NITROGEN, LLC - PORT NEAL NITROGEN COMPLEX

CF INDUSTRIES NITROGEN, LLC Flares 61.012 natural gas 0

Three (3) flares of different sizes. One is for syngas, one is for the ammonia process, and one is for ammonia tanks. All have the same BACT limits

Carbon Dioxide P proper operation and use of natural gas 0

BACT-PSD 0

There are no emission limits on the flares. The BACT limits for the flares is a set of work practices which includes the units being fueled with natural gas, maintaining pressure during idling, and proper design.

13 of 14

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Table C-1RBLC Search Results: Flare

RBLCID FACILITY NAMECORPORATE OR COMPANY NAME PROCESS NAME

PROCCESS TYPE

PRIMARY_FUEL THROUGHPUT

THROUGHPUT UNIT PROCESS NOTES POLLUTANT

CONTROL METHOD

CODE CONTROL METHOD DESCRIPTIONEMISSION

LIMIT 1

EMISSION LIMIT 1

UNIT

EMISSION LIMIT 1 AVG

TIME CONDITION

CASE-BY-CASE BASIS

OTHER APPLICABLE

REQUIREMENTSPERCENT

EFFICIENCY POLLUTANT COMPLIANCE NOTES

IN-0179OHIO VALLEY RESOURCES, LLC

OHIO VALLEY RESOURCES, LLC

FRONT END PROCESS FLARE 19.31

NATURAL GAS PILOT 0.25 MMBTU/H

HEAT INPUT IS FOR NATURAL GAS PILOT ONLY. SSM EMISSIONS ARE CONTROLLED BY THE FLARE AND ARE LIMITED TO 336 HOURS OF VENTING PER YEAR.

Carbon Dioxide P

NATURAL GAS PILOT, FLARE MINIMIZATION PRACTICES 116.89 LB/MMBTU

3-HR AVERAGE

BACT-PSD 0

SSM VENTING LIMITED TO 336 HOURS PER YEAR.

IN-0179OHIO VALLEY RESOURCES, LLC

OHIO VALLEY RESOURCES, LLC BACK END AMMONIA FLARE 19.31

NATURAL GAS 0.25 MMBTU/H

HEAT INPUT IS FOR PILOT ONLY. SSM EMISSIONS ARE CONTROLLED BY THE FLARE AND ARE LIMITED TO 336 HR/YR.

Carbon Dioxide P

NATURAL GAS PILOT, FLARE MINIMIZATION PRACTICES 116.89 LB/MMBTU

3-HR AVERAGE

BACT-PSD 0 SSM VENTING LIMITED TO 336 HR PER YEAR.

TX-0638MONT BELVIEU COMPLEX

ENTERPRISE PRODUCTS OPERATING LLC Flare 19.39 0 Flare, EPA: SK25.001

Carbon Dioxide N 62494 T/PY

12-MONTH ROLLING BASIS

BACT-PSD 0 Use Good Combustion Practices

*PA-0317SUNOCO MARCUS HOOK SUNOCO West Warm Flare 19.33 Natural Gas 42 MMBtu

Model EEF-HSA1-30 (or equivalent), three piolets each with two thermocouple elements an on

ionization detector.Base on the RBLC search and that the Flare itself is a control device compliance with design and operating requirements of 40 CFR § 60.18 satisfy LAER for the West Warm Flare, including maximum velocity, visible emissions, and minimum heating value.

14 of 14

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rpsgroup.com

FEDERAL AIR QUALITY ANALYSIS PROTOCOL EQUISTAR CHEMICALS, LP AMENDMENT TO NSR PERMIT NO. 4682B

Equistar Chemicals, LP

RN100221662

CN600124705

December 2019

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Federal Air Quality Analysis | December 2019

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Prepared by: Prepared for:

RPS Equistar Chemials, LP

Brooke Joseph

Senior Consultant

Howard S. Peters

Environmental Engineer

4801 Southwest Parkway, Parkway 2, Suite 150

Austin TX 78735

P.O. Box 10940

Corpus Christi, TX 78410

T +1 512 579 3317

E [email protected]

T +1 361 242 5028

E [email protected]

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Contents

1 INTRODUCTION ........................................................................................................................... 1

2 IDENTIFICATION INFORMATION ............................................................................................... 2

3 PROJECT OVERVIEW ................................................................................................................. 3

3.1 Type of Permit Review and Analysis ..................................................................................... 3

4 AREA MAP AND PLOT PLAN ..................................................................................................... 5

5 PSD PRE-APPLICATION ANALYSIS ......................................................................................... 8

5.1 CO .......................................................................................................................................... 8

6 MODELING EMISSIONS INVENTORY ........................................................................................ 9

6.1 Project Sources and Parameters ........................................................................................... 9

6.2 Off-Property Sources ............................................................................................................. 9

6.3 EPN/Modeling ID Correlation ...............................................................................................10

6.4 Scaling Factor ......................................................................................................................10

7 MODELS AND MODELING TECHNIQUES ...............................................................................11

7.1 Dispersion Model Selection .................................................................................................11

7.2 Dispersion Options ...............................................................................................................11

7.3 Terrain ..................................................................................................................................11

7.4 Building Wake Effects ..........................................................................................................11

7.5 Meteorological Data .............................................................................................................12

7.5.1 Surface Roughness .....................................................................................................12

7.6 Receptor Grid .......................................................................................................................13

8 PSD ANALYSIS ..........................................................................................................................16

8.1 CO PID .................................................................................................................................16

8.2 Additional Impact Analysis ...................................................................................................16

8.2.1 Class I Area Analysis ...................................................................................................16

8.2.2 Growth Analysis ...........................................................................................................17

8.2.3 Soils and Vegetation ....................................................................................................17

8.2.4 Class II Area Visibility ..................................................................................................17

9 REFERENCES ............................................................................................................................18

APPENDIX A – EMISSION RATES AND STACK PARAMETERS ...........................................................19

APPENDIX B – DOWNWASH INFORMATION ..........................................................................................21

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Tables

Table 3-1. PSD NAAQS Analysis Air Contaminants Reviewed .................................................................... 4

Table 6-1. Correlation of EPN to Model ID…………………………………………………………………….…10

Table 7-1. AERSURFACE Input Options…………………………………………………………………………12

Table A-1. Modeled Emission Rates – CO PSD Increases……………………………………………….…...20

Table A-2. Modeled Point Source Parameters – CO PSD Analysis.………………………………………….20

Table B-1. Building Downwash……………………………………………………………………………………22

Figures

Figure 4-1. Area Map ..................................................................................................................................... 6

Figure 4-2. Plot Plan ...................................................................................................................................... 7

Figure 7-1. Full Receptor Grid starting at the Fence Line ...........................................................................14

Figure 7-2. Receptors Near Facility starting at the Fence Line ...................................................................15

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1 INTRODUCTION This document presents the dispersion modeling protocol for a proposed Federal Air Quality Analysis (AQA) to be performed for the Equistar Chemicals Facility, located in Corpus Christi, Nueces County, Texas. Equistar Chemicals, LP (Equistar) is submitting an application concurrently to amend New Source Review (NSR) Permit No. 4682B/PSDTX761M3.

As the proposed increases of carbon monoxide (CO) trigger Prevention of Significant Deterioration (PSD) review, compliance with the National Ambient Air Quality Standards (NAAQS) is required and will be demonstrated with air dispersion modeling for CO, NO2, and long-term SO2. The Project does not trigger PSD review for any other regulated pollutants besides CO; therefore, any increase in allowable emissions of other regulated pollutants or toxics will be reviewed in accordance with Texas Commission on Environmental Quality (TCEQ)’s minor NSR NAAQS and Modeling and Effects Review Applicability (MERA) analysis.

All procedures, described herein, conform to the latest federal guidance from the U.S. Environmental Protection Agency (EPA) document, 40 CFR Part 51 Appendix W and State guidance as presented in the following TCEQ documents: Air Quality Modeling Guidelines (APDG 6232, TCEQ 2018). The EPA approved American Meteorological Society/Environmental Protection Agency Regulatory (AERMOD) air dispersion model, Version 19191, is proposed to be used for all analyses described in this document.

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2 IDENTIFICATION INFORMATION

Applicant: Equistar Chemicals, LP

Facility:

Permit:

Equistar Chemicals, Corpus Christi

4682B / PSDTX761M3

Regulated Entity Number: RN100221662

Nearest City and County: Corpus Christi, Nueces County

Applicant’s Modeler: Brooke Joseph, RPS Group

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3 PROJECT OVERVIEW Equistar owns and operates a petrochemical manufacturing facility in Corpus Christi, Nueces County, Texas. The petrochemical manufacturing facility consists of the Olefins and Aromatics Unit. There is also a cogeneration facility that supplies electricity and steam at the site authorized under Permit No. 18358. The Olefins and Aromatics Unit is commonly referred to as the Olefins Plant. The facility is authorized under Permit No. 4682B/PSDTX761M3, Title V Permit No. O1486, and various Standard Permit and Permit by Rule (PBR) authorizations. The maintenance, startup, and shutdown (MSS) activities associated with the Olefins Plant are authorized under Permit No. 83864. Greenhouse gas (GHG) emissions that were part of a 2015 expansion project are authorized under EPA-issued Permit No. PSD-TX-761-GHG (TCEQ GHG Permit No. GHGPSDTX32).

The amendment seeks to authorize flare emission increases needed to meet the net heating value in the combustion zone (NHVcz) targets. On September 5, 2019, EPA Administrator Andrew Wheeler signed a notice that addressed proposed changes to the 40 CFR 63 Subpart YY—National Emission Standards for Hazardous Air Pollutants for Source Categories: Generic Maximum Achievable Control Technology Standards for Ethylene Production. The EPA is proposing several rule changes as a result of its risk and technology review (RTR) for the Ethylene Production source category. The Agency is under a court-ordered deadline to finalize the RTR by March 13, 2020. The proposed new Ethylene Production MACT rules for flare performance are expected to mirror the flare rules found in the Refinery MACT subpart CC. The rules will require ethylene production units to maintain a minimum of 270 British thermal unit per standard cubic foot (BTU/scf) NHVcz to ensure proper combustion efficiency. Per information from the EPA, the rules will be the same as the flare rules found in 40 CFR 63.670, “Requirements for flare control devices”. Additionally, the flares in this permit amendment are part of an EPA flare enforcement initiative involving the site. EPA has requested that the flares meet NHVcz expeditiously. This project only seeks to authorize additional supplemental BTU content in the form of plant fuel gas that will need to be added to the flare vent gas to keep the heating value in the combustion zone above the EPA mandated 270 BTU/scf and does not add additional production capacity or modify the operating facility. This project does not impact MSS emissions currently authorized under Permit No. 83864; no additional MSS emissions are associated with this project.

As part of this project Equistar is also proposing to consolidate PBR and Standard Permit authorizations into Permit 4682B as required.

3.1 Type of Permit Review and Analysis

An application for a PSD permit must include an analysis of the ambient air quality in the vicinity of the proposed project for each compound for which the Project is subject to PSD review. As such, an air dispersion modeling analysis for CO is required.

The air contaminants reviewed in this Federal Air Quality Analysis and the applicable standards are

summarized in Table 3-1 below.

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Table 3-1. PSD NAAQS Analysis Air Contaminants Reviewed

Air Pollutant Averaging Time

Significant Impact Level

(µg/m3)

Significant Monitoring

Concentration Level

(µg/m3)

NAAQS Primary Standard (µg/m3)

CO

1-hr 2,000 -- 40,000

8-hr 500 575 10,000

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4 AREA MAP AND PLOT PLAN Figure 4-1 presents the area map showing the location of the Equistar plant and the surrounding area. The

plot plan is represented in Figure 4-2, which shows the location of all sources, as well as the locations of all

buildings and structures that could cause plume downwash. The area map and plot plans show two

boundaries for the plant. The "Property Line” is used for the Minor NAAQS evaluations, as well as the Health

Effects Review. The “Fenceline” represents the physical fence of the property, used for the CO PSD

analysis.

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636500 637000 637500 638000 638500 639000 639500 640000 640500 641000 641500

UTM Easting (meters)

30

735

00

30

740

00

3074

500

3075

000

3075

500

3076

000

3076

500

307

700

0307

750

0307

800

0307

850

0307

900

030

795

00

30

800

00

UT

M N

ort

hin

g (

mete

rs)

Figure 4-1Area Map

Source: Google EarthZone: 15Coordinate Datum: NAD 83

North

3,000 ft Radius

4801 Southwest Parkway, Parkway 2, Suite 150Austin TX 78735, USA

Property Line

Fence Line

Scale

(feet)0 1000 2000 3000 4000 5000

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5 PSD PRE-APPLICATION ANALYSIS According to 40 CFR 52.21(m), an application for a PSD permit must contain an analysis of ambient air

quality in the vicinity of the proposed source for each compound subject to PSD review. As stated previously,

the proposed project is subject to PSD review for CO.

A pre-application analysis is required for all pollutants triggering a PSD review. 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.

TCEQ Air Quality Modeling Guidelines (APDG 6232, TCEQ 2018) document provides a three-step procedure

for assessing the air quality near a project site:

Step 1:

Compare the highest model concentration obtained from the preliminary impact determination (PID) to the

applicable significant monitoring concentration (SMC). If the model concentration is equal to or greater than

the SMC, go to Step 2.

Step 2:

Assess local ambient air monitors to establish the existing air quality for the project area. If existing

monitoring data is not available or is deemed to not be representative, go to Step 3.

Step 3:

Establish a site-specific monitoring network

5.1 CO

Equistar proposes to employ Step 1 mentioned above and compare the highest model concentration

obtained from the PID for CO to the applicable significant monitoring concentration to determine if

preconstruction monitoring is required.

Based on the preliminary modeling analysis, it is anticipated that the highest model concentration from the

PID will be less than the applicable SMC of 575 µg/m3 for 8-hour CO. Therefore, preconstruction monitoring

will not be required. If it is determined later that preconstruction monitoring is triggered, Equistar will submit a

monitoring background concentration evaluation and/or monitoring plan for evaluation.

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6 MODELING EMISSIONS INVENTORY This section presents the modeling inventory used for this project.

6.1 Project Sources and Parameters

Appendix A contains a copy of the proposed project emission increases. Tables A-1 and A-2 contain the

emission rates and release parameters for sources evaluated for the CO PSD NAAQS analysis.

In general, the two flares are proposed to be modeled as point sources using the Good Engineering Practice

(GEP) release height of 212 feet, as well as the default flare exit velocity and temperature. The effective

diameters will be calculated based off their heat releases and average molecular weight with the following

formula:

𝐷 = √10−6𝑞𝑛 𝑞𝑛 = 𝑞(1 − 0.048√𝑀𝑊)

q = gross heat release in cal/s

qn = net heat release in cal/s

MW = weighted by volume average molecular weight of the composition being flared in g/mol

The CO PSD modeling analysis will not include any other point, area, or volume sources.

6.2 Off-Property Sources

Based on preliminary Federal NAAQS analysis, it is anticipated that a cumulative impacts analysis will not be

required. If it is determined later that a cumulative NAAQS analysis is required, Equistar will propose off-

property sources for inclusion in the cumulative NAAQS analysis.

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6.3 EPN/Modeling ID Correlation

Table 6-1 provides a cross reference between the EPN and the corresponding source IDs for the Equistar

plant to be used in the modeling analyses.

Table 6-1. Correlation of EPN to Model ID

EPN Model ID Description

10 10ROUT Cold Flare Routine

11 11_ROUT Hot Flare Routine

6.4 Scaling Factor

No scaling factors are proposed to be used in this analysis.

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7 MODELS AND MODELING TECHNIQUES This section outlines the dispersion models and modeling techniques that are proposed to be utilized in

performing the AQA.

7.1 Dispersion Model Selection

This analysis will be conducted with the EPA approved air dispersion model, AERMOD (Version 19191).

AERMOD is the EPA Preferred/Recommended regulatory model and is approved by the TCEQ modeling

staff. AERMOD is a steady-state plume dispersion model for assessment of pollutant concentrations from a

variety of sources, which determines concentrations from multiple point, area, and/or volume sources based

on an up-to-date characterization of the atmospheric boundary layer. The model calculates off-property,

ground-level concentrations for both short term (1-hour, 3 hour, 8-hour, and 24-hour) and annual averaging

periods and employs hourly sequential pre-processed (using AERMET) meteorological data to estimate

concentrations. The AERMOD model is applicable to receptors in all types of terrain, including flat terrain,

simple elevated terrain (below height of stack), intermediate terrain (between height of stack and plume

height), and complex terrain (above plume height). In addition, AERMOD provides a smooth transition of

algorithms across these different terrains. Therefore, AERMOD is proposed as the most appropriate model

for the air quality impact analysis for the Equistar plant. The Oris Solutions, LLC software program, “BEEST

for Windows”, will be used to set up the model inputs and to perform the model runs. All regulatory default

options are proposed to be chosen for this analysis.

7.2 Dispersion Options

Based on the Area Map, the project area is predominantly surrounded by rural land-use. Therefore, the urban

option in AERMOD will not be used.

7.3 Terrain

Mild variations in terrain occur in the area within 10 km of the site. The minimum receptor elevation modeled

is about 0 m and the maximum receptor elevation is around 30 m. Terrain elevations taken from the National

Elevation Dataset (NED) will be processed by AERMAP (version 18081) to develop receptor terrain heights

and critical heights. All receptor locations are referenced to UTM NAD83, Zone 14.

7.4 Building Wake Effects

Direction-specific building data will be generated for stacks below Good Engineering Practice (GEP) stack

height (EPA, 1985) using the EPA Building Profile Input Program PRIME (BPIPPRM Version 04274). Figure

4-2 in Section 4 provides a plot plan illustrating both emission points and building structures for the facility.

Building corners will be assigned UTM coordinates to identify building shapes and locations. This information,

along with emission point coordinates and heights, will be used by BPIPPRM to obtain downwash inputs to

AERMOD.

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7.5 Meteorological Data

The Equistar plant is located in Nueces County; therefore, based upon TCEQ guidance, representative

National Weather Service (NWS) meteorological stations will be as follows:

Surface data – Corpus Christi International Airport (NWS 12924);

• Anemometer Height: 10.06 m

• Profile Base Elevation: 13.4 m

• Corpus Christi International Airport is located approximately 7 km east of the Equistar plant.

Mixing Height data – Corpus Christi International Airport (NWS 12924)

For the PSD NAAQS analysis, five years (2011-2015) of concatenated pre-processed meteorological data

were used, which were obtained from the TCEQ’s website.1

7.5.1 Surface Roughness

An AERSURFACE analysis will be performed to determine the surface roughness for the Equistar plant based upon a 1-kilometer radius surrounding the site.

As shown in Table 7-1, the surface roughness length around the site calculated by AERSURFACE is 0.263 meters (m). Since this value is between 0.1 m and 0.7 m, the meteorological data set with medium surface roughness category will be used for modeling analysis.

Table 7-1. AERSURFACE Input Options

Input/Output Equistar Facility

Number of Wind Sectors One

Surface Characteristic Frequency Annual

Winter Season Snow Cover? No

Located at Airport? No

Arid Conditions? No

Moisture Level Average

Calculated Surface Albedo 0.18

Calculated Bowen Ratio 0.62

Calculated Surface Roughness 0.263

1 https://www.tceq.texas.gov/permitting/air/modeling/aermod-datasets.html

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7.6 Receptor Grid

For Federal NAAQS analyses, modeled predictions are required to determine if a source will cause or

contribute to a violation of an ambient air standard. A source is not required to model the impacts of its

emissions at locations that are not considered to be ambient air. For this analysis, the following will be used

to create the receptor grid:

- 25-meter spacing extending from the fence line out to 300 meters;

- 100-meter spacing within 1 km of fence line for any locations not covered by the 25-meter grid;

- 500-meter spacing within 1 to 5 km of fence line; and

- 1,000-meter spacing within 5 to 10 km of fence line.

Figure 7-1 shows an overall view of the receptor grid, and Figure 7-2 shows the receptors near the facility

fence line.

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Figure 7-1. Full Receptor Grid starting at the Fence Line

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Figure 7-2. Receptors Near Facility starting at the Fence Line

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8 PSD ANALYSIS A PSD NAAQS analysis is anticipated to be requested for CO. The TCEQ modeling guideline outlines the

procedures for a PSD NAAQS analysis.

8.1 CO PID

Equistar is proposing a PID otherwise called a “significance analysis” for PSD – triggered CO (1-hour and 8-

hour). The PID represents an initial screen to determine the following: (1) if a refined PSD analysis (NAAQS

and PSD Increment) is required for the proposed project; and (2) the appropriate location, or Area of Impact

(AOI), for a refined analysis.

For the CO PID analysis, all increases were modeled for comparison to the SILs. If the highest first high

(H1H) model concentrations are less than the applicable SILs, no further modeling is required. Based on a

preliminary modeling analysis, it is anticipated that model concentrations considering CO emission changes

will be less than the SILs. If it is determined that the model concentrations are greater than the SILs, Equistar

will conduct a cumulative NAAQS and PSD increment analysis.

8.2 Additional Impact Analysis

An additional impacts analysis is required under the PSD requirements at 40 CFR §52.21(o) to evaluate the

effects of economic growth and the effect on soils, vegetation, and visibility from regulated compounds

emitted in significant quantities from a new or modified major stationary source.

8.2.1 Class I Area Analysis

Any new major source or major modification located within 100 kilometer (km) of a Class I area is required to

perform an impacts analysis for the affected Class I areas; however, an analysis may also be required for

sources located more than 100 km from a Class I area if there is concern that the project emissions could

cause an adverse impact on a Class I area (see TCEQ APDG 6232, Revised 09/18 Air Quality Modeling

Guidelines, Page 26). The nearest Class I areas and their distance from the facilities are:

• Big Bend National Park at 570 km;

• Caney Creek Wilderness Area at 800 km; and

• Carlsbad Caverns at 825 km;

The closest Class I Area is 570 km from the facility, which is significantly greater than the 100 km threshold.

The emissions from the proposed project are not expected to cause any adverse impacts on this Class I

area; therefore, Class I area PSD increment, visibility or Air Quality Related Value (AQRV) analyses are not

proposed to be included in the modeling analysis.

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8.2.2 Growth Analysis

The proposed project will begin upon issuance of authorization by TCEQ. The project is not expected to

create significant additional permanent jobs in the area. The project is not expected to cause a shift in the

population and activity in the area; therefore, the associated air emissions are not expected to have

significant impacts.

8.2.3 Soils and Vegetation

The PSD regulations require an evaluation of the impact of project emissions on soils and vegetation. The

analysis is required only for those pollutants for which PSD review is triggered. According to EPA’s A

Screening Procedure for the Impacts of Air Pollution on Plants, Soils and Animals, the relevant pollutants for

soils and vegetation are NO2, SO2 and CO. The project triggers PSD review for CO but does not have a

significant net emission increase of NO2 or SO2.

EPA has developed NAAQS Secondary standards to provide public welfare protection, including protection

against decreased visibility and damage to animals, crops, vegetation, and buildings. The model

concentrations considering emissions from the proposed sources are expected to be less than the primary

NAAQS, which are more conservative than the secondary NAAQS. TCEQ has determined that the ambient

concentrations of criteria pollutants below secondary NAAQS will not result in harmful effects; therefore,

further analysis of soil and vegetation impacts should not be required.

8.2.4 Class II Area Visibility

The PSD regulations require an evaluation of the impact of project emissions on visibility in Class II areas.

The relevant pollutants for visibility are PM, NOX and SO2. Since the proposed project is not subject to PSD

review for any of the visibility impairing pollutants, a Class II visibility analysis should not be required for this

project.

Equistar will comply with all the requirements of 30 TAC Chapter 111 to Class II Area visibility requirements

as applicable.

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9 REFERENCES

NC NRCD, 1985 “Screening Threshold” Method for PSD Modeling. July 1985. State of North Carolina Department of Natural Resources and Community Development, North Carolina Air Quality Section, 512 North Salisbury Street, Raleigh, North Carolina 27611

EPA, 1985 Guideline for Determination of Good Engineering Stack Height (Technical Support

Document for the Stack Height Regulation) (Revised), EPA-450/4-80-023R, June 1985,

Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency,

Research Triangle Park, NC 27711.

EPA, 2004 User’s Guide for the AMS/EPA Regulatory Model – AERMOD. U.S. Environmental

Protection Agency, Research Triangle Park, NC.

EPA, 2013 Draft Guidance for PM2.5 Permit Modeling, March 4, 2013, EPA-454-/B-11-001, U.S.

Environmental Protection Agency, Research Triangle Park, North Carolina 27711.

TCEQ, 2018 Modeling and Effects Review Applicability: How to Determine the Scope of Modeling and

Effects Review for Air Permits, APDG 5874v5, March 2018. Texas Commission on

Environmental Quality, Air Permits Division, P.O. Box 13087, Austin, Texas 78711-3087

TCEQ, 2015 Air Quality Modeling Guidelines, APDG 6232v2. September 2018. Texas Commission on Environmental Quality, P.O. Box 13087, Austin, Texas 78711-30

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APPENDIX A – EMISSION RATES AND STACK PARAMETERS

The following tables are provided in this appendix:

Table A-1. Modeled Emission Rates – CO PSD Increases

Table A-2. Modeled Point Source Parameters – CO PSD Analysis

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Table A-1. Modeled Emission Rates – CO PSD Increases

EPN Source ID

Federal NAAQS CO Preliminary Impact Determination

1-hour (g/s)

8-hour (g/s)

10 10ROUT 6.17E-01 6.17E-01

11 11_ROUT 8.78E-01 8.78E-01

Table A-2. Modeled Point Source Parameters – CO PSD Analysis

Model ID

Stack Release

Type

UTM Coordinates Base Elevation

(m)

Stack Height

(m)

Temperature (K)

Velocity (m/s)

Diameter (m)2 Easting

(m) Northing

(m)

10ROUT DEFAULT 638,539 3,076,730 19.31 64.61 1273 20 2.03

11_ROUT DEFAULT 638547.5 3,076,727 19.31 64.61 1273 20 2.03

2 Effective Diameter is calculated with the formula in Section 6.1 with the following:

EPN 10: Heat Release – 75.11 MMBtu/hr, Molecular Weight – 20.10 g/mol

EPN 11: Heat Release – 74.79 MMBtu/hr, Molecular Weight – 20.10 g/mol

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APPENDIX B – DOWNWASH INFORMATION

The following is provided in support of Section 7.4 of this analysis:

Table B-1. Building Downwash Structures

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Table B-1. Building Downwash Structures

Building Name Tier Height

(m)

STARTUP 3.6576

LUNCH 3.6576

MECH_SP 3.6576

WEILDING 3.6576

WARE_HS 9.144

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Special Conditions Permit Numbers 4682B, PSDTX761M4, and GHGPSDTX32M1

1. This permit covers only those sources of emissions listed in the attached table entitled “Emission Sources - Maximum Allowable Emission Rates” (MAERT), and those sources are limited to the emission limits and other conditions specified in that table. (TBD)

2. Non-fugitive emissions from relief valves, safety valves, or rupture discs of gases containing volatile organic compounds (VOC) at a concentration of greater than 1 percent are not authorized by this permit unless authorized on the MAERT. Any releases directly to atmosphere from relief valves, safety valves, or rupture discs of gases containing VOC at a concentration greater than 1 weight percent are not consistent with good practice for minimizing emissions. (TBD)

Federal Applicability

3. These facilities shall comply with all applicable requirements of the U.S. Environmental Protection Agency (EPA) regulations on Standards of Performance for New Stationary Sources promulgated in Title 40 Code of Federal Regulations Part 60 (40 CFR Part 60):

A. Subpart A, General Provisions.

B. Subpart D, Fossil-Fuel-Fired Steam Generators.

C. Subpart K, Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978.

D. Subpart Kb, Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced after July 23, 1984.

E. Subpart VV, Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry for which Construction, Reconstruction, or Modification Commenced After January 5, 1981, and on or Before November 7, 2006.

4. These facilities shall comply with all applicable requirements of the EPA regulations on National Emission Standards for Hazardous Air Pollutants in 40 CFR Part 61:

A. Subpart A, General Provisions.

B. Subpart J, Equipment Leaks (Fugitive Emission Sources) of Benzene.

C. Subpart V, Equipment Leaks (Fugitive Emission Sources).

D. Subpart FF, Benzene Waste Operations.

5. These facilities shall comply with all applicable requirements of the EPA regulations on National Emission Standards for Hazardous Air Pollutants for Source Categories in 40 CFR Part 63:

A. Subpart A, General Provisions.

B. Subpart F, Organic Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing Industry.

C. Subpart G, Organic Hazardous Air Pollutants from the Synthetic Organic Chemical Manufacturing Industry Process Vents, Storage Vessels, Transfer Operations, and Wastewater.

D. Subpart H, Organic Hazardous Air Pollutants for Equipment Leaks.

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E. Subpart SS, Closed Vent Systems, Control Devices, Recovery Devices and Routing to a Fuel Gas System or a Process.

F. Subpart UU, Equipment Leaks - Control Level 2 Standards.

G. Subpart WW, Storage Vessels (Tanks) - Control Level 2.

H. Subpart, XX, Ethylene Manufacturing Process Units: Heat Exchange Systems and Waste Operations.

I. Subpart YY, Hazardous Air Pollutants for Source Categories: Generic Maximum Achievable Control Technology Standards.

J. Subpart ZZZZ, Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines.

K. Subpart DDDDD, Hazardous Air Pollutants for Industrial for Institutional, Commercial, and Industrial Boilers and Process Heaters.

Operation Limits

6. Records of production of all products and by-products shall be maintained at the plant site and made readily available to TCEQ personnel upon request. (TBD)

7. Eight pilot-operated safety relief valve systems in gaseous service on the prefractionation tower, rectifier tower, demethanizer tower, deethanizer tower, ethylene tower, methane recycle system and two on the fuel gas system are not required to be equipped with rupture discs and disc monitoring systems. These valves in gaseous service are subject to instrument leak monitoring after any gaseous release to verify proper reseating of the valve in gaseous service under the requirements of Special Condition No. 22. (04/14)

8. Vacuum vent gases from Process Towers E1802 and E1803 shall be routed to HDA Feed Heater (B-1851) or to the Hot Flare designated as EPN 10. The heater shall operate at no less than 99.5 percent destruction removal efficiency (DRE) in disposing of the vent gas streams. The heater DRE shall be demonstrated by either vendor data or stack testing. Stack testing results shall be forwarded to the TCEQ Corpus Christi Regional Office within 60 days after testing has been completed.

9. Exported biphenyls shall be loaded via a pressurized loading system to pressurized trucks rated at 25 psig or higher.

10. Storage and Loading of VOC

A. These conditions shall not apply (1) where the VOC has an aggregate partial pressure of less than 0.5 psia at the maximum expected operating temperature or (2) to storage tanks smaller than 25,000 gallons.

B. An internal floating roof or equivalent control shall be installed on all tanks.

C. An open top tank containing a floating roof which uses double seal or secondary seal technology shall be an approved control alternative to an internal floating roof tank provided the primary seal consists of either a mechanical shoe seal or a liquid-mounted seal and the secondary seal is rim-mounted. A weathershield is not approvable as a secondary seal unless specifically reviewed and determined to be vapor-tight.

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D. For any tank equipped with a floating roof, the integrity of the floating roof seals shall be verified annually and records maintained to describe dates, seal integrity, and corrective actions taken.

E. The floating roof design shall incorporate sufficient flotation to conform to the requirements of API Code 650, Appendix C or an equivalent degree of flotation, except that an internal floating cover need not be designed to meet rainfall support requirements.

F. Uninsulated tank exterior surfaces exposed to the sun shall be white.

G. For purposes of assuring compliance with VOC emission limitations, the holder of this permit shall maintain an annual emissions record which describes calculated emissions of VOC from all storage tanks and loading operations. The record shall include tank or loading point identification number, control method used, tank or vessel capacity in gallons, name of the material stored or loaded, VOC molecular weight, VOC average temperature in degrees Fahrenheit (°F), VOC vapor pressure at the average material temperature in psia, VOC throughput and total tons of emissions. This record shall be maintained at the plant site and be made available to representatives of the TCEQ upon request.

H. Emissions for tanks and loading operations shall be calculated using the edition of AP-42, “Compilation of Air Pollutant Emission Factors,” in effect on the date this permit was issued (or the edition in effect on the last date the permit was amended if the permit has been amended).

11. The cooling tower water shall be monitored monthly for VOC leakage from heat exchangers in accordance with the requirements of the TCEQ Sampling Procedures Manual, Appendix P (dated January 2003 or a later edition) or another air stripping method approved by the TCEQ Executive Director. Appendix P equipment shall be installed and operating 180 days from the month year of permit amendment approval.

Cooling water VOC concentrations above 0.08 ppmw indicate faulty equipment. Equipment shall be maintained so as to minimize VOC emissions into the cooling water. Faulty equipment shall be repaired at the earliest opportunity but no later than the next scheduled shutdown of the process unit in which the leak occurs.

Emissions from the cooling tower are not authorized if the VOC concentration of the water returning to the cooling tower exceeds 0.80 ppmw. The VOC concentrations above 0.80 ppmw are not subject to extensions for delay of repair under this permit condition. The results of the monitoring and maintenance efforts shall be recorded.

Cooling water shall be sampled once a week for total dissolved solids (TDS). Dissolved solids in the cooling water drift are considered to be emitted as PM10. The data shall result from collection of water samples from the cooling tower feed water and represent the water being cooled in the tower. Water samples should be capped upon collection, and transferred to a laboratory area for analysis. The analysis method for TDS shall be EPA Method 160.1, ASTM D5907, and SM 2540 C [SM - 19th edition of Standard Methods for Examination of Water]. Use of an alternative method shall be approved by the TCEQ Regional Director prior to its implementation. (04/14)

Emission Standards and Fuel Limits

12. Fuel oil used in the steam boiler designated as Emission Point Number (EPN) 4A shall contain no more than 0.90 percent sulfur by weight. When this steam boiler burns fuel oil then the holder of

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this permit shall demonstrate compliance with this special condition by performing a once a calendar quarter analysis of the fuel oil to determine its sulfur content. Hydrogen fuel is also authorized for fuel only in the steam boiler designated as EPN 4A.

13. Nitrogen oxides (NOx) emissions from pyrolysis USC furnaces A through N and VMR furnaces A and B shall not exceed 0.06 pound per million Btu (lb/MMBtu) of heat input, averaged daily, except during decoking operations, hot standby periods and periods where there is no hydrocarbon feed. The CO emissions from these sources shall not exceed 0.036 lb/MMBtu of heat input, averaged daily except during decoking operations, hot standby periods and periods where there is no hydrocarbon feed. In all cases the maximum allowable emission rates as shown on the MAERT shall not be exceeded. (TBD)

14. Fuels allowed for use in the USC and VMR furnaces are natural gas, in-plant produced fuel or other gaseous fuels with characteristics similar to natural or plant fuel gas. (04/14)

15. Records of decoking operations shall be maintained at the plant site and made available to Texas Commission on Environmental Quality (TCEQ) personnel upon request to demonstrate compliance with MAERT limits applicable to the decoke cyclones (EPN 9A and 9B) (04/14)

Visible Emission Limits

16. The opacity of emissions from the boiler stack designated as EPN 4A shall be continuously monitored and recorded whenever this steam boiler burns fuel oil. Loss of valid data due to periods of monitor break down, out-of-control operation (producing inaccurate data), repair, maintenance or calibration may be exempted provided it does not exceed 5 percent of the time (in minutes) that this steam boiler operated using fuel other than plant fuel gas or natural gas over the previous rolling 12-month period. Records of the amount of downtime and cause for the missed measurements shall be kept on site.

17. Opacity of emissions from pyrolysis USC furnaces A through N and VMR furnaces A and B shall not exceed 15 percent averaged over a six-minute period as determined by the U.S. Environmental Protection Agency (EPA) Reference Method 9. Stack testing may be required if this opacity limit is exceeded from any subject furnace. (04/14)

18. Opacity of emissions from each decoking cyclone designated as EPN 9A and 9B shall not exceed 15 percent averaged over a six-minute period as determined by EPA Reference Method 9 once a week. Once a week opacity measurements shall be completed from one or both EPNs when an ethylene furnace is undergoing decoking. Each opacity measurement result shall be recorded at the plant site. These opacity results shall be reported to the nearest appropriate TCEQ regional office and EPA Region VI office on an annual basis. If this opacity limit from each EPN is exceeded, the TCEQ and/or EPA may require stack sampling from the decoking cyclone(s) EPN(s) per Special Condition No. 28 within 60 days, but not later than 120 days of this opacity exceedance. The possible use of established sampling procedures shall be discussed and approved at a pretest meeting as specified by Special Condition No. 28.

Flares

19. Each flare designated as EPN 10 and EPN 11 shall be designed and operated in accordance with the following requirements:

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A. The combined assist natural gas and waste stream to each flare shall meet the 40 CFR 60.18 specifications of minimum heating value and maximum tip velocity under normal, upset and maintenance flow conditions. Compliance with this condition shall be demonstrated by monitoring required in section D below. Flare testing per 40 CFR 60.18(f) may be requested by the TCEQ Corpus Christi Regional Office to demonstrate compliance with this condition.

B. The flare shall be operated with a flame present at all times and/or have a constant pilot flame. The pilot flame shall be continuously monitored by a thermocouple or an infrared monitor. The time, date, and duration of any loss of pilot flame shall be recorded. Each monitoring device shall be accurate to, and shall be calibrated at a frequency in accordance with, the manufacturer’s specifications

C. Each flare shall be operated with no visible emissions except periods not to exceed a total of five minutes during any two consecutive hours. This shall be ensured by the use of steam-assist to each flare.

D. The permit holder shall install, maintain and operate a continuous flow monitor and composition analyzer that provide a record of the vent stream flow and composition as total Btu content sent to each flare. Each flow monitor sensor and analyzer sample point(s) shall be installed in the vent stream as near as possible to each flare inlet such that the total vent stream directed to each flare is measured and analyzed. Readings shall be taken at least once every 15 minutes and the average hourly values of the flow and composition shall be recorded each hour for each flare.

Each monitor shall be calibrated on an annual basis to meet the following accuracy specifications: the flow monitor shall be ±5.0%, temperature monitor shall be ±2.0% at absolute temperature, and pressure monitor shall be ±5.0 mm Hg;

The holder of this permit will maintain a flare monitoring plan that will be subject to the following:

(1) Flare gas Btu content shall be monitored using an on-line gas chromatograph. Data from the chromatograph shall be accessible and shall be monitored at the unit control room.

(2) Flare gas exit velocity shall be monitored using an on-line flow meter. The exit velocity shall be accessible and shall be monitored at the unit control room.

(3) Single point calibration of the chromatograph shall be performed at least once per calendar month. In addition, single point calibration of the chromatograph shall be performed after significant maintenance, before returning the chromatograph to duty.

(4) A physical check and inspection of the chromatograph system and of the on-line flow meter system shall be performed at least once per calendar month.

The monitors and analyzers shall operate as required by this section at least ninety-five percent of the time when the flare is operational, averaged over a rolling 12 month period. Flared gas net heating value and actual exit velocity determined in accordance with 40 CFR §60.18(f)(4) shall be recorded at least once every 15 minutes. Hourly mass emission rates shall be determined and recorded using the above readings and the emission factors used in the permit amendment application, Form PI-1 dated April 2010.

E. The flare Hot Flare (EPN 10) and the Cold Flare (EPN 11) shall operate in accordance with the proposed 40 CFR 63 Subpart YY rules “National Emission Standards for Hazardous Air Pollutants: Generic Maximum Achievable Control Technology Standards Residual Risk and

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Technology Review for Ethylene Production” (84 Fed. Reg. 54278, Oct. 9, 2019), and the subsequently promulgated final version of that subpart, as of December 31, 2020 or the effective date of the amended subpart, whichever is earlier. Prior to the compliance requirements and schedule of this paragraph, Special Condition Nos. 19.A through 19.D shall apply. (TBD)

F. Supplemental fuel gas combusted in the flare shall be either, or a combination of, sweet natural gas, plant produced fuel gas and/or hydrogen. Each flare vent gas stream (supplement fuel gas and waste gas) shall be sampled at least weekly to determine sulfur content. The sulfur content shall be multiplied by the hourly flare flow rates to verify compliance with MAERT SO2 limits. (TBD)

Compliance Assurance Monitoring

20. The following requirements apply to capture systems for the hot flare designated as EPN 11 and the cold flare designated as EPN 10.

A. If used to control pollutants designated as VOC, either:

(1) Conduct a once a month visual, audible, and/or olfactory inspection of the capture system to verify there are no leaking components in the capture system; or

(2) Once a year, verify the capture system is leak-free by inspecting in accordance with 40 CFR Part 60, Appendix A, Test Method 21. Leaks shall be indicated by an instrument reading greater than or equal to 500 ppmv above background.

B. The control device shall not have a bypass.

or

If there is a bypass for the control device, comply with either of the following requirements:

(1) Install a flow indicator that records and verifies zero flow at least once every fifteen minutes immediately downstream of each valve that if opened would allow a vent stream to bypass the control device and be emitted, either directly or indirectly, to the atmosphere; or

(2) Once a month, inspect the valves, verifying the position of the valves and the condition of the car seals prevent flow out the bypass.

A deviation shall be reported if the monitoring or inspections indicate bypass of the control device.

C. Records of the inspections required shall be maintained and if the results of any of the above inspections are not satisfactory, the permit holder shall promptly take necessary corrective action.

Process Fugitive Monitoring

Piping, Valves, Flanges, Pumps, and Compressors in VOC Service - Applies to Components for EPN FU-4 NESHAP FF - 28M

21. Except as may be provided for in the Special Conditions of this permit, the following requirements apply to the above-referenced equipment:

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A. The requirements of paragraphs F and G shall not apply (1) where the VOC has an aggregate partial pressure or vapor pressure of less than 0.5 pounds per square inch, absolute (psia) at 100oF or at maximum process operating temperature if less than 100oF or (2)) where the operating pressure is at least 5 kilopascals (0.725 psi) below ambient pressure. Equipment excluded from this condition shall be identified in a list or by one of the methods described below to be made readily available upon request.

The exempted components may be identified by one or more of the following methods:

(1) piping and instrumentation diagram (PID);

(2) a written or electronic database or electronic file;

(3) color coding;

(4) a form of weatherproof identification; or

(5) designation of exempted process unit boundaries.

B. Construction of new and reworked piping, valves, pump systems, and compressor systems shall conform to applicable American National Standards Institute (ANSI), American Petroleum Institute (API), American Society of Mechanical Engineers (ASME), or equivalent codes.

C. New and reworked underground process pipelines shall contain no buried valves such that fugitive emission monitoring is rendered impractical. New and reworked buried connectors shall be welded.

D. To the extent that good engineering practice will permit, new and reworked valves and piping connections shall be so located to be reasonably accessible for leak-checking during plant operation. Difficult-to-monitor and unsafe-to-monitor valves, as defined by Title 30 Texas Administrative Code Chapter 115 (30 TAC Chapter 115), shall be identified in a list to be made readily available upon request. The difficult-to-monitor and unsafe-to-monitor valves may be identified by one or more of the methods described in subparagraph A above. If an unsafe-to-monitor component is not considered safe to monitor within a calendar year, then it shall be monitored as soon as possible during safe-to-monitor times. A difficult-to-monitor component for which quarterly monitoring is specified may instead be monitored annually.

E. New and reworked piping connections shall be welded or flanged. Screwed connections are permissible only on piping smaller than two-inch diameter. Gas or hydraulic testing of the new and reworked piping connections at no less than operating pressure shall be performed prior to returning the components to service or they shall be monitored for leaks using an approved gas analyzer within 15 days of the components being returned to service. Adjustments shall be made as necessary to obtain leak-free performance. Connectors shall be inspected by visual, audible, and/or olfactory means at least weekly by operating personnel walk-through.

Each open-ended valve or line shall be equipped with an appropriately sized cap, blind flange, plug, or a second valve to seal the line. Except during sampling, both valves shall be closed. If the removal of a component for repair or replacement results in an open ended line or valve, it is exempt from the requirement to install a cap, blind flange, plug, or second valve for 72 hours. If the repair or replacement is not completed within 72 hours, the permit holder must complete either of the following actions within that time period:

(1) a cap, blind flange, plug, or second valve must be installed on the line

valve; or

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(2) the open-ended valve or line shall be monitored once for leaks above background for a plant or unit turnaround lasting up to 45 days with an approved gas analyzer and the results recorded. For all other situations, the open-ended valve or line shall be monitored once at the end of the 72-hour period following the creation of the open ended line and monthly thereafter with an approved gas analyzer and the results recorded. For turnarounds and all other situations, leaks are indicated by readings 500 ppmv above background and must be repaired within 24 hours or a cap, blind flange, plug, or second valve must be installed on the line or valve.

F. Accessible valves shall be monitored by leak-checking for fugitive emissions at least quarterly using an approved gas analyzer. Sealless/leakless valves (including, but not limited to, welded bonnet bellows and diaphragm valves) and relief valves equipped with a rupture disc upstream or venting to a control device are not required to be monitored. For valves equipped with rupture discs, a pressure-sensing device shall be installed between the relief valve and rupture disc to monitor disc integrity. All leaking discs shall be replaced at the earliest opportunity but no later than the next process shutdown.

A check of the reading of the pressure-sensing device to verify disc integrity shall be performed at least quarterly and recorded in the unit log or equivalent. Pressure-sensing devices that are continuously monitored with alarms are exempt from recordkeeping requirements specified in this paragraph.

The gas analyzer shall conform to requirements listed in Method 21 of 40 CFR part 60, appendix A. The gas analyzer shall be calibrated with methane. In addition, the response factor of the instrument for a specific VOC of interest shall be determined and meet the requirements of Section 8 of Method 21. If a mixture of VOCs are being monitored, the response factor shall be calculated for the average composition of the process fluid. A calculated average is not required when all of the compounds in the mixture have a response factor less than 10 using methane. If a response factor less than 10 cannot be achieved using methane, then the instrument may be calibrated with one of the VOC to be measured or any other VOC so long as the instrument has a response factor of less than 10 for each of the VOC to be measured.

G. Except as may be provided for in the special conditions of this permit, all pump, compressor and agitator seals shall be monitored with an approved gas analyzer at least quarterly or be equipped with a shaft sealing system that prevents or detects emissions of VOC from the seal. Seal systems designed and operated to prevent emissions or seals equipped with an automatic seal failure detection and alarm system need not be monitored. Seal systems that prevent emissions may include (but are not limited to) dual pump seals with barrier fluid at higher pressure than process pressure or seals degassing to vent control systems kept in good working order.

Submerged pumps or sealless pumps (including, but not limited to, diaphragm, canned, or magnetic-driven pumps) may be used to satisfy the requirements of this condition and need not be monitored.

H. Damaged or leaking valves, connectors, compressor seals, agitator seals, and pump seals found to be emitting VOC in excess of 10,000 parts per million by volume (ppmv) or found by visual inspection to be leaking (e.g., dripping process fluids) shall be tagged and replaced or repaired. A first attempt to repair the leak must be made within 5 days. Records of the first attempt to repair shall be maintained. A leaking component shall be repaired as soon as practicable, but no later than 15 days after the leak is found. If the repair of a component would require a unit shutdown, the repair may be delayed until the next scheduled shutdown. All leaking components which cannot be repaired until a scheduled shutdown shall be

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identified for such repair by tagging. At the discretion of the TCEQ Executive Director or designated representative, early unit shutdown or other appropriate action may be required based on the number and severity of tagged leaks awaiting shutdown.

I. Records of repairs shall include date of repairs, repair results, justification for delay of repairs, and corrective actions taken for all components. Records of instrument monitoring shall indicate dates and times, test methods, and instrument readings. The instrument monitoring record shall include the time that monitoring took place for no less than 95% of the instrument readings recorded. Records of physical inspections shall be noted in the operator’s log or equivalent.

J. Fugitive emission monitoring required by an applicable NSPS, 40 CFR Part 60, or an applicable NESHAP, 40 CFR Part 61, may be used in lieu of Items F through I of this condition.

K. Compliance with the requirements of this condition does not assure compliance with requirements of NSPS or NESHAP and does not constitute approval of alternate standards for these regulations.

Piping, Valves, Connectors, Pumps, and Compressors - 28VHP - Applies to components for EPNs FU-1 EMACT, FU-2 HON, FU-3 VOC and EPN FUG

22. Except as may be provided for in the special conditions of this permit, the following requirements apply to the above-referenced equipment:

A. The requirements of paragraphs F and G shall not apply (1) where the VOC has an aggregate partial pressure or vapor pressure of less than 0.044 pounds per square inch, absolute (psia) at 68° F or (2) operating pressure is at least 5 kilopascals (0.725 psi) below ambient pressure. Equipment excluded from this condition shall be identified in a list or by one of the methods described below to be made readily available upon request.

The exempted components may be identified by one or more of the following methods:

(1) piping and instrumentation diagram (PID);

(2) a written or electronic database or electronic file;

(3) color coding;

(4) a form of weatherproof identification; or

(5) designation of exempted process unit boundaries.

B. Construction of new and reworked piping, valves, pump systems, and compressor systems shall conform to applicable ANSI, API, ASME, or equivalent codes.

C. New and reworked underground process pipelines shall contain no buried valves such that fugitive emission monitoring is rendered impractical. New and reworked buried connectors shall be welded.

D. To the extent that good engineering practice will permit, new and reworked valves and piping connections shall be so located to be reasonably accessible for leak-checking during plant operation. Difficult-to-monitor and unsafe-to-monitor valves, as defined by Title 30 Texas Administrative Code Chapter 115 (30 TAC Chapter 115), shall be identified in a list to be made readily available upon request. The difficult-to-monitor and unsafe-to-monitor valves may be identified by one or more of the methods described in subparagraph A above. If an unsafe-to-monitor component is not considered safe to monitor within a calendar year, then it

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shall be monitored as soon as possible during safe-to-monitor times. A difficult-to-monitor component for which quarterly monitoring is specified may instead be monitored annually.

E. New and reworked piping connections shall be welded or flanged. Screwed connections are permissible only on piping smaller than two-inch diameter. Gas or hydraulic testing of the new and reworked piping connections at no less than operating pressure shall be performed prior to returning the components to service or they shall be monitored for leaks using an approved gas analyzer within 15 days of the components being returned to service. Adjustments shall be made as necessary to obtain leak-free performance. Connectors shall be inspected by visual, audible, and/or olfactory means at least weekly by operating personnel walk-through.

Each open-ended valve or line shall be equipped with an appropriately sized cap, blind flange, plug, or a second valve to seal the line. Except during sampling, both valves shall be closed. If the removal of a component for repair or replacement results in an open ended line or valve, it is exempt from the requirement to install a cap, blind flange, plug, or second valve for 72 hours. If the repair or replacement is not completed within 72 hours, the permit holder must complete either of the following actions within that time period;

(1) a cap, blind flange, plug, or second valve must be installed on the line or

valve; or

(2) the open-ended valve or line shall be monitored once for leaks above background for a plant or unit turnaround lasting up to 45 days with an approved gas analyzer and the results recorded. For all other situations, the open-ended valve or line shall be monitored once at the end of the 72 hour period following the creation of the open ended line and monthly thereafter with an approved gas analyzer and the results recorded. For turnarounds and all other situations, leaks are indicated by readings 500 ppmv above background and must be repaired within 24 hours or a cap, blind flange, plug, or second valve must be installed on the line or valve.

F. Accessible valves shall be monitored by leak-checking for fugitive emissions at least quarterly using an approved gas analyzer. Sealless/leakless valves (including, but not limited to, welded bonnet bellows and diaphragm valves) and relief valves equipped with a rupture disc upstream or venting to a control device are not required to be monitored. For valves equipped with rupture discs, a pressure-sensing device shall be installed between the relief valve and rupture disc to monitor disc integrity. All leaking discs shall be replaced at the earliest opportunity but no later than the next process shutdown.

A check of the reading of the pressure-sensing device to verify disc integrity shall be performed at least quarterly and recorded in the unit log or equivalent. Pressure-sensing devices that are continuously monitored with alarms are exempt from recordkeeping requirements specified in this paragraph.

The gas analyzer shall conform to requirements listed in Method 21 of 40 CFR Part 60, Appendix A. The gas analyzer shall be calibrated with methane. In addition, the response factor of the instrument for a specific VOC of interest shall be determined and meet the requirements of Section 8 of Method 21. If a mixture of VOCs are being monitored, the response factor shall be calculated for the average composition of the process fluid. A calculated average is not required when all of the compounds in the mixture have a response factor less than 10 using methane. If a response factor less than 10 cannot be achieved using methane, then the instrument may be calibrated with one of the VOC to be measured or any other VOC so long as the instrument has a response factor of less than 10 for each of the VOC to be measured.

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Replacements for leaking components shall be re-monitored within 15 days of being placed back into VOC service.

G. Except as may be provided for in the special conditions of this permit, all pump, compressor, and agitator seals shall be monitored with an approved gas analyzer at least quarterly or be equipped with a shaft sealing system that prevents or detects emissions of VOC from the seal. Seal systems designed and operated to prevent emissions or seals equipped with an automatic seal failure detection and alarm system need not be monitored. These seal systems may include (but are not limited to) dual pump seals with barrier fluid at higher pressure than process pressure, seals degassing to vent control systems kept in good working order, or seals equipped with an automatic seal failure detection and alarm system. Submerged pumps or sealless pumps (including, but not limited to, diaphragm, canned, or magnetic-driven pumps) may be used to satisfy the requirements of this condition and need not be monitored.

H. Damaged or leaking valves or connectors found to be emitting VOC in excess of 500 parts per million by volume (ppmv) or found by visual inspection to be leaking (e.g., dripping process fluids) shall be tagged and replaced or repaired. Damaged or leaking pump, compressor, and agitator seals found to be emitting VOC in excess of 2,000 ppmv or found by visual inspection to be leaking (e.g., dripping process fluids) shall be tagged and replaced or repaired. A first attempt to repair the leak must be made within 5 days. Records of the first attempt to repair shall be maintained.

I. A leaking component shall be repaired as soon as practicable, but no later than 15 days after the leak is found. If the repair of a component would require a unit shutdown that would create more emissions than the repair would eliminate, the repair may be delayed until the next scheduled shutdown. All leaking components which cannot be repaired until a scheduled shutdown shall be identified for such repair by tagging within 15 days of the detection of the leak. A listing of all components that qualify for delay of repair shall be maintained on a delay of repair list. The cumulative daily emissions from all components on the delay of repair list shall be estimated by multiplying by 24 the mass emission rate for each component calculated in accordance with the instructions in 30 TAC § 115.782(c)(1)(B)(i)(II). The calculations of the cumulative daily emissions from all components on the delay of repair list shall be updated within ten days of when the latest leaking component is added to the delay of repair list. When the cumulative daily emission rate of all components on the delay of repair list times the number of days until the next scheduled unit shutdown is equal to or exceeds the total emissions from a unit shutdown as calculated in accordance with 30 TAC § 115.782(c)(1)(B)(i)(I), the TCEQ Regional Manager and any local programs shall be notified and may require early unit shutdown or other appropriate action based on the number and severity of tagged leaks awaiting shutdown. This notification shall be made within 15 days of making this determination.

J. Records of repairs shall include date of repairs, repair results, justification for delay of repairs, and corrective actions taken for all components. Records of instrument monitoring shall indicate dates and times, test methods, and instrument readings. The instrument monitoring record shall include the time that monitoring took place for no less than 95% of the instrument readings recorded. Records of physical inspections shall be noted in the operator’s log or equivalent.

K. Alternative monitoring frequency schedules of 30 TAC §§115.352 - 115.359 or National Emission Standards for Organic Hazardous Air Pollutants, 40 CFR Part 63, Subpart H, may be used in lieu of Items F through G of this condition.

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L. Compliance with the requirements of this condition does not assure compliance with requirements of 30 TAC Chapter 115, an applicable NSPS, or an applicable NESHAP and does not constitute approval of alternative standards for these regulations.

23. In addition to the weekly physical inspection required by Item E of Special Condition No. 22, all connectors in gas or vapor and light liquid service shall be monitored annually with an approved gas analyzer in accordance with Items F through J of Special Condition No. 22. Alternative monitoring frequency schedules of 40 CFR Part 63, Subpart H, National Emission Standards for Organic Hazardous Air Pollutants for Equipment Leaks, may be used in lieu of the monitoring frequency required by this permit condition. Compliance with this condition does not assure compliance with requirements of applicable state or federal regulation and does not constitute approval of alternative standards for these regulations. This special condition only applies to process fugitive components under the designation of EPN FU-2. (TBD)

Painting Operations

24. Painting operations shall meet the following limits:

A. No more than six pounds per hour of VOC emissions, averaged over any five-hour period, and 500 pounds per week shall be emitted at any time for all operations authorized by this paragraph.

B. If coatings applied with spray equipment contain more than 0.1 percent by weight of chromates, lead, cadmium, selenium, strontium, or cobalt, then total VOC emissions shall be further limited to 240 pounds per week and 2,000 pounds per year. If coatings are applied with non-spray equipment (such as brushes, rollers, dipping, or flow coating), the additional restrictions in this paragraph do not apply.

Coating operations shall be conducted at least 50 feet from the property line and at least 250 feet from any recreational area, residence, or other structure not occupied or used solely by the owner or operator of the facility or the owner of the property upon which the facility is located.

Carbon Beds

25. The covered oil water separator shall vent through a non regenerative carbon adsorption system (CAS) designated as EPN 13C consisting of at least two activated carbon canisters connected in series.

A. The CAS shall be sampled once a month to determine breakthrough of VOC. The sampling point shall be at the outlet of the initial canister but before the inlet to the second or final polishing canister. Sampling shall be done during normal operation of the covered oil water separator.

B. The VOC sampling and analysis shall be performed using an instrument with a photo ionization detector (PID), or a TCEQ-approved alternative detector. The instrument/PID must meet all requirements specified in Section 8.1 of EPA Method 21 (40 CFR 60, Appendix A). Sampling and analysis for VOC breakthrough shall be performed as follows:

(1) Immediately prior to performing sampling, the instrument/PID shall be calibrated with zero and span calibration gas mixtures. Zero gas shall be certified to contain less than

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0.1 ppmv total hydrocarbons. Span calibration gas shall be a calibration gas such that the response factor (RF) of the VOC (or mixture of VOC’s) being monitored is less than 2.0 at a concentration within ± 10 percent of 100 ppmv, and certified by the manufacturer to be ± 2 percent accurate. Calibration error for the zero and span calibration gas checks must be less than ± 5 percent of the span calibration gas value before sampling may be conducted.

(2) The sampling point shall be at the outlet of the initial canister but before the inlet to the second or final polishing canister. Sample ports or connections must be designed such that air leakage into the sample port does not occur during sampling.

(3) During sampling, data recording shall not begin until after two times the instrument response time. The VOC concentration shall be monitored for at least 5 minutes, recording 1-minute averages, during normal operation of the covered oil water separator.

C. Breakthrough shall be defined as the highest one minute average measured VOC concentration at or exceeding 100 ppmv. When the condition of breakthrough of VOC from the initial saturation canister occurs, the waste gas flow shall be switched to the second canister and a fresh canister shall be placed as the new final polishing canister within twenty-four hours. Sufficient new activated carbon canisters shall be maintained at the site to replace spent carbon canisters such that replacements can be done in the above specified time frame.

D. Records of the CAS monitoring maintained at the plant site, shall include (but are not limited to) the following:

(1) Sample time and date.

(2) Monitoring results (ppmv).

(3) Corrective action taken including the time and date of that action.

(4) Process operations occurring at the time of sampling.

E. Alternate monitoring or sampling requirements that are equivalent or better may be approved by the TCEQ Regional Manager. Alternate requirements must be approved in writing before they can be used for compliance purposes.

Requirements for Continuous Emissions Monitoring Systems (CEMS)

26. The permit holder shall install, calibrate, and maintain a continuous emission monitoring System (CEMS) to measure and record the in-stack concentration of NOx and CO from pyrolysis USC furnaces A through N and VMR furnaces A and B. Each CEMS required for pyrolysis USC furnaces A through N and VMR furnaces A and B shall be operational not later than 60 days after the emission source achieves maximum operation, not to exceed 180 days after completion of modifications authorized by amendment application under PI-1 dated March 1, 2013. (04/14)

A. The CEMS shall meet the design and performance specifications, pass the field tests, and meet the installation requirements and the data analysis and reporting requirements specified in the applicable Performance Specification Nos. 1 through 9, Title 40 Code of Federal Regulation Part 60 (40 CFR Part 60), Appendix B. If there are no applicable performance specifications in 40 CFR Part 60, Appendix B, contact the TCEQ Office of Air, Air Permits Division for requirements to be met.

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B. Section 1 below applies to sources subject to the quality-assurance requirements of 40 CFR Part 60, Appendix F; section 2 applies to all other sources:

(1) The permit holder shall assure that the CEMS meets the applicable quality-assurance requirements specified in 40 CFR Part 60, Appendix F, Procedure 1. Relative accuracy exceedances, as specified in 40 CFR Part 60, Appendix F, Section 5.2.3 and any CEMS downtime shall be reported to the appropriate TCEQ Regional Manager, and necessary corrective action shall be taken. Supplemental stack concentration measurements may be required at the discretion of the appropriate TCEQ Regional Manager.

(2) The system shall be zeroed and spanned daily, and corrective action taken when the 24-hour span drift exceeds two times the amounts specified in the applicable Performance Specification Nos. 1 through 9, 40 CFR Part 60, Appendix B, or as specified by the TCEQ if not specified in Appendix B. Zero and span is not required on weekends and plant holidays if instrument technicians are not normally scheduled on those days. Daily zero and span can be accomplished with either zero and span gas or appropriate optical filters to test analyzers.

Each monitor shall be quality-assured at least quarterly using Cylinder Gas Audits (CGA) in accordance with 40 CFR Part 60, Appendix F, Procedure 1, Section 5.1.2, with the following exception: a relative accuracy test audit (RATA) is not required once every four quarters (i.e., four successive quarterly CGA may be conducted). An equivalent quality-assurance method approved by the TCEQ may also be used. Successive quarterly audits shall occur no closer than two months.

All CGA exceedances of +15 percent accuracy indicate that the CEMS is out of control.

C. The monitoring data shall be reduced to hourly average concentrations at least once every day, using a minimum of four equally-spaced data points from each one-hour period. The individual average concentrations shall be reduced to units of the permit allowable emission rates in pounds per hour at least once every week. To determine the hourly emission rate, the measured hourly average concentration from the CEMS shall be multiplied by the allowable emission rate calculation basis flow rate identified in the permit application, PI-1 March 1, 2013.

D. All monitoring data and quality-assurance data shall be maintained by the source. The data from the CEMS may, at the discretion of the TCEQ, be used to determine compliance with the conditions of this permit.

E. The appropriate TCEQ Regional Office shall be notified at least 30 days prior to any required RATA in order to provide them the opportunity to observe the testing.

F. Quality-assured (or valid) data must be generated when the (facility generating emissions) is operating except during the performance of a daily zero and span check. Loss of valid data due to periods of monitor break down, out-of-control operation (producing inaccurate data), repair, maintenance, or calibration may be exempted provided it does not exceed 5 percent of the time (in minutes) that the (facility generating emissions) operated over the previous rolling 12-month period. The measurements missed shall be estimated using engineering judgement and the methods used recorded. Options to increase system reliability to an acceptable value, including a redundant CEMS, may be required by the TCEQ Regional Manager.

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Sampling and Monitoring Requirements

27. If the normal production rate of the facilities listed below exceeds the operating rate maintained during sampling by more than 10 percent, the permit holder must notify, in writing, the appropriate TCEQ Regional Office and the source may be subject to additional sampling to demonstrate continued compliance with all applicable state and federal regulations. (04/14)

Source Maximum Operating Conditions MMBtu/hr each

HP Boilers A-D 302 USC Furnaces A, B, K, L 188 USC Furnaces C, D, E, F, G, H, J, M, N 290 VMR Furnaces A, B 126.7 Steam Superheaters A, B 146

28. Sampling ports and platform(s) shall be available for each type of ethylene furnace EPN and each ethylene furnace decoking cyclone EPN according to the specifications set forth in the attachment entitled “Chapter 2, Stack Sampling Facilities” of the TCEQ Sampling Procedures Manual. Alternate sampling facility designs must be submitted for approval to the TCEQ Regional Director.

The holder of this permit shall perform stack sampling and other testing as required to establish the actual pattern and quantities of air contaminants being emitted into the atmosphere from each EPN designated in this special condition upon request by the TCEQ Executive Director. Sampling shall be conducted in accordance with the appropriate procedures of the TCEQ Sampling Procedures Manual and the U.S. EPA Reference Methods. The holder of this permit is responsible for providing sampling and testing facilities and conducting the sampling and testing operations at his expense.

A. The appropriate TCEQ Regional Office in the region where the source is located shall be contacted as soon as testing is scheduled but not less than 45 days prior to sampling to schedule a pretest meeting.

The notice shall include:

(1) Date for pretest meeting.

(2) Date sampling will occur.

(3) Name of firm conducting sampling.

(4) Type of sampling equipment to be used.

(5) Method or procedure to be used in sampling.

The purpose of the pretest meeting is to review the necessary sampling and testing procedures, to provide the proper data forms for recording pertinent data, and to review the format procedures for submitting the test reports.

A written proposed description of any deviation from sampling procedures specified in permit conditions or TCEQ or EPA sampling procedures shall be made available to the TCEQ prior to the pretest meeting. The TCEQ Regional Director shall approve or disapprove of any deviation from specified sampling procedures.

Requests to waive testing for any pollutant specified in this condition shall be submitted to the TCEQ Air Permits Division. Test waivers and alternate/equivalent procedure

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proposals for NSPS testing which must have EPA approval shall be submitted to the nearest TCEQ Regional Director.

B. Air contaminants emitted from the ethylene furnace(s) to be tested for include (but are not limited to) oxides of nitrogen (NOx) and carbon monoxide (CO). (04/14)

C. Decoking opacity measurements shall occur not later than 180 days after April 16, 2014. Opacity measurement from one of the two ethylene furnace decoking cyclones designated as EPN 9A or 9B shall be tested according to EPA Reference Method 9. At the pretest meeting, additional parameters will be identified and selected for monitoring during the opacity measurement. The decoking cyclone to be measured for opacity shall be determined at the pretest meeting. (04/14) Opacity measurements shall be done when the decoking cyclone is operating under maximum operating conditions. If the opacity measurements results demonstrate compliance with the percent opacity shown in special condition number seven then compliance is shown for the two decoking cyclones designated as EPNs 9A and 9B.

If the opacity measurements results do not demonstrate compliance with the percent opacity in special condition number seven then the decoking cyclones identified as EPN 9A and 9B are not in compliance; therefore, each decoking cyclone EPN will be subject to opacity measurements following the requirements in this special condition and Reference Method 9 to demonstrate compliance with the percent opacity requirements in special condition number seven. This follow up opacity measurements shall occur within 60 days, but not later than 120 days after the date the opacity measurements showed noncompliance with the percent opacity in special condition number seven.

The opacity measurement(s) and cyclone stack test operating parameter(s) obtained from each decoking cyclone will be correlated with the most recent opacity measurements to develop a method of determining continuous compliance for opacity from decoking cyclone EPNs 9A and 9B. The continuous compliance method will be a calculation performed, updated and recorded by the permit holder once a day to clearly demonstrate ongoing compliance with percent opacity in special condition number seven from EPNs 9A and 9B. The calculation will be clearly documented by the permit holder and these records shall be clearly made readily available at the request of TCEQ or EPA personnel.

D. Sampling shall occur at such times as may be required by the Executive Director of the TCEQ. Requests for additional time to perform sampling shall be submitted to the TCEQ Regional Office. Additional time to comply with the applicable requirements of 40 CFR Part 60 and 40 CFR Part 61 requires EPA approval, and requests shall be submitted to the nearest TCEQ Regional Office.

E. The plant shall operate at maximum production rates during stack emission testing. Primary conditions/parameters and any other primary operating parameters that affect the emission rate shall be monitored and recorded during the stack test. Primary operating parameters that enable determination of production rates shall be monitored and recorded during the stack test. Any additional parameters shall be determined at the pretest meeting and shall be stated in the sampling report. Permit conditions and parameter limits may be waived during stack testing performed under this condition if the proposed condition/parameter range is identified in the test notice specified in paragraph a and accepted by the TCEQ Regional Office. Permit allowable emissions and emission control requirements are not waived and still apply during stack testing periods.

During subsequent operations, if each ethylene furnace and/or each decoking cyclone operating values are greater than those same values recorded during the most recent stack

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test period, stack sampling shall be performed at the new operating conditions within 120 days.

F. Sampling reports shall comply with the attached provisions of Chapter 14 of the TCEQ Sampling Procedures Manual. One copy of the final sampling report shall be forwarded to the following within 60 days after sampling is completed:

One copy to the TCEQ Corpus Christi Regional Office.

One copy to the EPA, Air Enforcement Branch, Dallas Office.

Referenced Permits-by-Rule

29. The following sources and/or activities are authorized under a Permit by Rule (PBR) by Title 30 Texas Administrative Code Chapter 106 (30 TAC Chapter 106). These lists are not intended to be all inclusive and can be altered without modifications to this permit. (04/14)

Authorization Source or Activity PBR No. 95855 Change of service for Tank F-2009A PBR No. 101862 Construction of tank truck unloading racks for

condensate

Greenhouse Gas Emissions

30. Permit holders must keep records sufficient to demonstrate compliance with 30 Texas Administrative Code § 116.164. If construction, a physical change or a change in method of operation results in Prevention of Significant Deterioration (PSD) review for criteria pollutants, records shall be sufficient to demonstrate the amount of emissions of Greenhouse Gas (GHG) from the source as a result of construction, a physical change or a change in method of operation does not require authorization under 30 TAC §116.164(a). If there is construction, a physical change or change in the method of operation that will result in a net emission increase of 75,000 tpy or more CO2e and PSD review is triggered for criteria pollutants, greenhouse gas emissions are subject to PSD review. (TBD)

31. Monitoring, quality assurance/quality control requirements, emission calculation methodologies, record keeping, and reporting requirements related to GHG emissions shall adhere to the applicable requirements in 40 CFR Part 98 and in this permit. (TBD)

32. Permittee shall calculate the CO2e emissions on a 12-month rolling basis, based on the procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1. (TBD)

33. Records of emissions of GHG, and how they were determined, in compliance with Special Condition Nos. 30, 31, and 32 must be maintained by the holder of this permit in a form suitable for inspection for a period of five years after collection and must be made available upon request to representatives of the TCEQ, EPA, or any local air pollution control program having jurisdiction. (TBD)

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Recordkeeping

34. The records required by these special conditions shall be maintained in either hard copy or electronic format and shall be maintained for at least five years rather than the two-year period specified in General Condition No. 7. These records shall be made immediately available at the request of personnel from the TCEQ or any air pollution control agency with jurisdiction. (TBD)

Date: TBD

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Project Number: 310455

Emission Sources - Maximum Allowable Emission Rates

Permit Number 4682B This table lists the maximum allowable emission rates and all sources of air contaminants on the applicant’s property covered by this permit. The emission rates shown are those derived from information submitted as part of the application for permit and are the maximum rates allowed for these facilities, sources, and related activities. Any proposed increase in emission rates may require an application for a modification of the facilities covered by this permit.

Air Contaminants Data

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

1A USC Furnace A

CO 6.74 29.52

NOX 11.28 49.41

PM 0.94 4.12

PM10 0.94 4.12

PM2.5 0.94 4.12

SO2 0.11 0.48

VOC 1.01 4.44

1B USC Furnace B

CO 6.74 29.52

NOX 11.28 49.41

PM 0.94 4.12

PM10 0.94 4.12

PM2.5 0.94 4.12

SO2 0.11 0.48

VOC 1.01 4.44

1C USC Furnace C

CO 10.40 45.54

NOX 17.40 76.21

PM 1.45 6.35

PM10 1.45 6.35

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

1D USC Furnace D

CO 10.40 45.54

NOX 17.40 76.21

PM 1.45 6.35

PM10 1.45 6.35

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Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

1E USC Furnace E

CO 10.40 45.54

NOX 17.40 76.21

PM 1.45 6.35

PM10 1.45 6.35

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

1F USC Furnace F

CO 10.40 45.54

NOX 17.40 76.21

PM 1.45 6.35

PM10 1.45 6.35

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

1G USC Furnace G

CO 10.40 45.54

NOX 17.40 76.21

PM 1.45 6.35

PM10 1.45 6.35

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

1H USC Furnace H

CO 10.40 45.54

NOX 17.40 76.21

PM 1.45 6.35

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Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

PM10 1.45 6.35

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

1J USC Furnace J

CO 10.40 45.54

NOX 17.40 76.21

PM 1.45 6.35

PM10 1.45 6.35

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

1K USC Furnace K

CO 6.74 29.52

NOX 11.28 49.41

PM 0.94 4.12

PM10 0.94 4.12

PM2.5 0.94 4.12

SO2 0.11 0.48

VOC 1.01 4.44

1L USC Furnace L

CO 6.74 29.52

NOX 11.28 49.41

PM 0.94 4.12

PM10 0.94 4.12

PM2.5 0.94 4.12

SO2 0.11 0.48

VOC 1.01 4.44

1M USC Furnace M CO 10.40 45.54

NOX 17.40 76.21

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Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

PM 1.45 6.35

PM10 1.45 6.35

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

1N USC Furnace N

CO 10.40 45.54

NOX 17.40 76.21

PM 1.45 6.35

PM10 1.45 6.35

PM2.5 1.45 6.35

SO2 0.17 0.75

VOC 1.56 6.85

3A VMR Furnace A

CO 4.54 19.89

NOX 7.60 33.30

PM 0.63 2.77

PM10 0.63 2.77

PM2.5 0.63 2.77

SO2 0.07 0.33

VOC 0.68 2.99

3B VMR Furnace B

CO 4.54 19.89

NOX 7.60 33.30

PM 0.63 2.77

PM10 0.63 2.77

PM2.5 0.63 2.77

SO2 0.07 0.33

VOC 0.68 2.99

4A HP Steam Boiler A CO 23.65 103.59

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Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

NOX 94.63 414.46

PM10 23.14 101.33

SO2 284.48 1246.04

SO3 10.33 25.24

VOC 1.56 6.78

4B HP Steam Boiler B

CO 23.65 103.59

NOX 53.50 234.32

PM10 2.14 9.37

SO2 0.18 0.78

VOC 1.56 6.78

4C HP Steam Boiler C

CO 23.65 103.59

NOX 53.50 234.32

PM10 2.14 9.37

SO2 0.18 0.78

VOC 1.56 6.78

4D HP Steam Boiler D

CO 23.65 103.59

NOX 53.50 234.32

PM10 2.14 9.37

SO2 0.18 0.78

VOC 1.56 6.78

5A Steam Superheater A

CO 5.22 22.86

NOX 8.74 38.26

PM 0.73 3.19

PM10 0.73 3.19

PM2.5 0.73 3.19

SO2 0.09 0.38

VOC 0.79 3.44

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Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

5B Steam Superheater B

CO 5.22 22.86

NOX 8.74 38.26

PM 0.73 3.19

PM10 0.73 3.19

PM2.5 0.73 3.19

SO2 0.09 0.38

VOC 0.79 3.44

6 HDA Feed Heater

CO 7.08 31.00

NOX 8.42 36.90

PM10 0.64 2.80

SO2 0.05 0.23

VOC 0.46 2.03

7 HDA Recycle Heater

CO 0.49 2.15

NOX 0.59 2.56

PM10 0.04 0.19

SO2 0.01 0.02

VOC 0.03 0.14

8 Dryer Regeneration Heater

CO 1.61 7.05

NOX 1.92 8.39

PM10 0.15 0.64

SO2 0.01 0.05

VOC 0.11 0.46

8A Cat. Reactivation Furnace

CO 2.12 9.30

NOX 2.53 11.07

PM10 0.19 0.84

SO2 0.02 0.07

VOC 0.14 0.61

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Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

9A South Decoking Cyclone

CO 1932.94 135.80

PM 11.63 1.37

PM10 3.58 0.43

PM2.5 3.58 0.43

VOC 0.05 0.02

9B North Decoking Cyclone

CO 1999.16 133.80

PM 12.47 1.35

PM10 3.84 0.42

PM2.5 3.84 0.42

VOC 0.04 0.02

10 Hot Flare

CO 1097.55 152.24

NOX 210.44 24.17

SO2 64.68 2.66

VOC 369.22 16.02

11 Cold Flare

CO 107.81 128.60

NOX 20.36 18.81

SO2 0.08 0.28

VOC 76.88 14.65

12 Cooling Tower

VOC 2.92 12.79

PM 4.05 15.33

PM10 4.05 15.33

PM2.5 1.20 4.55

12B Cooling Tower

VOC 2.02 3.72

PM 1.20 4.54

PM10 1.20 4.54

PM2.5 0.36 1.35

13C Carbon Canisters in Series VOC 0.06 0.01

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Permit Number 4682B Page 8

Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

16 Naphtha Feedstock Day Tank VOC 1.52 2.52

17 Kerosene Feedstock Day Tank VOC 1.52 2.47

18 Light Fuel Oil Tank VOC 3.07 4.30

19 Raw Pyrolysis Gasoline Tank VOC 1.74 4.90

20A Heavy Oil Fuel Tank VOC 4.30 5.10

20B Heavy Oil Fuel Tank VOC 4.30 5.10

23A Benzene Tank VOC 0.17 0.31

24 HDA Tank VOC 1.45 3.94

30A Feedstock Tank VOC 3.37 10.01

30B Feedstock Tank VOC 3.37 10.04

30C Feedstock Tank VOC 3.39 10.13

31 Second Stage Feed Heater

CO 1.27 5.55

NOX 1.51 6.60

PM10 0.11 0.50

SO2 0.01 0.04

VOC 0.08 0.36

32 Lube Oil Tank VOC 16.27 0.15

33 Wash Oil Tank VOC 0.23 0.43

39A Spent Caustic Gasoline Wash Tank VOC 0.64 1.07

39B Spent Caustic Gasoline Wash Tank VOC 0.41 0.85

40 Recovered Oil Tank VOC 0.30 0.87

42 Methanol Tank VOC 4.08 0.04

43 Fuel Oil Truck Loading VOC 29.63 7.04

50 Spent Caustic Wastewater VOC 0.03 0.06

51 Spent Caustic Wastewater VOC 0.06 0.12

52 Wastewater Tank VOC 0.75 1.15

53 Slop Oil Tank VOC 0.26 0.77

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Permit Number 4682B Page 9

Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

55 Hot Water Belt Tank VOC 1.01 3.19

AC-1 Air Compressor Engine No. 1 (8)

CO 2.74 2.05

NOX 3.03 2.27

PM10 0.16 0.12

SO2 0.97 0.73

VOC 0.12 0.09

AC-1 Air Compressor Engine No. 2 (8)

CO 2.74 2.05

NOX 3.03 2.27

PM10 0.16 0.12

SO2 0.97 0.73

VOC 0.12 0.09

F2602A Vehicle Diesel Tank VOC 0.70 0.01

F2603 Vehicle Gasoline Tank VOC 51.22 1.26

FA1665 Diesel Tank VOC 0.22 0.01

FU-1 EMACT Process Fugitives (5) VOC 23.14 101.42

FU-2 HON Process Fugitives (5) VOC 0.93 4.08

FU-3 Process Fugitives (5) VOC 13.73 60.13

FU-4 NESHAP FF Fugitives (5) VOC 0.02 0.10

FUG Fugitive Emissions (5) VOC 8.02 35.14

FWDIESELA Firewater Diesel Tank VOC 0.02 0.01

FWDIESELB Firewater Diesel Tank VOC 0.02 0.01

FWDIESELC Firewater Diesel Tank VOC 0.02 0.01

FWDIESELD Firewater Diesel Tank VOC 0.02 0.01

J-2019-A Olefin Firewater Engine (7)

CO 2.87 0.36

NOX 13.33 1.67

PM10 0.95 0.12

SO2 0.88 0.11

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Permit Number 4682B Page 10

Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

Emission Point No. (1) Source Name (2) Air Contaminant

Name (3) Emission Rates

lbs/hour TPY (4)

VOC 1.06 0.13

J-2019-B Olefin Firewater Engine (7)

CO 2.87 0.36

NOX 13.33 1.67

PM10 0.95 0.12

SO2 0.88 0.11

VOC 1.06 0.13

J-2019-C Olefin Firewater Engine (7)

CO 2.87 0.36

NOX 13.33 1.67

PM10 0.95 0.12

SO2 0.88 0.11

VOC 1.06 0.13

J-2019-D Olefin Firewater Engine (7)

CO 2.87 0.36

NOX 13.33 1.67

PM10 0.95 0.12

SO2 0.88 0.11

VOC 1.06 0.13

L-1697 Emergency Generator (6)

CO 0.85 0.02

NOX 10.37 0.27

PM10 0.06 0.01

SO2 1.65 0.04

VOC 0.02 0.01

PAINT Painting VOC 2.00 0.32

WWC-1 Wastewater Collection VOC 1.37 0.22

(1) Emission point identification - either specific equipment designation or emission point number from plot plan. (2) Specific point source name. For fugitive sources, use area name or fugitive source name. (3) VOC - volatile organic compounds as defined in Title 30 Texas Administrative Code § 101.1

NOx - total oxides of nitrogen SO2 - sulfur dioxide PM - total particulate matter, suspended in the atmosphere, including PM10 and PM2.5, as represented

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Permit Number 4682B Page 11

Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

PM10 - total particulate matter equal to or less than 10 microns in diameter, including PM2.5, as represented

PM2.5 - particulate matter equal to or less than 2.5 microns in diameter CO - carbon monoxide

(4) Compliance with annual emission limits (tons per year) is based on a 12 month rolling period. (5) Emission rate is an estimate and is enforceable through compliance with the applicable special condition(s) and

permit application representations. (6) 52 hours per rolling twelve months of operation (7) 250 hours per rolling twelve months of operation (8) 1,500 hours per rolling twelve months of operation

Date: TBD

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Project Number: 310455

Emission Sources - Maximum Allowable Emission Rates

Permit Number 4682B This table lists the maximum allowable emission rates of greenhouse gas (GHG) emissions, as defined in Title 30 Texas Administrative Code § 101.1, for all sources of GHG air contaminants on the applicant’s property that are authorized by this permit. The emission rates shown are those derived from information submitted as part of the application for permit and are the maximum rates allowed for these facilities, sources, and related activities. Any proposed increase in emission rates may require an application for a modification of the facilities authorized by this permit.

Air Contaminants Data

Emission Point No. (1) Source Name (2) Air Contaminant Name (3)

Emission Rates

TPY (4)

1A

USC Furnace A

CO2 (5) 93,838.00

CH4 (5) 5.50

N2O (5) 1.10

CO2e 94,303

1B

USC Furnace B

CO2 (5) 93,838.00

CH4 (5) 5.50

N2O (5) 1.10

CO2e 94,303

1C

USC Furnace C

CO2 (5) 144,751.00

CH4 (5) 8.40

N2O (5) 1.70

CO2e 145,468

1D

USC Furnace D

CO2 (5) 144,751.00

CH4 (5) 8.40

N2O (5) 1.70

CO2e 145,468

1E

USC Furnace E

CO2 (5) 144,751.00

CH4 (5) 8.40

N2O (5) 1.70

CO2e 145,468

1F

USC Furnace F

CO2 (5) 144,751.00

CH4 (5) 8.40

N2O (5) 1.70

CO2e 145,468

1G

USC Furnace G

CO2 (5) 144,751.00

CH4 (5) 8.40

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Permit Number 4682B Page 2

Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

N2O (5) 1.70

CO2e 145,468

1H

USC Furnace H

CO2 (5) 144,751.00

CH4 (5) 8.40

N2O (5) 1.70

CO2e 145,468

1J

USC Furnace J

CO2 (5) 144,751.00

CH4 (5) 8.40

N2O (5) 1.70

CO2e 145,468

1K

USC Furnace K

CO2 (5) 93,838.00

CH4 (5) 5.50

N2O (5) 1.10

CO2e 94,303

1L

USC Furnace L

CO2 (5) 93,838.00

CH4 (5) 5.50

N2O (5) 1.10

CO2e 94,303

1M

USC Furnace M

CO2 (5) 144,751.00

CH4 (5) 8.40

N2O (5) 1.70

CO2e 145,468

1N

USC Furnace N

CO2 (5) 144,751.00

CH4 (5) 8.40

N2O (5) 1.70

CO2e 145,468

3A

VMR Furnace A

CO2 (5) 63,241.00

CH4 (5) 3.70

N2O (5) 0.70

CO2e 63,542

3B

VMR Furnace B

CO2 (5) 63,241.00

CH4 (5) 3.70

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Permit Number 4682B Page 3

Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

(1) Emission point identification - either specific equipment designation or emission point number from plot plan. (2) Specific point source name. For fugitive sources, use area name or fugitive source name. (3) CO2 - carbon dioxide N2O - nitrous oxide CH4 - methane HFCs - hydrofluorocarbons PFCs - perfluorocarbons SF6 - sulfur hexafluoride CO2e - carbon dioxide equivalents based on the following Global Warming Potentials (1/2015):

N2O (5) 0.70

CO2e 63,542

5A

Steam Superheater A

CO2 (5) 72,675.00

CH4 (5) 4.20

N2O (5) 0.80

CO2e 73,018

5B

Steam Superheater B

CO2 (5) 72,675.00

CH4 (5) 4.20

N2O (5) 0.80

CO2e 73,018

9A and 9B

North & South Decoking Cyclones (6)

CO2 (5) 1,270.00

CO2e 1,270

11 Hot Flare CO2 (5) 45,396.92

CH4 (5) 137.03

N2O (5) 0.45

CO2e 48,958

12 Cold Flare CO2 (5) 45,205.52

CH4 (5) 136.45

N2O (5) 0.45

CO2e 48,752

FUG

Fugitive Emissions

CH4 (5) (7)

CO2e (7)

10 DBN MSS Elevated Flare - MSS CO2 (5) 3,866.00

CH4 (5) 13.30

N2O (5) 0.01

CO2e 4,201

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Permit Number 4682B Page 4

Emission Sources - Maximum Allowable Emission Rates

Project Number: 310455

CO2 (1), N2O (298), CH4(25), SF6 (22,800), HFC (various), PFC (various) (4) Compliance with annual emission limits (tons per year) is based on a 12-month rolling period. These rates include

emissions from maintenance, startup, and shutdown. (5) Emission rate is given for informational purposes only and does not constitute enforceable limit. (6) The North & South Decoking Cyclones (EPNs 9A and 9B) emissions are estimated to be 1,270 CO2/CO2e for both

decoke cyclones combined. (7) Fugitive process emissions from EPN FUG are estimated to be 18.4 tpy of CH4 and 460 tpy CO2e. In lieu of an

emission limit, the emissions will be limited by implementing a design/work practice standard as specified in the permit.

Date: TBD

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Preliminary Determination Summary

Permit Numbers 4682B, PSDTX761M4, and GHGPSDTX32M1 I. Applicant

Equistar Chemicals LP PO Box 10940 Corpus Christi, TX 78460-0940

II. Project Location

Equistar Chemicals 1501 McKinzie Rd Nueces County Corpus Christi, Texas 78410

III. Project Description

Equistar submitted an amendment to authorize additional natural gas for the flares (EPNs 10 and 11) in anticipation of the proposed amendments to the 2002 Ethylene Production National Emission Standards for Hazardous Air Pollutants (NESHAP). Additionally, Permit by Rule (PBR) Registration Nos. 131202, 136589, 141992, 155067 are being incorporated into the permit by consolidation and will be voided upon issuance. Maintenance, startup, and shutdown (MSS) emissions are authorized under Permit No. 83864.

IV. Emissions

Air Contaminant Proposed Allowable Emission Rates (tpy)

VOC 452.81

NOx 2,264.06

SO2 1,263.76

CO 1,638.85

PM/PM10/PM2.5 108.14/241.41/92.30 CO2 Equivalents (CO2e) 2,062,725.00

CO2e - carbon dioxide equivalents based on global warming potentials of CH4 = 25, N2O = 298, SF6 = 22,800.

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Preliminary Determination Summary Permit Numbers: 4682B, PSDTX761M4, and GHGPSDTX32M1 Page 2

V. Federal Applicability

The following chart illustrates the annual project emissions for each pollutant and whether this pollutant triggers PSD or Nonattainment (NA) review.

Pollutant Project Emissions (tpy)

Major Mod Trigger (tpy)

NA Triggered Y/N

PSD Triggered Y/N

VOC 18.12 25 for NA 40 for PSD N/A N

NOx 28.93 25 for NA 40 for PSD N/A N

SO2 2.61 40 N/A N

CO 206.46 100 N/A Y

The proposed project triggers PSD review for non-GHG NSR regulated pollutants. As shown in the table below, because the project increase is more than 75,000 tpy of CO2e, PSD review is triggered for GHG emissions.

Pollutant Project Emissions (tpy)

Major Source or Major Mod Trigger Level (tpy)

PSD Triggered Y/N

CO2e 97,709.43 75,000 Y

The site is located in Nueces County, which has been designated as attainment for all criteria pollutants. NNSR does not apply. The site is a named source and has a potential to emit (PTE) in excess of 100 tpy for at least one pollutant. PSD review applies, and PSD Air Quality Analysis (AQA) and Best Available Control Technology (BACT) requirements apply to the following pollutants for which the PTE exceeds an applicable significance threshold (40 CFR § 52.21(b)(23)(i)): CO. The PTE for VOC, NOX, and SO2 are less than the applicable significance thresholds, and PSD AQA and BACT requirements do not apply for these pollutants. Instead, Minor NSR AQA and BACT requirements apply. Finally, the facility has a PTE in excess of 100 tpy (mass basis) and 75,000 tpy GHG (CO2e basis) for GHG. GHG are therefore subject to regulation (40 CFR § 52.21(b)(49)(iv)) and PSD BACT requirements apply to GHG.

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Preliminary Determination Summary Permit Numbers: 4682B, PSDTX761M4, and GHGPSDTX32M1 Page 3 Pollutant Project

Increase (tpy) 1

NA Nettin

g Trigger (tpy)

PSD Netting Trigger

(tpy)

Netting Required Y/N

Net Emissio

n Change (tpy) 2

Major Mod

Trigger (tpy)

PSD Triggere

d Y/N

NA Triggere

d Y/N

VOC 3 18.12 N/A 40 N N/A 40 N N/A NOx 3 , 4 28.93 N/A 40 N N/A 40 N N/A SO2 4 2.61 N/A 40 N N/A 40 N N/A CO 206.46 N/A 100 Y 206.46 100 Y N/A

Note: Nonattainment (NA) significance levels (trigger levels) should follow current Federal New Source Review (FNSR) guidance, and be based on the classification of the NA area in which the project is proposed. 1 Project Increases: Comparison of Baseline Actual to PTE (or Projected Actual)

Increases only 2 Net Emissions: Baseline Actual to PTE (or Projected Actual) for the project currently

under review, Baseline Actual to PTE for all other increases and decreases within netting window.

3 Ozone precursor. Either pollutant precursor can trigger BACT/LAER and impacts

analysis, as applicable. 4 PM2.5 precursor. Not used to trigger PM2.5 BACT/LAER or impacts analysis at this

time.

VI. Control Technology Review

The draft permit requires controls (detailed below) consistent with PSD BACT for PSD pollutants (CO and GHG) and state minor NSR BACT for VOC, NOX, and SO2. A control technology review was conducted for all pollutants. The controls described in this section were determined to satisfy BACT requirements, based on a review of recently issued permits from Texas and other states, and consideration of RACT/BACT/LAER Clearinghouse (RBLC) data provided by the applicant. Flare CO emissions will be limited through the use of good engineering design and proper operation of the flares. Equistar will maintain the flame integrity through

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Preliminary Determination Summary Permit Numbers: 4682B, PSDTX761M4, and GHGPSDTX32M1 Page 4

the implementation of good combustion practices and flame detection monitoring with an automatic re-ignition system and designing and operating the flares in accordance with 40 CFR §60.18 and the anticipated MACT Subpart YY requirements. GHGs from the flare will be limited through proper operation in compliance with 40 §CFR 60.18, good combustion practices, and use of flare gas recovery systems.

VII. Air Quality Analysis The air quality analysis (AQA) is acceptable for all review types and pollutants. The results are summarized below. A. De Minimis Analysis

A De Minimis analysis was initially conducted to determine if a full impacts analysis would be required. The De Minimis analysis modeling results for 1-hr and 8-hr CO indicate that the project is below the respective de minimis concentrations and no further analysis is required.

Table 1. Modeling Results for PSD De Minimis Analysis in Micrograms Per Cubic Meter (µg/m3)

Pollutant Averaging Time

GLCmax (µg/m3)

De Minimis (µg/m3)

CO 1-hr 1.8 2000

CO 8-hr 1.5 500 The GLCmax represent the maximum predicted concentrations over five years of metrological data.

B. Air Quality Monitoring

The De Minimis analysis modeling results indicate that 8-hr CO is below its respective monitoring significance level.

Table 2. Modeling Results for PSD Monitoring Significance Levels Pollutant Averaging

Time GLCmax (µg/m3)

Significance (µg/m3)

CO 8-hr 1.5 575 The GLCmax represents the maximum predicted concentration over five years of meteorological data.

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C. National Ambient Air Quality Standards (NAAQS) Analysis

The De Minimis analysis modeling results indicate that 1-hr and 8-hr CO are less than the respective de minimis concentrations and no further analysis is required.

D. Increment Analysis PSD increments do not exist for CO.

E. Additional Impacts Analysis The applicant performed an Additional Impacts Analysis as part of the PSD AQA. The applicant conducted a growth analysis and determined that population will not significantly increase as a result of the proposed project. The applicant conducted a soils and vegetation analysis and determined that all evaluated criteria pollutant concentrations are below their respective secondary NAAQS. The applicant meets the Class II visibility analysis requirement by complying with the opacity requirements of 30 TAC Chapter 111. The Additional Impacts Analyses are reasonable and possible adverse impacts from this project are not expected. The ADMT evaluated predicted concentrations from the proposed project to determine if emissions could adversely affect a Class I area. The nearest Class I area, Big Bend National Park, is located approximately 570 kilometers (km) from the proposed site. The predicted concentrations of NO2 and SO2 for all averaging times, are all less than de minimis levels at a distance of 1 km from the proposed sources in the direction of the Big Bend National Park Class I area. The Big Bend National Park Class I area is an additional 569 km from the location where the predicted concentrations NO2 and SO2 for all averaging times are less than de minimis. Therefore, emissions from the proposed project are not expected to adversely affect the Big Bend National Park Class I area.

F. Minor Source NSR and Air Toxics Review

Table 3. Modeling Results for Minor NSR De Minimis Pollutant Averaging

Time GLCmax (µg/m3)

De Minimis (µg/m3)

NO2 1-hr 0.2 7.5

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Preliminary Determination Summary Permit Numbers: 4682B, PSDTX761M4, and GHGPSDTX32M1 Page 6

Pollutant Averaging Time

GLCmax (µg/m3)

De Minimis (µg/m3)

NO2 Annual 0.1 1 The GLCmax are the maximum predicted concentrations associated with one year of meteorological data. The primary NAAQS for annual SO2 has been revoked for Nueces County and is not reported above. The justification for selecting the EPA’s interim 1-hr NO2 De Minimis level was based on the assumptions underlying EPA’s development of the 1-hr NO2 De Minimis level. As explained in EPA guidance memoranda,1, the EPA believes it is reasonable as an interim approach to use a De Minimis level that represents 4% of the 1-hr NO2 NAAQS.

Table 4. Generic Modeling Results Source ID 1-hr GLCmax (µg/m3

per lb/hr) Annual GLCmax (µg/m3 per tpy)

10ROUT 0.12 0.003

11_ROUT 0.12 0.003

FUG20_1 6.85 0.02

FUG20_2 6.77 0.02

FUG20_3 6.66 0.02

FUG20_4 6.56 0.02

FUG20_5 6.48 0.02

FUG20_6 6.46 0.02

FUG20_7 6.41 0.02

FUG80_1 6.92 0.02

1 www.tceq.texas.gov/assets/public/permitting/air/memos/guidance_1hr_no2naaqs.pdf

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Preliminary Determination Summary Permit Numbers: 4682B, PSDTX761M4, and GHGPSDTX32M1 Page 7

Source ID 1-hr GLCmax (µg/m3

per lb/hr) Annual GLCmax (µg/m3 per tpy)

FUG80_2 6.75 0.02

FUG80_3 6.60 0.02

FU1_1 9.09 0.03

FU1_2 8.12 0.03

FU1_3 7.41 0.02

FU1_4 7.17 0.02

FU1_5 4.87 0.02

FU1_6 5.82 0.02

FU1_7 9.54 0.03

FU1_8 9.32 0.03

FU1_9 7.15 0.03

G. Greenhouse Gases EPA has stated that unlike the criteria pollutants for which EPA has historically issued PSD permits, there is no National Ambient Air Quality Standard (NAAQS) for GHGs, including no PSD increment. The global climate-change inducing effects of GHG emissions, according to the “Endangerment and Cause or Contribute Finding”, are far-reaching and multi-dimensional (75 FR 66497). Climate change modeling and evaluations of risks and impacts are typically conducted for changes in emissions that are orders of magnitude larger than the emissions from individual projects that might be analyzed in PSD permit reviews. Quantifying the exact impacts attributable to a specific GHG source obtaining a permit in specific places and points would not be possible [EPA’s PSD and Title V Permitting Guidance for GHGs at 48]. Thus, EPA has concluded in other GHG PSD permitting actions it would not be meaningful to evaluate impacts of GHG emissions on a local community in the context of a single permit. The TCEQ has determined that an air quality analysis would provide no meaningful data and has not required the applicant to perform one. As stated in the preamble to TCEQ’s adoption of the GHG PSD program, the

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Preliminary Determination Summary Permit Numbers: 4682B, PSDTX761M4, and GHGPSDTX32M1 Page 8

impacts review for individual air contaminants will continue to be addressed, as applicable, in the state's traditional minor and major NSR permits program per 30 TAC Chapter 116.

VIII. Conclusion As described above, the applicant has demonstrated that the project meets all applicable rules, regulations and requirements of the Texas and Federal Clean Air Acts. The Executive Director’s preliminary determination is that the permits should be issued.


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